Tethys Oil AB

STO:TETY

Earnings Call Transcript 2021-Q2

[Operator]

Hello, and welcome to the Tethys Oil Q2 Earnings Report 2021. [Operator Instructions] Today, I'm pleased to present Magnus Nordin, Managing Director; and Petter Hjertstedt, CFO. Please begin your meeting.

[Magnus Nordin, Founder, CEO, MD & Director]

Thank you very much, and welcome to the second quarter for 2021, a quarter which I think is surprisingly strong based on where we were a year ago and, in particular, with oil prices having recovered remarkably quickly. So let's go into the details of the numbers. If I start with the first slide here, we have the Q2 '21 highlights. Production of 11,000 barrels of oil per day had been affected by a few operational issues that have been resolved. We are still working with the possibility of being cut back, but we are certainly hopeful that we are going to maintain at least these levels or actually higher as we guide for the second half of this year. Production, of course, at these levels of the oil price is quite important, and we are happy to see that we are at these levels and not lower, but we certainly would like to be higher. Oil price, yes, 28% up quarter-on-quarter, and we are looking at an even stronger price as we can see for the third quarter of the year, which is indeed a remarkable recovery. Production, we expect to do a bit better than we did in second half than the first half. And turning to our exploration blocks. Thameen-1 well drilled in the first quarter, I should say, came in way above expectations on the logs with a very substantial column of oil, disappointed in not flowing. And we are now at the end of the technical evaluation, where we can see that we have some very good porosity, but low permeability in the reservoir. That's something we, of course, will have to deal with. 56 is moving ahead, drilling preparations ongoing as the preparation for seismic. And in 58, we are beefing up the seismic operations. Turning to the next slide. Just a reminder, during the quarter, we distributed $50 million plus to our shareholders, another SEK 4 per share. And that's the seventh consecutive year in the ups and downs of the oil market that we have given a solid dividend and cash distribution to our shareholders. Turning to the highlights. Revenue and other income at $26 million, giving us an EBITDA of $14 million, which is better than the first quarter, and in particular, an operating result that is very much better than the first quarter, as is the free cash flow. They achieved selling price better or they are not as thematically better as it could have been, as we will see in the third quarter. OpEx has come down, which we are grateful for. Netback is up, and entitlement is down. And we are going to comment a little bit more on entitlement. But let me just say that in this oil price environment, we do not expect to build a cost pool. Rather, we expect an even further acceleration in the way we get back all our investments and our OpEx. So the project is in a very -- in a mode where it costs us very little cash to keep it going because we get it back literally within the same quarter that we spend it. And as you will see -- and that, of course, has a direct effect on the operating results being down, although the nominal cash flow is down given the entitlement. But we do see a strong profitability, resilience and robustness from the Blocks 3&4. And if we can see an increase in production, that will translate immediately into better numbers on the top line, of course, and bottom line. A quick comment on the oil price. We have seen a remarkable recovery. It's very much -- we're seeing it from an increased demand perspective. And as the pandemic recedes worldwide, it's a little bit with ups and downs, we are still seeing a trend of the demand recovery. And we are seeing here, for example, that OPEC expects to be able to cut down on its productions and go back to a normal situation over the course of 2022. And the second slide -- this slide here shows clearly that we have the inventory increase that we saw building in 2022 has come down, and we are back to the normal levels. And with the fiscal discipline received from the U.S. oil patch, and the cohesion within OPEC+, I'd say we are reasonably confident that we are going to continue to see the oil market in balance. We should be able to lead OPEC to increase production, while maintaining a reasonable price. And with that, just a reminder that 2 years ago, before the pandemic set in, we were at 13,000 barrels of oil per day. We have, of course, seen a reduction, of course, by the quotas that we had to be aware of, although we have been allowed to produce more than our former quotas. And we certainly hope that we continue. But we've also seen that we have been affected by slightly lower investments. And we are hopeful that the second quarter will see a higher production, and that we will also see increased investment in bringing production back to -- closer to where it was before the pandemic hit. And so much for the forward looking. Now let's look at the quarter in question in some more detail. And for that, we will turn to the next slide, achieved price per barrel, and we'll return to our other speaker, Petter, please.

[Petter Hjertstedt, Chief Financial Officer]

Thank you, Magnus, and good morning, everyone. The achieved price per barrel in the quarter was 59.7% and as Magnus has already said, that's a significant improvement over the first quarter and the situation a year ago when you can see we were at $34 per barrel. So it's certainly a great place to be compared to where we were a year ago and a continued improvement that we've seen in previous quarters. Now it's worth remembering, however, that in the quarter, there was some impact on the achieved price given the slight slippages in liftings because as you know the achieved price is based on the actual oil sales in the quarter that forms the basis of the revenue line. So in the first quarter, we had 2 liftings reflected in the achieved oil price as the March lifting slipped into the second quarter with -- and then we saw a similar situation in the second quarter with the June lifting slipped into the early third quarter. So had we had the normal state of April through June, liftings, the achieved price would have been $63 as opposed to the $59.7. But that all evens out over the year, but that's worth noting on how the achieved oil price came out. And on the subject of prices, the official selling price for the whole third quarter is at this point, already known, as you can see to the right in the graph. The July through September OSPs gives a nice high number around $68 per barrel if unweighted. However, you should remember that -- and that includes the June number. Otherwise, I believe we will probably be above $70 probably. But it all depends on the actual -- the final realized achieved price will, of course, depend on the weighting between the different liftings. That's worth noting, but a clear improvement to be expected in the third quarter. Okay. Moving forward, net entitlement. We have, in the quarter 42% net entitlement out of the possible 52%. We had 50% in the first quarter. Year-to-date, we're at 46%. I think it's worth remembering that in the first quarter, we recovered the remainder of what was in the cost pool. So going into the second quarter, the cost oil was the -- that would be recovered was what was generated in the quarter. We did not use up the whole cost allowance, which meant we came to 42%. And the nice benefit of that, of course, is seeing the profit oil portion increasing. It also means that we've recovered all costs that have been spent in the quarter. Moving then to the next slide. I think that this is worth highlighting that net entitlement as a gross number, of course, is made up of 2 components. It is the cost oil and the profit oil. And as the cost oil portion declines, the profit oil portion increases. So while we had a very slight increase in the value of net entitlement, the profit oil portion increased significantly from the first quarter. And of course, that is the name of the game, maximizing the profit oil, as the cost oil is simply recycling what we're spending. And it's worth remembering the dynamics, and this is -- as the oil price goes up, the value of total production increases, of course. And that means that if costs stay the same, they make up a smaller portion of the total value of production. And hence, fewer barrels are needed to recover that cost. And so mathematically, we do get a lower entitlement in barrels while still recovering the same value. But it does mean that the profit oil portion increases. Moving on to over and under lift. As has been the case for many years now, we nominate our liftings 2 to 3 months ahead of time, which means that the lifting will not always match the exact production in the period, in the month, giving rise to the under and overlift effect. And this is something that we need to neutralize over time. So there, periodically, will be corrections done in the liftings to ensure that we are on balance and not selling more oil than we are entitled to or the opposite, not selling all that we should be. And at the end of the second quarter, we have an underlift position and as we did in the first quarter as well, but it has been reduced somewhat to now only 90,000 barrels. However, that's probably the effect of the June lifting slipping into July. Adding that back, we would have been overlifted by a few barrels. So that's worth remembering. And that will, of course, be reflected in liftings going forward throughout the year. It has been a bit unfortunate this year with the timing of those liftings, which has given rise to a bit more fluctuation than that would be normal. Moving on, revenue and other income. That is both the revenue portion and the value adjustment effect related to over and underlift at $26.1 million. That's up 3% in -- versus the first quarter, but it's a nice improving trend as we've seen since the third quarter last year. Moving on to expenses. I think we're pleased to see that we have a nice fairly stable level of operating expenditure and also a relatively stable admin expense, overhead expense. There were some fluctuations in that in Q4 and Q1, but those effects are behind us. So the $1.7 million is not disrupted by any onetime effects. And the $9.9 million in OpEx reflects the current situation in the field with the slightly lower production. But remember that the first quarter does seasonally usually have a bit higher costs reflecting some one-off annual costs -- sorry, annual cost in the joint operations relating to benefits and bonuses. So this is a normal seasonal effect to see that the Q2 is slightly lower than Q1. OpEx and netback per barrel. We see the netback per barrel improving significantly, reflecting the higher achieved oil price and the lower OpEx. So we have $15.2 per barrel. And you can see that OpEx per barrel is at $9.9. So we're very pleased with that development, and I hope to be able to see this continue. Moving to EBITDA. This reflects, of course, the improvement in revenue and other income and lower OpEx, which results in the improved EBITDA to $14.5 million in the second quarter. Now to investments. In the quarter, we had investments, oil and gas assets of $8.4 million. Majority of that in Blocks 3&4, picking up somewhat from the first quarter. And as we have indicated in the past, we do expect investments on Blocks 3&4 to increase gradually throughout the year. And we also see -- expect the investments on, particularly Block 56 and 58 to pick up as the year moves along and as activity picks up. First quarter was impacted. We had a negative investment as related to the Block 49 farmout transaction and the consideration we received, giving rise to that one-off negative impact. And that gives us actually a free cash flow of $4.9 million. That is the cash flow after investments. Year-to-date, we have over $7million in free cash flow, which is better than we had for all of last year. So that's a nice improvement. And I think, it is a key metric to keep an eye on as the company develops. And looking at the year-to-date situation. You can see -- when it comes to cash flow, you can see that we have cash flow from operations of just above $26 million. We have a negative working capital change. That's in part related to what we see in the EOG farmout transaction. So we expect that to balance out somewhat as the final consideration, which was paid after the close of the quarter came in, reducing that negative effect. We have investments of $9 million in the year giving us a free cash flow of $7 million so far. And you can also see we have, of course, distributed $15.5 million in the past quarter. And with the share buybacks, we're well above $16 million in distributions to shareholders. Which brings us to the balance sheet, which remains very solid. Oil and gas properties of 200 -- just above $200 million, cash of just above $46 million and no debt, leaving us with a very, very solid situation to weather both storms and to look at future opportunities irrespective of the environment we're acting. And with that, I'd like to hand over the word to Magnus again.

[Magnus Nordin, Founder, CEO, MD & Director]

Thank you very much. So we'll quickly turn slides to the operation slides. This is the Sultanate of Oman. We see clearly the Omani land maps at the southern -- south Eastern edge of the Arabian Peninsula with adjacent waters. And you note that now some of the -- a bit of the waters have all also been put into blocks, and some of this has been licensed with the occasional offshore oil [agreement] wholesale. The Tethys, of course, is strictly onshore. And we want to focus on the blue areas here, which is Tethys' exist position in Oman, surrounding, in particular, the central part of the Oman, the green area, which is run by PDO, the joint venture between the state of the Oman and Shell and various other oil companies. Of course, at the dawn of time, the PDO concession encompassed all other countries, and -- which is to say that all [indiscernible] are previous relinquishments from PDO.And here's really the key to what we are trying to do for the long run, which we started with 3&4 because we learned more about how the geology of Oman works and also how the geology of Oman has been interpreted in the past. We realized that there was a lot of overlooked opportunity on the flanks. And thus, we've built this position on the flanks of the Central area of Oman, entering into separate basins and also new plays within the Central Omani salt basin.And that has played out quite well for us so far from 3&4. And that's, of course, what we're trying to do again with 56, 58, to lesser degree in 49, which is more -- which is the Rub'Al Khali Basin, which is a completely different play, but where we, of course, have the success of the mean showing that there is indeed a working petroleum system also in Block 49. And this is our long term -- our long run. This is where we hope to see future production come from while we continue to explore blocks 3 and 4 to maintain and increase production there also.We are not alone in the mine. Apart from the PDO, we do have colleagues, like Shell and BP, ENI, our partner EOG, Occidental, Total, and PTTP, all active to a larger or smaller extent in Oman. The pain point would be [indiscernible] oil field which came -- gas field which came on stream and 5 years ago, which has changed the gas outlook for Oman dramatically. So we are not the only ones seeing opportunity -- continued opportunity and possibly increased opportunity in Oman.Turning to the next slide. Just to remind you quickly that we have a 30% stake in Blocks 3&4 from which we get our production, and we have seen production from this block since 2012, peaking -- at least the latest peak was in 2019. CCED is the operator, Mitsui has 20%. 49, we are the operator; EOG, 50%. So we announced the Thameen in late 2020. We completed in the first quarter, and we actually closed the final payment of the Thameen only a couple of days ago.Block 56. We operate as of half a year ago with previous operator Medco staying in the 5% and local Omani service company Biyaq currently 25% together with another Omani company Intaj. 51 -- 58, sorry, awarded to us in bid round last year. We had 100%, and we are the operator. Similar situation that we had with Block 49, which was awarded to us in a bid round in 2017.Blocks 3&4, producer saw some massive deferment of investment in 2020 due to the cutbacks and quotas and the corona situation. We have come back here, and we are back to 3 drilling rigs active and 1 workover rig. So we expect development in drilling to pick up in the second half. We expect the exploration well in drilling to pick up in the second half. And we also expect production to pick up in the second half, while, of course, the continued work of infrastructure focus within Blocks 3&4 will continue.On the exploration side, we drilled the Safi well in the first quarter. It's currently under -- in production testing. And the Suhail well, we expect to see spudding within the next day also and it's definitely a little bit in the month. Safi is on the left-hand side of our Shahd field west, the main Shahd producing area and Suhail is to the East, an exploration well between the Shahd field and the Erfan field, in what we call near-field exploration. We also hope to see some far field wells drilled before the end of the year.49, Thameen now 50-50 between EOG and Tethys. Well went very well indeed. And as I mentioned before, we know we have all the -- we know we have the petroleum system working. We know we have good source. And we also now know that we have a workable reservoir, however, one with good porosity and low permeability. We are looking at the best way forward to further appraise the reservoir in question. And we will focus for the third quarter when the work with 49 comes up to see how best we are going to make use of the data we have in 49 and how to take the project forward. The current license extension expires in December. So it will indeed be focused during the third quarter, how we're going to take this project forward.56, according to plan, we are gearing up to appraise the Al Jumd trend. And we are -- we can turn immediately to the next slide, by the way, what's shown in the multiple leads in 2D seismic. So Block 56 really consists of 2 parts: we have the upper ring, the Al Jumd trend, where we have churned oil to surface, which is on trend with the producing green field to the immediate left of the block boundary. We will continue the appraisal with a view to get this long-term production before the end of the year and see how far we can take it. While we prepare for an extensive seismic study in the southern ring, where we have a number of interesting leads, similar in nature, some of them to Blocks 3&4, but of this also we are being charged from a tertiary basin that extends from offshore into our block. From what we know today, I would say our probably most interesting exploration adding up, and we are eagerly awaiting starting the seismic campaign.58, we are here in the extension of the Oman Salt Basin. It's part of the main Omani Fairway and turning to identified leads. We have now become more familiar with the seismic collected by previous operators. We have a number of leads and even a larger number of potential leads. But most importantly, we are focusing on the ones highlighted here, and we are planning a new seismic acquisition to be done later this year over the one within the square, which, as you can see, is right adjacent to producing lookalikes, Block 6, operated by PDO.This is mainly [Audio Gap] given that well underway to get the seismic started in Block 58.So that said, whereas the second quarter has seen some very strong numbers from the outside world, we are hopeful we'll see better production from 3&4. We are hopeful we will continue to see good oil prices. And we already know that the Q3 price is going to be very good indeed. We will focus on how to take Thameen further and do a proper continued appraisal that in mind that we are dealing with a tight reservoir. And the exploration program, 56 and 58, continue. And 58, a little bit faster than expected; and 56, according to plan. And that is, of course, where we hope to see some very interesting developments over the next year to 18 months.On that note, I would like to open the floor for questions.

[Operator]

[Operator Instructions] Our first question comes from the line of Stephane Foucaud from Auctus.

[Stephane Guy Patrick Foucaud, Head of Research]

A few questions for me. First, an accounting sort of question. When you talk about the underlift position being quite hard with us over the coming quarter, but I could also notice that the current payable are still quite low and probably that has an impact on working capital. Would you expect that to potentially reverse to a higher figure next quarter that could have a positive impact on cash flow? That's my first question. Then on Thameen. What's the -- what are your thoughts here? What would be the potential -- what would happen in Q3, Q4? Is there a situation where you could decide not to progress with Thameen at all? Or is it more hard to progress whether than -- whether you will progress or not? And lastly, I noticed that there is this Suhail exploration well. I think I was not covering previously. How material -- could that be between just a few million barrels? Could it be a bit more?

[Magnus Nordin, Founder, CEO, MD & Director]

Okay. Thank you, Stephane. Petter, you want to deal with the overlift question first?

[Petter Hjertstedt, Chief Financial Officer]

Yes. I mean we have the underlift situation, which, of course -- so yes, no. We have an underlift situation and that's mainly a consequence of that June lifting slipping into July. But when it comes to payables, I would -- it's difficult to give any real guidance on that. That's usually impacted partly on the overlift and underlift situation as such, but we would expect the -- if you adjust for June, we're actually in more of an overlift situation, practically speaking. So -- and I think that situation, we're looking to balance out throughout Q3. But we'll see where we end the quarter, and that really depends on the production, which we don't know yet. So it's difficult to give any real guidance on that. But in terms of receivables, the main section of receivables is, of course, related to the final consideration from EOG that now we have received. So that will have improved from that point of view on working capital.

[Magnus Nordin, Founder, CEO, MD & Director]

Thank you, Petter. If that was all right, Stephane, let me talk a little bit more about 49. The -- if I have to speculate, the obvious way forward here would, of course, be to -- I mean we have an old column of some 30 meters, good porosity. So there's definitely something there. And then the permeability is lousy. So it's really an extraction issue. It's a matter of how to get the reservoir to flow in the best possible manner. And of course, the school book way of doing this. I mean if you get your reservoir book out, you would say, increase the volume of the well, i.e., drill horizontal and crush the reservoir, so that increased permeability, i.e., frac. So most likely, we will have to look at various ways of horizontal sections, the best way of stimulating. And I would say it's not a carbonate. It's a plastic. It's a sandstone. So you would typically not look at acid, for example. You'll be looking at maybe some other way of fracturing the reservoir and making it stay open. There are, of course, ways also of chemically stimulating the plastics. And so that's really what we're going to focus on for the third quarter.What would be the best way of making this particular kind of casting reservoir flow? As you know, we don't really have experience at this in the past. We had some quicky carbonates in 3&4, but we -- and we have some very thin difficult clastics. They are -- they have better permeability than we have seen here. So we don't really have the experience from this. So we've obviously had to look at people that have experience and find the best person -- people to help us with taking the project forward. And of course, we have to make up our minds before the end of November, really, and either enter into the second period for the license or ask for an exemption or in the worst case, quote for above. But as I say, there's definitely something there, and we have a clear idea of how we want to continue the work in understanding the reservoir. So I would expect a lot of activity during the third quarter.

[Stephane Guy Patrick Foucaud, Head of Research]

And how does EOG feel about it, if you have communicated anything?

[Magnus Nordin, Founder, CEO, MD & Director]

I have to give you the obvious answer that, you have to speak to EOG. But let me say they are, of course, are 50% higher, and we -- of course, we expect them to be supportive with the expertise they may or may not have in this particular regard. But that view will have to come from that. Any further questions, Stephane?

[Stephane Guy Patrick Foucaud, Head of Research]

Okay. And lastly -- yes, the last one was on the new exploration target...

[Magnus Nordin, Founder, CEO, MD & Director]

Typically -- yes, sorry. Okay. So Suhail is a near-field exploration well. So typically, it's a lower risk, lower reward situation given that it is. And as you can -- as I briefly shared in the map, it's right between the Shahd and Erfan fields. So we are right in an area where we have production. So we would expect it to be -- to have a reasonably high chance of success and could contribute to -- reasonably quickly contribute to production. And size-wise, near-field wells are typically smaller in size than the far-field wells where we look at bigger targets, but also with higher risk.

[Operator]

And the next question comes from the line of Teodor Sveen-Nilsen from Sparebank 1 Markets.

[Teodor Sveen-Nilsen]

I have 3 questions from me, if I may. Petter, you briefly commented on the realized oil price this quarter. As far as I understand, the discount to the official selling price is mainly due to the timing of the lifting. Can you please confirm that? And if not, what other factors are behind that discount? And second question, on the entitlement. Are you in position to provide any guidance going forward? You indicated that maybe around 40 going forward. Is that correct? And lastly, on CapEx guidance. Is this still $47 million you plan to spend this year? Or could you provide any update on that figure?

[Petter Hjertstedt, Chief Financial Officer]

Yes, thanks for the questions. Yes. No, the achieved oil price we have is calculated on the basis of the revenues of the liftings recognized in the quarter. So in this quarter, we had, of course, the March lifting which slipped over from the first quarter, April and May, and the June lifting slipping into the third quarter. So it's a slightly skewed price, which -- so it reflects those 3 months sales. And of course, when you look at the achieved price, well, that comes weighted by the relative size of the different sales. So if I recall correctly, there was -- I believe the March lifting was relatively big in relation to, say, the May lifting. So that will have also balanced shown through in the achieved price. So we're not actually getting a discount to the OSP in any way. Each lifting is, in fact, priced very much in line with the OSP. However, the actual kind of mix between the months does have an impact. And as I indicated, had we had a normal sort of setup of liftings with April through June, we would have been at 63 for the second quarter. So it's more a question of timing and weighting. There's no money lost, so to speak, vis-a-vis the official selling price.And then when it comes to -- what was your second question? Was that net entitlement? Well, the difficult part with net entitlement is that we don't know the oil price for the rest of the year because as the oil price goes up and everything else stays the same, well -- if costs don't increase, well, then they do make up a smaller portion of the total value of the production. So in that, it is very difficult to estimate what the final entitlement will be. We -- but as Magnus also mentioned earlier in the presentation, we're not expecting to be generating a cost pool this year. So yes, most likely, we will be comfortably below the 52%. And if oil prices continue to be strong, well, that does mean the value of our profit oil remains high as well. So that's a positive. We are looking in the future quarters to provide an update ahead of the quarterly release with some of this information to give you a bit of guidance as it is difficult to completely calculate the net entitlement on the basis of the publicly known information ahead of hand. So you can look forward to that in the coming quarters. And you had a final question, I don't exactly recall that one.

[Teodor Sveen-Nilsen]

Yes, that was on CapEx. You previously guided for, I think, just $47 million for this year. Is there any change to that number? Are you intending to invest more given where the oil price sits right now?

[Petter Hjertstedt, Chief Financial Officer]

I think we are -- we haven't changed that guidance. We haven't changed our investment guidance. We will stick with that. I think the higher oil price certainly leaves a lot of room for more investment given that there is more cost recovery on 3&4 to use. But it's also a question of practicalities and what -- and also doing meaningful investments. So it's not always a numbers game. It's also being able to actually deliver those investments. But yes, I mean it does leave more room for it. So if practical and there is a positive potential return from it, I do -- that would be considered.

[Operator]

[Operator Instructions] We have another question from the line of Karl Pedersen from ABG.

[Karl Fredrik Schjøtt-Pedersen]

Thank you for your presentation. Just following up on the CapEx guidance, I'm trying to look further down the road. How are you thinking about spending into 2022? And what kind of -- what will be the basis for your investment program when we look into '22? Could you also provide some color on the allocation of capital between Blocks 3&4 where the spending is totally linked to production and revenues versus the other, more early phase exploration areas? That's my first question.

[Petter Hjertstedt, Chief Financial Officer]

Okay. Well, let me see. Sorry, when it comes to 2022, I think that's -- it's a difficult one. I mean if you -- but you can go back and you can look at kind of what has impacted our investments in the past. Well, look -- well, partly, of course, is the macro environment, how comfortable are we with the oil prices and the profitability of the project. And as we saw last year, having -- seeing oil prices come down significantly, that led to a significant reduction. It also meant that that's picking up. Our investment has been a bit slow as there has been a great level of uncertainty. There certainly is room to keep investing in the project, and there's lots more to do that we see is value accretive. But of course, we're still in a pandemic, so that creates some uncertainty, even though oil prices are looking very good and solid at the moment.And then also in terms of what -- the OPEC+ situation, what's the comfort we have in that, so I think those are some main factors in looking into 2022. And it's a long planning process, and it's partly working from long-term plans and multiyear plans and then sort of fitting those into the more immediate context of oil prices and production possibilities. But I think we're looking quite positively at the next year, where we're standing now, but we're still some way away from 2022. So it remains to be seen, but certainly the indications overall are on the positive side for us to feel more confident.And then when it comes to allocation between the other projects, well I think every project is viewed on its own merits, and we really -- if we look at particularly 56 and 58, where we have more activities coming up, we certainly see -- we will fulfill our commitments on those blocks and that is doing a proper exploration of what we have identified as the potential. So we have seismic coming up on both of them in the next sort of 12 months and some drilling. But everything beyond that really is very much a question of success based. So it's difficult to predict what to do on those blocks before we've had any results of any drilling, I would say. But we certainly will be properly exploring both those blocks. And as we've done with 49, we'll see where we'll go with 49. That's a question that I think Magnus has already addressed. I don't know, does that answer all your questions? Or did I miss something?

[Karl Fredrik Schjøtt-Pedersen]

Yes. And if I may add another question as well, please. If we were to look at -- what do you view as the production capacity out of Blocks 3&4? Meaning that in a scenario where all production quotas are lifted, what would be kind of your run rate production level?

[Petter Hjertstedt, Chief Financial Officer]

Yes. That's a difficult one, and I'm not sure there's one answer -- proper answer...

[Magnus Nordin, Founder, CEO, MD & Director]

So let's -- I'll have it quick. I mean the -- nothing has happened with the infrastructure of the fields that, in any way, would have impaired the possibility of getting back to the levels that we saw in 2019. So we say, a clear [sign] that -- produce as much as you possibly can for the next 5 years and no constraints. There would be ample room to increase investments and ramp up production. And if -- so the theoretical upper band is quite -- it's certainly up among the numbers we've seen in the past. Now under what circumstances we'll be able to get there is a slightly different question. And that's where we have to look at oil prices, we have to look at OPEC+ behavior, we have to look at overall demand and a number of other factors. So -- but to give you some sort of flavor for what would be possible, certainly getting back to where we've been in the past, the circumstances that take us there, to be determined.

[Operator]

And as there are no further questions, I'll hand it back to the speakers.

[Magnus Nordin, Founder, CEO, MD & Director]

I think on that note and being optimistic for the future with an interesting information program, we hope to see you again in about 3 months' time, when we are in November and the third quarter is completed and evaluated. Many thanks. See you then.

[Operator]

This concludes our conference call. Thank you all for attending. You may now disconnect your lines.