DNO ASA

Okay, welcome to DNO's Fourth Quarter 2021 Earnings Call. My name is Jostein Løvås, and I am Communication Manager of DNO.

I will share some practical information. All participants in this meeting are muted by the organizer and will not be able to unmute themselves, chat or share their screens.

We will start with a brief results presentation by Executive Chairman, Bijan Mossavar-Rahmani; and 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 to.

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 to Kurdistan's largest fields and very important for us to DNO 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 and I took the opportunity to travel here to see our team and spend some time with our own operations people here in Kurdistan who've done a fantastic job during the pandemic, in keeping operations going and in a safe manner, healthy manner as much as possible. And they've been quite successful at that and also to keep operations going notwithstanding all of the problems that you're familiar with and kinds of supply chains and travel restrictions, and so on.

I'm also here to -- for some visits with the members of the Kurdistan Regional Governments, and also to visit our fields at our operations, and Peshkabir of course, we started up our gas gathering and gas transport to Tawke and injection project and which is now humming along. You might occasionally hear in the background noises from the gas plants.

And again, I'm pleased to be here and I'm pleased that Kurdistan is back in business and closer to normal. But 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 Haakon who will go into much greater detail on the financial results both for the fourth quarter 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 for -- and also the more detailed reports that were posted this morning on our websites, but I'll just highlight a number of points beginning with operations.

Please move the -- turn to the next slide. Instead of 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.

And that was finally signed in December. And we're off and running with our activities at 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 is 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. I consider also that we didn't do any significant drilling in Tawke, the Tawke field at 2021 for different reasons that we can go into our North Sea production was down, in part due to natural field decline, and part to delay the new production and planned maintenance.

But we were active in the North Sea in terms of exploration. We are one of the more active companies in the North Sea and in the Norwegian sector, and 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 unlikely to be commercial, and there'll be a focus or 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.

But we do have the preliminary numbers, which we wanted to share with you. We exited the year 2021 2P proven and probable reserves at 321 million barrels of oil equivalent and contingent resources 2C of 189 million barrels of oil equivalent.

We have fast tracking now the development of Baeshiqa and expect early production hopefully, in this quarter. We're going to do this fast.

But in no way and now that we've been given the green lights 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. But significantly, we -- revenues top $2 billion last year up 63% from a 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 billion dollar 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. It was down from $473 million in a year earlier, resumed the dividend payments, we of course issued $40 million of 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 entitlements and overrides at payment areas, but still have all the rear side outstanding $169 million just down from $259 million at the end of 2020.

So we're chipping away at that. These numbers exclude the interest.

And we remained in touch discussions with the KRG to accelerate the payments others debts and the terms or conditions under which the debts accelerated repayment will take place. Next one please.

This is the reserve side story remains pretty much as we last discussed it in terms of the composition and location of the reserves are two key reserves are largely in Kurdistan. We have $321 million barrels of oil equivalents across the of 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 posted that is in Norway and some also in Kurdistan. Importantly on Peshkabir, we're looking at a gas three injection project but also largely and in Norway.

We have some numbers back in [indiscernible] numbers our 2B reserves at current production rates should last the 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 that we produced over 30 million barrels of oil from our inventory.

30 million barrels is the size of 2P reserves a lot of -- a lot of companies small and maybe even some mid-cap so. So finding 30 million, 40 million barrels a year every year consistently is not easy.

But our hope and expectation is that over a period of three years or so we're able to make discoveries as reserves move from the contingent into the 2P side to keep the - our reserve replacement ratio constants and key to this a 2022 4P Baeshiqa which is the contribution here that we have Baeshiqa as nominal. But as we start production and get a better sense of the three other wells and the size and scale of the other discoveries, I expect fully well that we will have a reserve recovery situation, we have the same again understating the reserves being very conservative is how we started off with Peshkabir.

We started with low numbers and each year with as the field was further developed, and we learn more about it, we kept increasing our Peshkabir reserves. So this sort of approach is not unusual for us as a company.

But again, once we have our annual statement of reserves and resources completed and signed off on we will share that of course with the markets. Next please.

Kurdistan our Tawke license production. There was largely unchanged, which is a bit of a miracle because we didn't drill, do much drilling at Tawke for about 18 months because of the pandemic because we were sorting out budgets and getting budget approvals and, and preparing for the accelerator once again, which would - which we've now done and we're going to move quite fast to Tawke this year, I think we have something like 17 or so wells planned in Tawke.

And that will of course, help or recover Tawke production. And hopefully keep our exit rates or average rates for the year where they were in 2021.

We found maybe a bit higher or lower but we're very confident that the Tawke license will perform well 2022. We had even though we didn't have any significant drilling at Tawke for this 18 month period we did inject by the gas, Peshkabir as part of our gas injection and carbon capture program.

We've injected in 2021, 7.6 billion cubic feet that's equivalent of 460,000 tonnes of CO2 so we hit the two birds with one stone both in terms of CO2 but also three birds in one capture of gas for future use but also 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. But also we did some work overs, 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 have been again everything it is the DNO way and I'm very proud of our four teams for sustaining production under these difficult conditions.

I've already discussed the production from a license from Baeshiqa. We expect that over the course of a year and if we average out the production once production starts, should I expect to be the case in this quarter that we will have an average of 4,000 barrels of oil per day from Baeshiqa.

But that accounts for several months and started the year with no production, that means the production is going to be higher. And we're targeting over maybe it makes a great twice, that's but we don't know we'll have to, we'll have to see all of the Baeshiqa wells will perform but we're again, bullish about Baeshiqa, that will be good addition.

We hope to our production portfolio. And 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 as the - is Kurdistan itself.

And they like the companies and other governments are looking for more production at these oil and gas prices, these oil prices like this at Kurdistan. So everyone's incentivized to do more quickly in this very strong pricing environments.

And we're committed to be 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. the one at Baeshiqa, one at Zartik.

The quality is a bit different. The zones from which we produced but we had something on the order of 15,000 barrels.

This is not barrels a day, it's 15,000 barrels of 40 degree API oil from Baeshiqa, the Baeshiqa discovery well. And 22 degree API oil from Zartik discovery oil which we truck the market at time of discovery.

So we prove that oil will flow to surface. That gave us a lot of confidence that in terms of moving forward to the development plan, which again has been approved now.

Our plan is to reenter these two discovery wells, put them on production, and then continue with the drilling of additional wells. I think we have three new wells planned in 2022 at -- all the Baeshiqa license will be doing some seismic.

But we'll be drilling three wells and the end of the year, we hopefully will have five wells on production. So that could be significance all the way down to where we're cautious and we'll see how these wells performing and we'll obviously, report to the markets as we learn more.

But let's say in first instance we will be trucking this oil to market using test facilities and time we'll be putting in more permanent service facilities and eventually depending on the size of the volume production 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 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.

But we drilled development wells and importantly the two that we believe are have commercial potential in terms of size and in terms of proximity to existing infrastructure on the Røver Nord and the Røver Nord and the Bergknapp discovery that were made -- it was made in 2020. Importantly, DNO has been taking a larger percentage interests in new licenses.

So 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. So we are taking larger interests in exploration wells, and hope that will pay out.

We have seven wells planned in 2022. These are unproven basins with moderate risk profiles.

We continue to play abandoned in some wells and facilities in the fields that we inherited at the time we did the Faroe acquisition, that's, that's moving, moving along at a good pace. It's a bit of a nuisance.

They also call us but we're cleaning up the portfolio that we acquired and trying to sharpen our focus on growth, meaningful growth. Next please.

We're closing in on four PDO project possibilities as part of the 2022 PDO. Brasse, of course we talked about quite a bit over the last several years and see this cartoon of the Brasse field and what we plan to do with it, that we have 50% of Brasse we operate.

So we have some ability to manage that process. Our partner is a Var Energi.

And we have been in discussions with the host Equinor to bring the production into their infrastructure system and bring Brasse production more rapidly. We reached a subsea frame agreements with Technip during the sort of low point of the pandemic, where industry activity was lower, so we lined that up in terms of schedule and in terms of cost.

And we believe that'll give us a better advantage in terms of proceeding with the Brasse project. Elsewhere, there are other projects which we don't operate.

There's the Iris-Hades discovery, there's Gjøk 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 that you get a sense of what it is for Brasse, what our initial targets are, and thoughts are as to what Brasse will look like.

Next, please. The next slide shows our breaks down our North Sea 2022 exploration drilling.

And I refer to seven wells. You'll see it's going to be a busy year for us.

We have, for the most part, large interest in the wells already drilled or are being drilled in our core area. They are drilled to your infrastructure, so we're hitting, checking all the right boxes, given the again the size of the company and the circumstances and the markets.

And we know we're very optimistic that we will, again have discoveries and some of them that are meaningful in terms of the contributions of the companies, initially at resource figures and ultimately the ARPU and probable category reserves. So we're very excited about this.

And as I said, we're one of the most -- the more and most active explorers in Norway now, and 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, as 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.

It'll drill spud at least in 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 we -- a number of reasons why we were interested in the power portfolio. In parts of that, we are obviously very keen on.

Some parts of it we were keen on, this is one part that we were quite keen on. And we'll see how that goes.

But 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 also interesting exploration wells in 2022. I will say a few more words about some of the other activities in the North Sea.

This one last slide. On this, following the Rover Nord success, part of our planning has been the other wells in this area, which is near the giant Troll field.

And there are these two wells that are scheduled in 2022 that had been de risked somewhat by the Rover Nord discovery. And this is, again, it's a focus area for us, but we're focusing on it more sharply and quite excited about these wells, at least this year, and again, we have participating interest in these sort of Nord discoveries, they will be meaningful in terms of size and scale for DNO.

And so all in all, a lot of activity in the offshore Norway and within offshore U.K. as well.

A lot of activity Kurdistan with wells in Tawke. We have, I think, a three well program in Peshkabir.

So it is more wells in Peshkabir, and of course, the three new wells have the re-entry into the Baeshiqa wells in this year as well. It's a very active drilling year for us, very active drilling -- very attractive prospects, we believe, and quite excited about what 2022 can bring to the company.

So 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. And 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 coming here.

And 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 in our company history.

And 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.

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.

So in short, 2021 was the thereby a good year for us in DNO, but especially strong finish in Q4. And with the tighter market balances and the 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'll start with that before we go on to the full year. So for the fourth quarter, 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. And that 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 over lift in this quarter, with an effect of $62 million in Q4, but also higher gas prices that added the $50 million of revenue in the quarter by itself.

So this is all good. But as we move down on the left side on the Q4 numbers, you'll see on the cost side that the movement in over lift, and the lift also adds $58.8 million in cost, and to our cost of goods, sort of catching up on the actual production cost here, tying that to the revenue.

And as we go down on the other expenses or costs, we see that the exploration is up from Q3. That's on higher expenses well costs.

This is for the Gomez and [indiscernible] wells. And we also got more seismic inventory 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. But even so, our Q4 operating profits still doubled to $128.2 million, backed by the high revenues.

One other key item I was mentioning in Q4 is that there is a significant increase in tax expense to $14.1 million, mainly explained by taxable profits in DNO Norway or DNO America during Q4 as a result of the higher oil and gas prices compared to the tax loss we had in Q3 in this company. But all in, we have a solid quarterly net income of $64.8 million for the quarter.

As you look on the right side of the slide, you have a 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 0from 2020, driven 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 stable and low production costs. While DD&A costs were significantly reduced in 2021 by lower DD&A charges per barrel in the -- barrel produced in Tawke license.

Otherwise, for the full year exploration expense, they increased in 2021 on the higher expenses well costs and also higher increase seismic purchases, seismic costs. And of course, this reflects our high exploration activity in our North Sea businesses.

It's good to see that we have mature lower impairments. So for 2021, 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. The taking of North East surveys said that the share of the tax income in 2020 was due to the effects of deferred tax -- on deferred taxes from impairments.

So really, that's a big part of the tax income for 2020. But anyway, to repeat, it's good to confirm the remarkable recovery in our P&L results last year and in total, solid net income for 2021 of $203.9 million.

Go to the next slide. However is often the case with our earnings presentation, the real fun in my view starts on this slide, which again shows some pretty good cash flow numbers.

Cash flow from operations more than doubled last year to a solid level $625 million. And that was mainly on the high revenues.

In addition, we received the North Sea tax refunds of 175 million, so that the total cash inflow on a cash flow basis was $800 million. The cash outflows that we saw here were primarily for the investment activities, the $362 million, split between exploration and CapEx of $276 million, and North Sea decom at $86 million.

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 the $54 million on our RBL drawdowns in Q4, the dividend payments of $22 million also in Q4, and otherwise for the year, I mean, the transaction costs and the interest expense on our bonds and bank debt.

But the main point here is that the strong cash flow from operations again, the fact that these significant investments and finance outflows and with the support from tax refunds also, we increased our cash balances by $260 million to a high level of $737 at year-end. Next one.

So for the capital structure, with this increase in cash balances, but also including the bank debt reduction that they 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, the much improved earnings strengthened our equity ratio to 35% at the end of the year.

And the bond -- the refinancing in q3also, as we mentioned already, but it served to extend the debt maturities and to lower debt costs going forward. So 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 year. So the oil and gas industry is supporting the commodity pricing.

And our solid production, we thereby expect to build further on our free cash flow and on our financial strength. On this basis, we have the flexibility to both maintain our robust balance sheet, key priority for us, but at the same time also step up the investments for further growth as well as look at ways of optimizing our capital structure going forward.

Next slide. So consequently, for this year's investment program, we plan to ramp up our operational spend, as we call it, to some of these four categories of investments and cost 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, extensive development spending, including now the first face on Baeshiqa project and the stepped drilling of the Tawke license as well as work on the four PTOs 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 in some key wells offering quite exciting resource potential this year. Total exploration expenditures amounted to $150 million in this program.

While 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.

And then 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 [indiscernible] fields in the U.K., and also Var field in Norway.

It will be good to be done with this work with good students, and then 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. And with that we see a really good value increased potential, especially within exploration but also within development for this year.

And I'll hand it back to you Jostein. I think we're opening up for Q&A at this point.

Thank you. And we've already got a question, a person who asked me one question here.

And that's Nikolas Stefanou from Renaissance Capital in London. So 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 you can go back to Baeshiqa and what's going to happen this year, I was a bit confused when the guidance show, is it -- are you going to produce from 2 wells but then to deal another three and don't complete them. Or are we going to see a five wells producing at the end of the year, because I think you mentioned something like an 8000 baht per day exit rate, which, I mean, sounds very low, can you -- I mean, clarify those comments, please.

And the second question is, I guess it's been a bit more like, [indiscernible] the next two to three years in the North Sea, can you give me a sense of what kind of like topics we should be looking at in the North Sea and assuming that those developments you mentioned do get sanctioned and well that might take production. And, then the final one is, I guess for Haakon, okay, I mean, it's been quite a few impairments over the past two years, which is understandable but I would have expected some reversals given the shopper like rebounding the oil price and usually this is the quarter most companies do the same.

Why have we not seen this? I mean, is -- you can kind of comment on that as well, please.

Thank you.

I believe Bijan has to unmute himself.

Okay now?

Yes.

Somebody muted me. They don't often get to mute me at the end but somebody did just fine, anyway.

Nikolas, thank you for your questions. Let me address the Baeshiqa on first because I'm the -- basically the closest to it, right.

This is next door here. Well, not exactly next door, but I'm in the vicinity.

And then, I will turn to my other colleagues to comment on the -- all the other questions in terms of North Sea and impairments and so. On the Baeshiqa numbers are quite conservative.

And those in terms of what we discussed internally, but certainly what we report to the market we've typically been quite conservative in our figures, so we under promise and over produce rather than the other way round. But so what's -- yes, we will start production from the two discoveries, those were left and as a temporary status that will allow us to re-enter and start producing pretty quickly.

We're going to do that, we're going to be -- we're committed to drilling out of three wells you'll see that on the chart that's on the screen now. The third well, that will be spotted in 2022, but may push into 2023, the report 2023 depending on again how much testing we do and then, what sort of else goes on with the other wells because you're entering two wells and drilling to another two wells, great say scheduling issue we may go faster, may go slower, but certainly intent is to spot what Baeshiqa could be, maybe put on production, I don't know.

But we are getting being conservative out of it. We're not -- these aren't shale wells where you complete them and walk away from a farm but not complete, we're going to plan is to drill them and complete them, complete them practice necessary rhapsodize perhaps, is more appropriate in this context, and put them on production and we want to 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.

But whether it's four wells on production, or three wells on production, or four or five, we'll just see how it goes with some of that uncertainty also leads to some confusion as to what's our production rates are given an average for the year rates, I refer to a an exit rates of around 10,000 or so that's a sort of internal target that I'm sharing with you but there is uncertainty. What is certain is that, we have discoveries that these choose important discovery wells drilled on this, which we're going to put on production, that's for sure.

We're committed to a fast development, that's for sure. We're not going to wait to drill many wells and then start production.

And once service facilities are, are installed, which may take years that's how large companies typically work, encourage us on our successes and based on the fact that we come in and we drill, we put them on put a discovery production and use the revenue to drill second well, the third well, I keep going into 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. So there'll be no holding back.

No worries to hold back and that will charge ahead as fast as we can. And again, it will report to the market as we proceed, but this is a new field for us.

And we'll have to see -- wait and see how it performs before we give more definitive numbers higher or lower a difference. So, you bear with us.

You will find out soon enough sort of the most companies do. But you can also be assured that we are very excited about this by the Baeshiqa license.

The previous operator and owner backbone was very excited about this license and the possibilities. And this is part of our - hopefully Baeshiqa become a very important part of our business in Kurdistan, the Tawke field is a mature field and it's going to go into -- and that started to go into decline as mature fields due to trying to stabilize that decline through gas injection and through in some of the plumbing that we do and work with pumps and other sort of tricks of the trade.

And we hope to end with a 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, again at the deeper Horizon, Jurassic and Zartik.

Maybe there's something there that would generate some excitement and some additional production. But Baeshiqa, we view as the future of an important part of the future at Kurdistan.

We're committed to make that happen and to spend what it takes and build the necessary people to it, which we've done. And we're very, very excited about it.

Okay, thank you.

Other question, Chris, would you like to do it, if you're signing, I'll unmute you.

Yes, thank you. Yes, so the other question was on the development portfolio in the North Sea, if I remember correctly and as Bijan explained during the presentation, we have a very exciting year in Norway with working very hard to get plans for the revenue operation delivered on for full potential developments.

That's really our key focus at the moment, we're working very hard to make sure those are successfully delivered. And I think, we'll return on guidance with respect to any CapEx and forward 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 Brasse. So that's maybe of some help.

I think we're 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.

And we had third question, Nikolas on the impairments. And, why don't we see any reversals sometime soon?

And yes, that's a good question. We do have at least one very strong candidate on reversal, that we conservatively 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 the names of the fields and all that. But once we are sorting through all the decision gates, the DG-3, et cetera and things are firmed up, I think we'll be in good position to come back with also with announcing at least one reversal, maybe more later in the year.

Around the impairments, of course, we have done quite a few. Somewhat it been tied to the rescue and catch cost situation where we had impairments.

But as we talked about, we're mostly done well with most of the work on larger projects. So when they get the stuff, that risk goes away quite significantly at the end of this year when we're done with those projects.

But will come back to you on all the possible reversals, which is a good discussion.

The next question here comes from Teodor Sveen-Nilsen from SpareBank 1 Markets.

Thanks for taking my questions. Three quick questions from me, first on the lifting cost on NCS in Q4, you reported for Q4 is something that we should expect going forward.

Second question is from Baeshiqa, and I just wonder, are there any big differences in the PSA terms compared to the TOC PSA? And last question is just on the OpEx guidance for 2022, is it possible to shed some light on what that corresponds or not per barrel basis?

That's all thanks.

Can you say that first question again, I didn't catch the full question number for the first point, Teodor.

Yes, sure. Our first question is related to NCS lifting cost, should we interpret the Q4 lifting cost as a normalized lifting cost going forward?

And then including that cost of the over lift.

With the question of what it was the perceived 14.4 points about. I don't know where's the -- do we have a view on that?

I would say it's almost the annual average what's up 17.9 going down a bit in Q4, we think that 8 months we see some of, maybe not so much this year. But day one, when we have new fields coming on stream, you will see that coming down.

But I don't know, I think would be fairly well, to pretty good assumption to assume it's around what we can see and expect for this year, would you add in Q4, and we'll count on that anybody else twist?

Well, it's always a tricky one for a top engineer like me, because it's this variability with the liftings as well, that makes it technically a bit difficult to track. But obviously, the sort of proportion of revenues that are associated with the lifting North East a constant, it's just the variability in liftings, I think that make it difficult to track.

Well, I'll answer the question about that the Tawke PSC. Yes, there are differences, I think, by and largely, the Kurdish PSCs cluster around the same numbers are similar, both with time they've been some changes.

The Tawke PSC is one of the first to be signed, the Exxon was one of the last to be signed. And with time, the PSCs have been tightened, and so on.

But they all cluster roughly around the same place in terms of the economics of these, what makes them different historically, the different PSC has been the level of the signature bonuses that have been paid all these PSCs, Exxon paid a significant signature bonus for the six blocks that it took in Kurdistan. And an important part of that was the Baeshiqa block.

So their economics factor that in, ours wasn't because that was paid by Exxon, so in that sense, the PSA/PSE, is more attracted to us than it was to the previous operator and the license holder. But the PSC is even more attractive to us.

Because we -- the cost pool Exxons prior costs that were expended are counted as part of our cost pool. That will make the economics okay, it's, again, more attractive that we didn't have to pay the sewage bonus.

And we had the opportunity to recover the cost. So our house looked different.

And it should be attractive, although if you look at, again, line items, probably the Tawke PSC on some of the metrics is somewhat more attractive than the Exxons. But again, by and large, the delay of the big purchase, not PSCs cluster around the same sort of numbers, or cost on and off of those and so on.

So if we have a good discovery will do, it'll be very economic develop.

So I believe there are two more people that wanted to ask questions before you start.

I think the third question the authority new OpEx barrel going forward

Yes, perhaps corrected looks like it on per barrel basis will increase in the area.

You know, we've 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 optics per barrel.

So that is about the lowest you'll see anywhere. It would be a maintain that for me to the current producers talk, you feel the pitch of your field.

So 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 Michigan license, there will be some increased on that average basis for your design with a new production coming in from Baeshiqa.

But not that much, and we expect that once we see that production coming out from our new development that they will be -- unfortunately the very low levels that we have already from our two current producers. And we talked about the North Sea OpEx already.

So I think we covered that question. That's okay.

People want to ask questions before we close the meeting, and the first one is called, like Karl Fredrik Schjøtt-Pedersen, from ABG Sundal Collier, please.

Hi guys. Thank you for taking my questions.

One question regarding the split of CapEx between the barrier between Baeshiqa talk, I guess, could you elaborate on how our CapEx spending is allocated between the two peaks? And second, in terms of exploration cost, is that entire amount related to activities in the North Sea?

Yes, let me -- this my first question, I went somewhere else, we guided you on the CapEx for the years. So, it's around the Kurdistan CapEx it's under $200 million.

Most of that will be for drilling on drilling on Tawke and Tawke facilities I mean, Tawke license, those are including Baeshiqa. So, out of the 200 or so, you know, large majority is for the development of our existing producers.

But really in vivid detail on the Baeshiqa but stays around 20% though, that is a rough guidance on the 200 to four Baeshiqa camp extending this year, just to give you an idea, you know, plus or minus that's a good way.

Look at these numbers, it's an again, it's amazing that for so little money, we're doing so much activity in Kurdistan or in 17 wells somewhere else with cost a lot more than resort perfective that's in Kurdistan Tawke field itself, the drill wells for well under $10 million a well now. Peshkabir, the deeper a bit more expensive, although every golfer a handle on that and with the experience that the early wells and new wells that will drill at Baeshiqa will be more costly, but with time, and we'll find it and we'll find the right way to do that, as well.

And we're like, the TLs 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. So you look at those numbers, the level of activity we're doing for those numbers is quite, quite impressive, by any standard.

And that that thing into the earlier question about the quality of the PSCs I mean the current PSCs aren't the most attractive PSCs, I've seen in the world and they're tough. They're tough than the -- what's made Kurdistan special is the fact that it hadn't properly been exploring.

And their opportunities to go in and do exploration of prospective areas and make discoveries which DNO did and our success has been not because the PSCs are credibly attractive, and they're not. It's because what we were able to find any oil and putting it up production quickly and at low cost that made it work for us, notwithstanding the fact that the PSCs aren't most attractive in the world.

And all of a sudden, the fact that the Kurdistan as you all know, is landlocked, that we pay quite a discount to get the oil to markets. So with 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. And with that I will go back to my tour of the Peschiera gas plants and eventually lunch with our operational people.

There's a beautiful cool day here. And it's just great to be to be back.

And that's great to see Curtis on the back again open for investments and 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 by the by the government and by those communities and other stakeholders with whom we work here in Kurdistan. So it's a very welcoming place to be no and you know is doing its part for Kurdistan as well.

So 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 two months or so years and the COVID will calm down in Norway and the world will be a lot more normal a place and it's been for the last two years and that he was for your support during this period and you're interested in our activities.

Okay, thank you.