Tethys Oil AB

STO:TETY

Earnings Call Transcript 2022-Q3

[Operator]

Good day and thank you for standing by. Welcome to the Tethys Oil Q3 Earnings Report 2022. [Operator Instructions] Please be advised that today's conference is being recorded.

I would now like to hand the conference over to our speakers today, Magnus Nordin, Managing Director; and Petter Hjertstedt, CFO. Please go ahead.

[Magnus Nordin, executive]

Thank you very much. Good morning, everyone. This is Magnus addressing you from a still very mild Stockholm autumn weather, very much the season of mist and mellow fruitfulness, and we are grateful as long as this weather stays with us. But welcome to yet another quarter with Tethys, highlights from Q3 2022. It's been one of those quarters where we have a strong financial and a lot of reparatory work for some interesting exploration and growth objectives for next year. That was primarily relating to Block 56, where we completed 2 wells into the Al Jumd structure, both encountered good oil sales, and we have now a very good geological idea of what the structure holds.

We are moving on to do an extended well test. This we expect to start within the next weeks. Virtually all the equipment is in place where it is waiting for a meter to measure the oil we actually deliver from the field into the Omani national pipeline system. And as soon as that's been commissioned and ready to go, we'll be off to start the long-term production test.

On Block 58, the seismic interpretation is almost completed. So far, all the leads are still there. We've done some important geological work, and we are gearing up for an interesting drilling campaign next year.

Production for the quarter, slightly disappointing 9,788 barrels of oil per day. On the positive side is that we have had lots of interesting data from the operator and what's actually going on in the field. And I think we are getting more and more confident that the production will stabilize and should be in a good position to start climbing again next year. In summary, I think we can say that the corona effects and surface constraints and the time it's taken to rectify surface constraints also with getting a new equipment in has been underestimated. We believe we know what needs to be done and we are getting done. So the -- as we say in the highlights, it's very much about debottlenecking action taking place. And of course, high oil prices and continued cost discipline and fiscal discipline has been a main driver behind the increased earnings for the quarter.

Turning to the Block 56 appraisal activities. It's one of our more interesting blocks. The Al Jumd is escorted by itself and the discovery that we have now proven significant amounts of oil in place. We are waiting to extend their production tests to get a better idea of what kind of recovery rate it has and how much oil we can actually plan to get out of this structure over the next couple of years.

The central area is a slightly different story. It's larger prospects than Al Jumd. We have some 12 leads we are focusing on within the new 3D seismic area, and we are well underway in processing and then interpreting that area. So far, the good news is that all our 2D identical leads are still there, and we have to have them in the prospect shape within the next 6 months.

Testing operations on the Al Jumd near wells, Sarha and Sahab, is on hold pending the arrival of rigs and also increased focus on the Al Jumd area. We will get back to that in the early part of next year.

Al Jumd, of course, is the main discovery so far in Block 56. We have 3 horizontal wells. We have delineated the structural well, and we have oil throughout the structure, which, of course, is the good news. The Al Jumd-2 well tested at an initial rate of 700 barrels of oil per day, but the real test of the productivity of the Al Jumd reservoir and potential field will come early next year as we can assess the long-term production test.

Everything is in place in the field and the tanks are filled with oil from the earlier testing. And I'm certainly not going to go into this drawing in any detail. But the main item we are waiting for to get installed is the Coriolis meter, on the far-right corner of this drawing. And this has been manufactured in Abu Dhabi, is currently undergoing tests to prove its ability to deliver, where after it will be moved to the field and installed. As I said, we are expecting somewhere between 4 to 6 weeks at most before this is fully commissioned and up and running.

So turning to Blocks 3 and 4. And as you can see very clearly here, we peaked out at 11,585 barrels of oil per day in Q1 2021 and have seen production fall virtually since then. In particular, 2022 has been weak. And what we have concluded in first quarter, we had a water breakthrough from one of the smaller fields. We wish then that was quite recovered. But that has also been followed by surface constraints. And we see an increased water cut in the Farha South field, there have been difficulties in separating out and handling the amount of water to get more oil out of the field. The problems have been identified, and we now know what's going on and the operator is working hard to fix this.

The main disappointment is that it's taking a bit longer than we had originally envisaged. But we are hopeful that things will stabilize over the fourth quarter and that we will see production increase again in 2023. That we know there, of course, that we still expect to have some 10,000 barrels of oil per day for the full year. And that, of course, in this oil price environment continues to yield us very good cash -- operating cash flow out of the blocks we have formed. 3 and 4 will also be focused on more operational appraisal as the quarter starts in Q3. We are therefore doing 1 exploration well that has been postponed for drilling more production wells during the course of the third quarter. And we are also gearing up to drill a quite significant well, the Yari-1 well that is scaled to start in early next year.

It's an exploration well drilled in a very underexplored area in Block 4. Previous wells have encountered oil, but no flows to surface have been established. And as you can see from the map here, there are a number of fairly large leads and prospects in the area. Yari-1, where we'll expect results during the course of the first quarter next year, it's going to be quite an important way to see if also that part of Block 4 would warrant a development on its own.

Seismic campaign is continuing. And before the end of next year, we expect to have most, if not all, of Blocks 3&4 covered by state-of-the-art new 3D seismic. The results so far from the exploration side this year has been rather limited, primarily because we have not really drilled any exploration wells.

And last, but certainly not least, Block 58, where we see seismic activity and also geological upgrade. Processing of the seismic study that we did earlier this year is completed. And prospect generation is fully ongoing. And we expect to have this completed by the end of this year. And there are some quite sizable prospects on this block. It's not quite as prolific from a prospects perspective 56 is. But sizes are quite large. And if they work, of course, it will be of great interest to the future growth to complement Block 56 and 3 and 4.

And on 49 is desktop work. We completed the well last year, encountered oil and gas shales while drilling, good logs, no flows to surface, and we are now preparing to do a proper hydraulic fracking operation in 2023 to see if we can fracture the rock in such a way that we can get the hydrocarbons out of that rock. We then expect results until the second half of 2023. If it works, of course, it will have a significant impact for the understanding of this part of Oman, which is currently not in production.

That briefly sums up what we've been doing on the operational side. And now I will happily turn the floor to Petter for the financial highlights.

[Petter Hjertstedt, executive]

Thank you, Magnus, and good morning, everyone. Financially, we have yet another strong quarter. And you can see from the graph, trend-wise, we're doing very well on both earnings and revenues with the oil price being the main driver of revenues and with stable costs ensuring that we have EBITDA growth in the same level. We are now at revenue and earnings levels that are comparable to levels we saw in -- last saw in early 2019, which is in itself impressive, given that production levels are a bit more modest than at that point.

In the quarter, we had an achieved oil price of $107 per barrel. That's up versus $100 the quarter before, and that's reflected in the earnings line. We've also seen significant investments continue at $20 million, resulting in a free cash flow of just above $3 million as we continue to invest significantly in both Blocks 3 and 4 and Block 56. But yet the year has offered a lot of shareholder returns. And most recently, we activated a share buyback program and 89,000 shares were repurchased before we went into the filing period. We also have -- remained with a solid financial position of over $40 million of cash on hand and no debt.

And speaking of returns, we can see that our return on equity and return on capital employed currently at levels that we have not seen since 2019, and these are comparable almost with 2018 levels, showing that we've been now seeing the financial turnaround that we've been seeing in the P&L quite solidly in these metrics as well.

Now the oil price being the main driver for our P&L earnings, you can see the average OSP in the quarter was $107.8 achieved price, somewhat lower. That's a consequence of the varied timing of liftings and a slightly different mix of lifting volumes versus production. And as you're familiar with, there is a slight delay of the OSP versus the spot prices we see in the market. So we already now see that the potential unweighted average OSP in Q4 is around $93 per barrel. That's reflecting the levels we've seen in recent months in the market. And the differential versus Brent for the Oman Blend is now at less than $1 per barrel coming down significantly from higher levels that were up as high as $4 per barrel in the previous quarter. So that's -- it's good to see that the Oman oil quality is strengthening vis-a-vis its peers in the market.

Moving on, we saw a quarter with significant oil sales of about 420,000 barrels. That's up significantly versus Q2. And as I'm sure you recall, this was because of Q2 only capturing 2 liftings instead of the customary 3, which means that this quarter, we had 4 listings instead of 3. And so we had June through September liftings captured in those sales, and that's also reflected in the achieved oil price. And this also means we had an overlift movement in the quarter of about 41,000 barrels. That is the number of barrels sold compared to the entitlement. So our underlift has been reduced by that same number.

Speaking of entitlement, that is the barrels of oil that we are entitled to sell, it's fairly stable throughout the year. We're about 42% of production with higher prices. Of course, that means we get fewer barrels for cost oil, but that is offset by the higher total expenditure on Blocks 3 and 4. So they balance each other out. But as we know, it's not the number of barrels. It's the kind of barrels and the value of barrels that's the important metric to keep track of. And as you can see on the graph to the left, net entitlement value has been growing steadily throughout the past few quarters. And that means that profit oil portion is growing as well in value and that's the -- what the profit we received from the operations on Blocks 3 and 4.

Now OpEx is quite stable over the quarters. OpEx per barrel is up somewhat, but that's mainly effect of the lower production quarter-on-quarter. But you can see that on a total level, it's basically flat compared to the previous quarters. And what we see is that cost savings that are being done and the savings that are as a result of the lower production are offsetting the cost pressures on energy and other consumables that are coming up. So -- and we're now looking for a full year number of about $13.5 per barrel in OpEx.

Moving on, cash flow. The cash flow -- operating cash mirrors very much our earnings trend. You can see it's trending upwards quite solidly in recent quarters with the working capital adding some volatility to that. And that's a consequence of timing effect of liftings and the over underlift, and it's really not something that has a sustainable effect on the actual cash flows. It just creates intra-quarter volatility. So you can see a strong operating cash flow of $27 million and a negative change in net working capital. And if you just look back a few quarters, you see this even out over time.

So -- and after that, we have quite a significant investment program. We are -- this year, we are investing levels that we have not seen for many years and that is both a step-up in Blocks 3 and 4 investments as we have invested in seismic to push exploration further, but also adding a fourth rig to increase the drilling capacity to push a turnaround in production and hopefully also in exploration success. But also, we've seen some significant investments on Block 56 with both seismic in Q1 and significant drilling throughout the year. And despite the significant investment program, which is the largest since 2012, we have seen overall, some positive free cash flow in the year with the Q1 being the big spend negative when the 3D seismic on Block 56 was paid for. Otherwise, we're seeing good free cash flows. And seeing that this year we probably had a peak in exploration spend, we'll have turned the corner in this respect. But there will be fluctuation from one quarter to another and as significant discretionary exploration spend impact the individual quarters.

But the overall picture is quite rosy, I'd say. We have good cash flow generation in the operations and more than offsetting the investments, leaving us with plenty of room to this year to return cash to shareholders, $23 million this year so far and leaving with a cash balance of $42 million at the end of this quarter.

The netback trend, I think, is worth keeping an eye on. This is where we see the underlying value being created in Blocks 3&4 where we kind of can look beyond the fluctuations of working capital and timing effect but rather seeing the net value being generated in total dollars, but also dollars per barrel. You see that is trending up quite nicely in USD per barrel. So a big step-up in Q3 to $15.8 from $12.9 in Q2. So trend-wise, it's very strong, and this is the underlying value being created and can generally be seen as a proxy for profit oil, that is the netback net of CapEx, so to speak, on 3 and 4.

And looking forward to our guidance, we have, as Magnus already mentioned, revised our full year guidance to 10,000 barrels per day, reflecting some of the constraints we see on the surface. But we are confident that we're investing for a turnaround. And equally, the operating expenditure per barrel is a reflection of that change in production levels. And we now expect to have total CapEx for the year of about $84 million, just down somewhat from $87 million, reflecting both timing and spending -- changes in spending priority.

With that, I hand the floor back to Magnus.

[Magnus Nordin, executive]

Thank you, Petter. Very impressive numbers, I must say. All right. As you're all aware, those numbers would not be very well if it was not that oil prices were as strong as they are. So I think it's worthwhile that we spend a little bit of time in trying to give a possible view of oil prices.

So turning to the -- well, the main point I would like to try to make here is that oil prices are where they are primarily because of demand and that the demand is outstripping available supply. If you look at the graph here, we can see that oil prices were already coming up by early -- by January 2022. And then we had geopolitical reasons, a massive uptick that lasted until July, August of this year. But if you take the trend we've seen since late August to early September, it follows fairly well the uptick and the increase in prices we have been seeing for -- as we have come back out of the corona environment.

Turning to the other side of the slide, you see how demand has come back strongly. And despite fears of recession, despite the lockdown in China, we are seeing demands now well above 100 million barrels of oil per day. And this is a return that I think that is certainly stronger than was originally envisaged just a year ago. And I would argue that is the main reason why we are seeing prices and why we think prices will remain at these rather lofty levels.

So turning to the next slide and look at the supply side. Well, we have importantly managed market from OPEC, where they also cut production barrels at the latest meeting. But if you do look closely at the numbers, there is not actually that much spare capacity even within the OPEC countries. And the compliance rates continue to be way above 100% within the OPEC+ group. This suggests that there is -- that there are actually supply constraints given the current demand. And the reasons we produce U.S. shale shows a slip in production over the last couple of months. And we've seen also about the drilling rigs and fracking crews have -- numbers have come down over the last couple of months.

So as we understand it also, the guidance from the major U.S. companies is to focus on cash flow and capital discipline. And based on that, I would argue that we are going to see an oil market primarily driven by demand and with little spare capacity where any weaknesses in demand can easily be met by supply cuts. And based on that, we would expect or we would argue that we are going to see oil prices at these or possibly even higher levels for the foreseeable future.

That said, we are hopeful and planning for a year of high prices. As we summarize the third quarter, we have had what is now amounting to a stable production of around 10,000 barrels of oil per day that we perceive for the year. As Petter has shown and gave an example, cash flow both to buy back shares -- used for share buybacks or for other cash distribution to shareholders, but also to fund other growth projects.

The operating cash flow out of 3 and 4 both goes to stabilizing and increasing production, but also finding more oil in Blocks 3&4. And of course, we are spending it on future growth. And 2022 from that perspective will be a year of a lot of seismic expenditure, which is money that you see coming out of cash flow and coming out of cash, but you don't necessarily see the results until almost a year later. And we are in that stage right now where we are taking the seismic data and turning it into drillable prospects.

So to conclude it, 2022 has seen a peak exploration spend and we've been very fortunate that we've been able to use cash and cash flow to pay for this. And as we move into next year, we will see a more visible activity on Blocks 56 and 58 with prospect sizes being delineated with resource base -- prospective resource base being determined and eventually also drill bit being brought out to test those prospects integrity. In 3 and 4, a fourth rig has now been made operational, while debottleneck operations are seriously gaining speed. And I would again say that that has been the main reason why production in the second half has been as lackluster as it has been.

So on that note, we continue to show very strong financials. We are having a very interesting growth year next year. And fourth quarter to yield continued good oil price, good cash generation and a good cash position towards the end of the year as we move into an interesting 2023.

On that note, we would like to open the floor for questions.

[Operator]

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

[Stephane Guy Foucaud, analyst]

I've got a few. The first one is around -- so this debottlenecking activity at Blocks 3&4, assuming there was no bottleneck problem that you could handle the water and so forth, what do you think the production could be without the debottlenecking issues? That's my first question.

My next question is on this Yari-1 exploration well. So you mentioned that the well will be drilled in an area, from what I understood, where you encountered the oil before, but it didn't flow. So what would be a good result looking like? You're looking for flow rates for Yari-1, you're going to encounter again net pay? And then you say it could be quite material. What sort of volume are we talking about for this area that will be derisked by the Yari-1 in case of success? I've got a few others, but let's stop by that.

[Magnus Nordin, executive]

Okay, thanks. Thank you, Stephane. Very relevant questions and not necessarily easy to answer. If we start with production, the -- I can't really give you a hard number, and also it would be speculative. Obviously, we will come with a guidance for next year as we see how the work is progressing and what we think would be realistic for next year. But I mean, I showed the trend of production for the last quarters. And I mean, obviously, we would be hopeful to see -- to be able to return production to higher levels than we've seen in the past. But to actually give a number, I think, would be too speculative and we must refer to the guidance for next year that we will publish in connection with the Q4 report.

Turning to exploration. Yes, you noted the Yari. Well, the area where Yari is being drilled is the entire southern part of Block 4 where both previous operators and also CCED and ourselves, current operator, have drilled wells before. There is clearly a petroleum system present. Seismic has been sketched in the past. We used 3D data when we drilled that's been -- then been reprocessed and reinterpreted.

And there are a number of prospects in that area that can be quite large. I don't really want to put a number to it, but I would say that given that it is as far away from the current infrastructure, we would certainly expect something if the area turns into being commercially viable, that it would be sizes that would warrant installation of production facilities, et cetera, also in that part of the block. So it would be something that would be significant. But let us revert with the numbers when we get a little bit closer to the spud date.

[Stephane Guy Foucaud, analyst]

A follow-on, and then I'll turn to next one who wants to ask a question. You talk about exploration drilling on Block 56 and Block 58 next year. I was wondering what we are talking about. Are we talking about 1 well per block? Could it be more? And I appreciate you're still thinking that, but it would be great to have some sort of sense of how busy you could be on the drilling side on those 2 blocks.

[Magnus Nordin, executive]

Of course, Stephane. Let me answer that by saying that we have a well commitment of 1 exploration well on Block 56 and a well commitment of 2 exploration wells on Block 58. So that, of course, will be the minimum that we would expect to drill. Depending on both Al Jumd results, depending on the continued testing of the Al Jumd success as satellite structures. And of course, depending on the size and a geological chance of success of the prospect inventory once we have completed that will -- could very well impact the drilling schedules. And we will get back to that with much more details as next year unfolds. But as a direct answer to your question, between 56 and 58, a minimum of 3 wells will be drilled.

[Stephane Guy Foucaud, analyst]

Wonderful. Most appreciated.

[Operator]

[Operator Instructions] There are currently no further questions. We've just had 1 question come in. One moment. I will now take the question for you. And your next question comes from the line of Knut Martin Karlsen from Commandeer Capital.

[Knut Martin Karlsen;Commandeer Capital;Analyst, analyst]

Just a short question on the CapEx side. Could you try to break down the CapEx in maintenance and growth CapEx? Because it's sort of hard to get around whether or not the majority of the CapEx goes toward keeping the growth stable or if it's going to increase in growth?

[Petter Hjertstedt, executive]

Yes, thanks for the question. It is a difficult question to answer in that it's not always easy to say exactly what is growth and what is maintenance. A significant part of CapEx is, in fact, drilling, if we take Blocks 3 and 4 in particular. And of course, drilling is both -- can be both to stabilize and to grow, whereas I would say that the majority of the drilling is actually going in to sort of maintain the current production levels. It is -- 3 and 4 is a drilling-intensive asset. So the majority of drilling CapEx is certainly going to maintaining levels. But the split between is not always easy to ascertain. And it depends on a number of other factors as well. And as we've seen this year, we have been investing in drilling in yet where we haven't fully been able to realize that growth given surface constraints and in particular in water handling systems and such and also in workover capacity to ensure that we stabilize the current producing wells.

Now the seismic, however, I would say that is clearly a growth investment. While it doesn't give immediate returns, it does open up for future exploration drilling. And the lead times are slightly longer than on drilling, but it is a necessary part of the investment. So looking at our total CapEx program, I would say, we're probably somewhere about -- taking into consideration exploration spend, we're probably somewhere around 50-50 between the 2 on the back of the envelope. But I would say that there's significant investments being made this year in terms of growth, even if we haven't seen that realized in that short time span.

[Operator]

[Operator Instructions] And your question comes from the line of Stephane Foucaud from Auctus Advisors.

[Stephane Guy Foucaud, analyst]

Yes, I had a follow-on on Al Jumd, please. So you talked about a well test that could deliver an initial flow rate of 800 barrel a day. Given that one of the well was -- the first one flowed at 700, could you perhaps talk about what's behind the 800? And is it constrained by any chance? Was it because you're playing with different fluoride to see all the reservoir flow? That would be great to have a bit of more color.

[Magnus Nordin, executive]

Yes, certainly. No, I mean it is an extended well test. Wells will be put on stream. They will be shut in. They will be expanded. A check will be increased, the check will -- they will be checked back. It's all really a program to evaluate and to establish the, shall we say, the recoverable parameters of the -- with the oil in place. So that number is really chosen just to manage expectations as to what this could do for contributing to our production during the period of well testing.

It is neither to be construed as an absolute number or a guaranteed number either way. It's -- putting in perspective, what we could expect to see once we start producing here. But again, we should remember, it's not commercial production. It is test production, and the main purpose of that test production is to get data, not to get all for sale. We are happy that we'll be -- that we are allowed to actually sell the oil drilled in the test production phase. But it's an add-on. It's not the main purpose of the test.

[Operator]

There are no further questions at this time. I will hand the call back to you. I will [Technical Difficulty]

[Magnus Nordin, executive]

Thank you so much for listening and do stay-tuned. Thank you.

[Operator]

This concludes today's conference call. Thank you for participating. You may now disconnect. Speakers, please stand by.