Yes, I think we are ready to start. People are still coming in, but I'd like to welcome you all to DNO's third quarter presentation earnings call. My name is Jostein Løvås, and I am the Communication Manager of DNO, and I will first 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 presentation of the third quarter results by CFO Haakon Sandborg present. After which, we will have a North Sea exploration update by Elisabeth Femsteinevik, who is the North Sea Exploration Manager. After these sessions, we will have a Q&A as normal. Executive Chairman Bijan Mossavar-Rahmani is also available to take questions.
With that, I'll leave the stage to CFO Haakon Sandborg.
Good. Thank you, Jostein. Hello, everyone, and welcome now to our third quarter earnings presentation. We have kept it fairly short again this time, and we will be focusing on the main highlights and also on the key financials for the quarter. I go to the first slide. Let's start with the Q3 highlights. We are pleased now to deliver another quarter with a strong cash flow and the further strengthening of our balance sheet and also our net cash position. As you will see, the P&L results are also good, showing a clean quarter, free of any extraordinary items, and also very close to the consensus estimates. Believe me, this is pretty good for the third quarter.
As we have seen in the prior quarters, the high oil and gas prices are driving these strong financial results in combination with our solid operations. As such, we increased the net production by close to 4,000 BOE per day in Q3 to 95,700 BOE per day. From that, 81,700 barrels per day came from Kurdistan, and 14,000 BOE per day came from the North Sea. We saw that the Kurdistan production increased in the quarter, mainly on new wells that were brought on stream on the Tawke field, while the North Sea volumes were up following the completion of maintenance at the Ula field in Q2.
As we comment on the slide, we maintain our strong gross production performance in the Tawke license in Kurdistan, and we also now have the first early production from the Baeshiqa license in Q3. Further, we closed on an important transaction agreement with RAK Petroleum in October to acquire its assets in Côte d'Ivoire in West Africa. From a strategic point of view, we see this transaction as the first step into a prospective region where we see new growth opportunities. The agreement has also opened up the shareholder base in our company, in DNO, which we hope and think will enhance interest from equity investors.
As announced in August, we're also pleased to participate in the Ofelia discovery offshore Norway, where the partnership now will be working on a fast-track tieback development to the Ula platform. Including the Ofelia discovery, we have now participated in four likely commercial North Sea discoveries last year and this year. I think that is adding significantly to our long-term value creation. As a key contributor to this success, Elisabeth will tell you more about this in a few minutes. Great. We move on and talk a bit about our financials. Next slide, please. Here it is.
For P&L, it's good to see that the Q3 revenues over $339 million marks the fourth consecutive quarter with the revenues above $300 million. Revenues in this quarter, in the third quarter, were split between Kurdistan at $198 million and the North Sea at $141 million. As you can maybe see from the graph here, Q3 compared to Q2, the revenues were down by $22 million in Q3 as Kurdistan revenues decreased by $42 million on the lower oil prices, also inclusion of only one month for the final monthly override payment from the KRG. But on the other hand, the North Sea revenues were up by $20 million in the quarter, and that was mainly on higher realized gas prices.
These increased from $97 per BOE in Q2 to $192 per BOE in Q3. Just to comment a bit on the cost side, our cost of goods sold increased by $13 million from Q2, primarily due to higher lifting costs from the first production at the Baeshiqa license, but also increased depreciation from the higher North Sea production. The main point is that with no impairment this time and with the lower expense exploration, the Q3 operating profit still doubled from the second quarter, as you can see on the graph. Much for the same reasons, the Q3 net profit increased by 79% despite much higher tax expense from taxable profits in Norway in the quarter.
We are pleased with the good P&L results for the third quarter. On a year-to-date basis, our revenues were up by 71% from last year. This growth comes mainly from higher oil and gas prices, and in turn, that increased both the year-to-date operating profit and the net profit by 2.5x . That's compared to the same period last year. Absolutely, also a strong progress on the year-to-date P&L results. Good. Let's move to the next one on the cash flow. We again have strong cash flow from operations in Q3 at a level of $276 million.
This is down from the second quarter, but that was mainly due to much higher capital working capital contribution in the second quarter cash flow. For taxes, just to mention that's some of the questions we get on that. We paid the first NCS Norwegian tax installment for 2022 tax year of close to $2 million in Q3. We'll pay another two installments in Q4 of close to $4 million. The next three final NCS tax payments for 2022 are due in the first half of next year. We currently expect that these installments will amount to around $105 million due to taxable profits in 2022.
To also mention the U.K. side, we received a tax refund of $18 million in October for decommissioning spend during 2021 in the U.K. We show here on the graph investments of $113 million for the quarter. These were primarily for drilling and development CapEx at $80 million. We also had $10 million in capitalized exploration. Further $23 million spent on U.K. decommissioning. Under the finance outflows, we bought back and canceled another $45 million in the DNO03 bond, and we paid down $60 million on our RBL bank debt. Further, we also paid a dividend of $25 million in August.
Thereby, we remain in a strong and comfortable position with cash flow funding significant investments, debt repayment, and dividends, and also adding to our cash balances in this quarter with $17 million. As we note here, that we have added $151 million in Q3. Our year-to-date free cash flow is now at a significantly strengthened level up to $469 million year- to- date. Okay. We're moving on to the balance sheet. As you can see, backed by strong cash flow and debt repayments, our balance sheet strengthened again further in Q3, and the net cash position grew to a level of $252 million.
Also important for us, with the support from retained earnings and debt reduction, our equity ratio has strengthened substantially over the last several quarters to a solid level of 46% at the end of Q3. With the debt repayments in Q3 that I mentioned, the DNO03 outstanding balance is currently at $131 million, while the RBL, the bank drawdown, has been reduced to a fairly modest level at $35 million. I think this is all looking really good. With this capital structure, we now have financial robustness and also flexibility to both continue to grow our business, but also to further work on our capital allocation going forward. All right, next one.
Looking ahead, we expect that gross production from Kurdistan will come in between 107,000- 109,000 barrels of oil per day this year. That's above the initial guidance for the year at 105,000 barrels of oil per day. While the North Sea net production we think will average around 13,000 BOE per day as guided for the year. Now, we are in the early stages of development at Baeshiqa, and we see that the ramp up of production from this new license is going a bit slower maybe than expected. As we get to understand the reservoirs and the resources better, we certainly aim to build this up through next year.
Otherwise, we have completed and executed operations this year largely as planned, but we still revise the projected operational spend down to $725 million from the guided level of $800 million. Much of this revision is due to currency and FX effects, as we have a large part of our North Sea costs in kroner and GBP, or pounds, and these currencies have weakened against the dollar, so that this is because we have our functional currency at the DNO ASA level is dollars, so that's where we get the FX effect. Our teams are working hard to finalize the three PDO candidates that we have in this year in Norway. We see that the recent proposed fiscal changes are not very helpful in this respect.
We are reviewing the product economics and to see what we can do to offset the effects of these tax changes. For our dividend program, we are pleased to announce today another dividend payment to be made in November of NOK 0.25 per share. That is around $25 million-$26 million, same level as we had in August, also now to be paid out in this month. Okay, thanks. I will finish my part now, and I'm pleased to hand over to you, Elisabeth, for your presentation.
Thank you so much, Haakon. It looks like Q3 was a success for DNO, as for many oil companies. I'm gonna talk about an area that will continue to grow value to give value creation into the future. Can you go to the next slide? Yeah. We have the last years built a substantial portfolio in this Troll-Gjøa area you see on the map. Over the next years, we are planning to drill six wells, exploration wells in this area. Those will target about 100 million barrels net unrisked volumes to DNO. It's the first one which is coming this year, and that's the Røver S ør , the well that we are spudding later this month. As you can see from the table, it's a good spread of volumes.
It has a good chance of success with low to medium risk, and that we have a material license interest in the prospects. As with all good work, it starts with the data and with the people that we have. I have a great team that digs into the data to gain the knowledge that we have that can result in prospects that we can mature, both within the license areas but also in new areas, so that we can apply for them in the APA licensing rounds. If you look at the prospects that we have, I start in the south, and we have the Røver Nord license. As you can see, it's three wells coming in that license.
All of these prospects were identified when we applied for the license, but we have been able to mature them further during the license time. Also, of course, the Røver Nord discovery has de-risked all those prospects. The Carmen to the north is also in the same play as the Røver Nord but at a deeper level. It has somewhat higher pressure and temperature than the Røver. Further to the north, we have the Kveikje discovery that I will present a bit more about later in the slides. The knowledge that we gained from the Kveikje made it possible for us to take the Heisenberg well commitment.
What we are looking at here is that it's shallow targets where the amplitudes are really important to guide what we want to drill. We see that the knowledge from Kveikje made it possible for us to have a good understanding of the Heisenberg. We have the Cuvette to the north, which sits between two discoveries that we already are part of, Orion and Syrah. This prospect is not the biggest one, but it's really important for the Vega area because it is possible to drill it from the template. This is a very low cost development, should it be a discovery in the Cuvette. As you can see from this.
As you can see, we have a lot of work ongoing, and it's new data coming all the time with wells, and we also have new developments in the seismic data, and we put together data in new ways. All of this, it's really important to combine so that we take advantage of all knowledge that we have to make the best decisions going forward. Then you can take the next one. This is showing the distance to the infrastructure, Gjøa in the north and Troll in the south. As you can see, the licenses that we have, they sit within a tieback distance to the infrastructure. It is important for us to work this area. It has been important for us to work this area.
How do we, how have we gone about it? It's a mix between departments and licensing rounds, and it's an opportunity that we have to take advantage of the seismic database that we have and to grow the portfolio. I think the last prospect that we farmed into was the Carmen, which was part of a strategy that we're having. The developments that we are looking into for the discoveries that we have are different in the two areas. We have the Ofelia in the north, which is looking to tie back to the Gjøa together with the Hamlet discovery that's also been made just south of it. In the Troll area, we're looking at different scenarios.
It can be single tiebacks to the infrastructure, or it can be a combined development with other discoveries in the area. In this area, in the last three years, more than 300 million barrels have been discovered. It is important to get the best development scenarios and the best tieback solutions for discoveries that are there. The volumes have been identified as very important by Equinor. They are the operator of the Troll, and they have identified this as a focus area for them to get as much as they can and to get the best developments that they can and the best or maximize the value of the discoveries that we have.
We have during the last two years made four discoveries, three in this area, and then we have the Bergnapp, which I will not touch upon today since the focus is Troll-Gjøa. I will show you a bit on the three discoveries that we have made, and we will start in the north with Ofelia and then Kveikje and then Røver. Ofelia is situated just north of the Hamlet discovery that Neptune made early this year. As you can see from the figure, the sands in the gap is present across the area. Pre-drill, we believe that the hydrocarbons in Ofelia would be the similar to the Hamlet with both gas and oil. The gas is red and oil is green on the figure.
When we drilled, we found a very good sand with just oil. That gives us some uncertainty on the amount of gas uptake and also we have to evaluate that further. We are looking into an appraisal well on Ofelia to see if we will find the gas cap. There's also more upside potential in the north of the structure and also in a shallower level on Kyrre, which is being evaluated. We see an amplitude in the Kyrre that we did not drill through in the Ofelia well because it was seen as a shallow hazard.
If the well is optimized for that, it's possible to also look into that anomaly and see if the gas has moved from Ofelia and up to Kyrre level, or if we have some gas in the Ofelia structure. Neptune is working this area very hard. They are the operator of Jora, and they have plans to submit a PDO on the Hamlet discovery. They also have another exploration well in the Doba license next year, and also they are then working on the Ofelia. Hopefully this will be tied back to Hamlet and will be a quick tieback for us in this area.
We have a lot of licenses around this, which is both operated and non-operated, where we are also working to see if it's possible to find other good prospects to drill. Next slide. This is Kveikje. We did this discovery early in the year. It's a tieback distance to the Troll platform, and it has gas in the injectites. As you can see from the figure, it's the lowermost, which is the Kveikje, and oil in Hordaland sandstones. The volume only quotes the oil because the uncertainties in the injectites in this area is so that we haven't calculated any volumes in. It's an upside in that.
The well results, what was really important for us with those is that it gave us confirmation about our interpretation of the seismic signatures and the reservoir presence and quality. Based on that, we were able to identify new prospects in the area and also take the drill decision on the Heisenberg injectite prospect, where we anticipate to both find oil and gas. I believe that the great work our geologists and geophysicists are doing is proving hard work and an open dialogue between colleagues is really important. We need to challenge each other to learn more, and this is a typical example where we have taken knowledge from other areas into this area where this was not the play that was proven.
For us, this is opening up a new area in the Troll-Gjøa area where we actually can further discover or find prospects that are in this injectite play. I think we need to ask each other questions, and we also need to not know the answers to all of it, because it is that will make us wiser. We need to look for new ways of finding the puzzle pieces in the puzzle. Yeah. I think all that will help us develop as people, but also as a company and an exploration department. It's really a focus in for us to not have accepted truths. You can go to the next slide. The last one is Røver Nord that we discovered last year and which was the starting point in this area.
It's also really close to Troll and it's a horst block, a very typical play in this area. It proved to be better than what we predicted, which was—it's always a great feeling, and it's positive for us. It gave us the opportunity to further work the license with a lot of prospects, some of them with quite good potential. It's just next to Troll, where the capacity to tie back new discoveries is there. Mapping of the structures in this area has given us three new wells to drill in 2023, in addition to Røver Sør, which is coming in now. I think the Røver Sør is on the spill route from Røver Nord up towards Troll.
It's gonna be really interesting to see what we will find in the well. As always, we're crossing fingers for our exploration wells. I have shown you a flavor of the work that we are doing in this area. It's a lot of work, and it's really exciting. It's a very good area to be in, I think, and I'm looking forward to the last well this year with Røver Sør and also the coming wells in 2023. That was it for me. Then you'll start.
Yes. Thank you. It's really interesting to see all the good stuff we've got going in this area. With that, I think we can open up for questions. If you want to pose a question, please raise the tiny yellow virtual hand on top of your screen. When you are 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. Please, I think we have a question here from Teodor Sveen-Nilsen at SpareBank 1 Markets. Please, Teodor.
Thank you, Jostein, and good morning to all of you. Thank you for the update. I have three questions. First, on realized prices. Some of your peers have reported that the basis for the prices or the revenues you get in Kurdistan will be changed because of competition from Russian oil. I just wonder how that will impact DNO and the realized prices from Kurdistan going forward. Second question is on dividend and buybacks. Positive to see that you announced dividend today. Just wonder how we should think about the dividend and shareholder payback in going into 2023, and what's the preferences between buybacks and cash dividends. Third question is on exploration on NCS.
Exciting to get some more details in the for exploration portfolio. Just wonder the chance of success that you showed on the slides, is they are pretty high. Is that a geological probability or is that a commercial probability? Thanks.
Good morning, Teodor. Let me start with the first question, then I'll turn to my colleagues for the second and third ones. On the question of pricing, you're correct. The pricing for Kurdish Blend crude has the gap between that and Brent has widened in the last several months and most noticeably in September, probably as a result of some of the political developments and legal challenges in Kurdistan. You're certainly aware of the court hearing and challenges opposed by Baghdad with respect to the Kurdish production-sharing contracts. This has been an ongoing matter. It changes character and wording.
As long as I've been an investor and Chairman of DNO, we've had this issue in various forms. That of course has been compounded by the ongoing, not really ongoing arbitration, but awaiting the outcome of the arbitration between Baghdad and Ankara with respect to use of the pipeline. Those uncertainties have put pressure on pricing of Kurdish Blend. Of course, there's been some perception of risk on the parts of some refiners and buyers and the traders have, I think, pushed hard, traders on the business of pushing buyers and sellers and increasing their own margins. They've smelled blood, and they put pressure on the price and parts.
We've seen the widening of that gap. How long that'll last, I don't know. You mentioned it's competition from Russian oil. It really isn't. We've always had competition from Urals crude in that market. I think to the extent sanctions against Russian oil exports are strengthened in December as is expected, that in fact that'll be positive for Kurdistan crude because that source of supply will dry up or become more or less available. I think we'll see a reversal in the widening of the price gap.
All of this, of course, has led to a rethink on the part of the Kurdistan Regional Government about the existing price formulas. There have been discussions. As I understand, we read these in the press the way you do, that at least, I think one, two of the companies of the various operators in Kurdistan have agreed to new lifting agreements involving new pricing. It's not the. But what exact formula are being used, we're not privy to that information. There's not a lot of details being given. We are not, at this time, engaged in active discussions with the Kurdistan government and the Ministry of Natural Resources about lifting agreements, for example, for Tawke production.
We have nothing to report on that other than we follow market developments, and it's been a difficult period. There's been a price widening of the discounts for Kurdish Blend for the reasons I've explained, these political risks or perceived political and legal risks. How those will unfold themselves with the new government in Baghdad, what posture they will have with respect to the arbitration, and what posture they will have with respect to the Kurdistan oil and gas sector, we don't know. For us, it's you know, business as usual. We continue until the developments cause us to make some mid-course correction.
On the issue of dividends and buybacks and cash, let me ask Haakon to respond to those.
Good. Morning again, Teodor. As you know, you may know that we have an authorization from the shareholders in DNO from the AGM in May of this year to pay out up to NOK 1 per share in dividends through the 12-month period from May this year to May next year. As you have seen so far, we have used half of that authorization by the payment of dividend in August, and another quarter kroner per share now to be made this month. We have basically used half of the authorization given to the board so far. You asked the question what happens into next year on the dividends and share buybacks.
The board will then decide on the use of the remaining half of the authorization from that AGM in May. We sort of have an approach here where we have also looked forward and made recommendations each year to the AGM on the coming year for the dividend payments. I certainly expect that will be the case also for next year, that there will be a discussion at the board level and a recommendation to the shareholders at the upcoming AGM. What do we do for dividends from the 12-month period from May 2023 going forward? I won't preempt that by saying, you know, anything, but we'll see.
At least, this year's program is significantly up from the previous year, and then we will see what the shareholders and the board decide for the AGM next year. There is, as I said, the remaining half of the NOK 1 authorization that the board will decide on going into next year. On the share buyback question, yeah, well, there's been you know, periods where we have been very active on the share buybacks in the past in DNO. I think, when I think back here, we had bought back up to 10% of our shares, and that was done you know, through a pretty long period. We canceled then the 10% that we had as treasury shares. When was that?
That must have been last year in Q3, I believe. We have done this in the past. Whether we gonna then embark on that again, that's also of course up for the board to decide. The board has an authorization from that AGM this year to buy back shares. That could maybe come on the table or. At least, it's been some time since we did that last in our company. We have a history of being active in that respect also on the share buybacks.
I can't be very specific here, but these would be the parameters we would work within, the authorization granted to the board from this year's AGM, and then the new request that we will make to the AGM for next year on both the future dividends and also on the buyback program. I think I'll rest that discussion there. Elisabeth, this is for you to answer please on the chance of success question from Teodor.
Yeah. Hello. The chance of success in the table is the geological chance of success. But as I've told you, this area has its close infrastructure. All of the wells that we are drilling and within tieback distance, so the commercial chance of success will also be high for all of the prospects that we have.
Okay. Thank you. That's clear. Just a follow-up to Bijan. Thank you for your comments around the pricing mechanism. Just to be sure that I understood you correctly, you believe that the discount we have seen recently is mostly explained by local factors and not competition from Russia. Was that what you said?
Importantly, yes. There's been some competition from Russia in the sense that Russian oil is being sold at discounts, as you know, everywhere. I don't know what the discount has been for Urals. I would guess in the $20 a barrel range. That's the number I've heard, but I don't know. Who picks up that discount, I don't know. Whether it goes to the traders, whether the traders pass it on to the refiners, I don't know. Ultimately, has more of an impact on us if it goes to the refiners. If it goes to the traders, then it becomes a sort of different kind of issue. I think, the.
For us, the important thing has been the perception of political increased political risk, and that's been, I think, made amply clear by the traders that there's more political risk and therefore they're taking on more risk, therefore they need to have deeper discounts to cover that. And that's been the driver more than than there's a lot of very cheap Russian oil available. But even if there is cheaper Russian oil available, then, you know, others are buying it too. Although, you know, Saudi Arabia's been buying cheaper Russian oil, but has that really impacted their market? No. But I think that'll be importantly impacted by how the Mediterranean basin and refining countries respond to the Russian sanctions decisions.
Okay. I think.
Thank you.
Next question.
One more thing. I just want to respond a bit to the second question. Haakon was very measured and careful and correct in his response, as he always is.
He usually am, you know.
As he always is. I'm a bit more free to give a bit more colored editorial comment. Two things. First of all, on the dividends. As you know, we had started the dividend program before COVID hit, and that of course put a stop to our dividend program and to that of other oil and gas companies. We're now in some respects flush with cash and expect that our cash position will continue to strengthen, and that gives a lot more leeway to the company to continue with the dividend program, and there'll be pressure from shareholders to have some of that money returned to them.
Other peer companies, Equinor and Kurdistan, of course, are doing so as well, some of them quite aggressively. You might expect that there would be some push from our shareholders to continue to a robust dividend program. With respect to share buybacks, we've already now have been treasuring, what, about 2.5%?
Yep. Mm-hmm.
Of own shares that came back to DNO from its investments in RAK Petroleum. RAK Petroleum was wound down, so we're 2.5% towards the 10% authorization level. In a sense, we've already picked up a little bit of that through that transfer. Companies, other oil companies are combining buybacks and dividends. BP just announced one yesterday. It was reported today that you might expect that the same rationale that drives other companies to do share buybacks and dividends are also carefully considered by DNO in this.
Haakon said we've done this before, so if we decide to do it again, it won't be a surprise, shouldn't be a surprise, and it's within the authorization level that was given by our shareholders in May, last May.
Okay. I guess Tom Erik Kristiansen from Pareto Securities will probably pose the last questions here unless there are any others. Please go ahead, Tom Erik, and remember to unmute yourself.
Yeah. With $800 million+ of cash on the balance sheet now, can you comment a bit on what you're looking for on the M&A side? You've been quite active historically, in terms of, you know, what type of asset and the size of a transaction that you may do there as well, as you obviously have quite high flexibility to go out and acquire. Have prices moved a lot, or do you think that there are still good deals to be done in the current oil price environment as well? Thank you.
The question is what are you gonna do with the cash. Depends whether you ask Elisabeth, Haakon, or me.
That's true. That's asking you then, Bijan.
With respect to M&A, in a sense, the acquisition in West Africa, in the Ivory Coast was one such move this year. We're always looking. As you well know, the prices for assets in the North Sea continue to be on the high side. It continues to be a seller's market, at least with respect to the expectation of the sellers. Not a lot of deals are being done because maybe the pricing has been too high. The North Sea remains a seller's market. There are opportunities elsewhere that we look at as well. We've always said we're looking for a third leg.
My hope has been, the expectation has been that, Africa, West Africa will become a third leg for us. This entry into the Ivory Coast is just the beginning. There are other opportunities. A large team of our management was in West Africa last week. I joined them, and so we are pursuing opportunities in West Africa, and I think there are some that are available, and we will look hard at them. We're also good at going in and exploring. Elisabeth talked about what some of the things we're doing in Norway, offshore Norway. There are other opportunities for exploration as well.
Obviously the highest impact in terms of value creation is through exploration. We'll pursue that. We can fast-track things elsewhere much more than we can do in Norway, where everything takes its good time. We can move faster overseas, and the speed of acquisition of exploration opportunities and execution and development is probably half overseas what it is in Norway. In that sense too, that's of interest to us. You're right, we have a robust balance sheet. We expect that to grow as more payments come in between now and the end of the year.
Among our peers, certainly we have one of the strongest balance sheets and the ability to go out and do more, which we very much plan to do and have financial strength now to do so.
Okay. Unless you have a follow-up, I think we will round it off.
Nothing more from me. T hanks.
Okay, thanks to all for joining this call, and we look forward to seeing you again on a later occasion. Goodbye.
Thanks. Bye-bye.