Tethys Oil AB

STO:TETY

Earnings Call Transcript 2021-Q3

[Operator]

Ladies and gentlemen, welcome to the Tethys Oil Q3 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 good morning all. Welcome to the November 2021 earnings call with Tethys Oil, where we will discuss the third quarter 2021.And as you can see from our first slide here with our highlights, it's been rather a good quarter. Production hanging in well above 11,000 barrels of oil per day, with an oil price that has been climbing throughout the year. And for the third quarter, we achieved a sales price of $66.70. And as you know, prices have steadily climbed, so for the fourth quarter, we will certainly expect to have prices considerably higher than the $66 of the third quarter.But more importantly, maybe quarter 3 saw massive cash generation and with the $13 million worth of free cash from our assets. It's one of the stronger quarters we have seen in recent memory. And that has impacted our net cash position, which already this time of year, by the end of September, stands at close to $60 million, which will present our Board with an agreeable discussion on what to do with this cash as we move into next year. But that's, of course, something that we would be delighted to get back to you on -- in a couple of months' time.So maybe not surprisingly, we have the strongest quarter since the start of the pandemic, much of course to do with oil prices, but also with a robust strong assets in the bottom, Blocks 3&4, with good cost control and a stable and proficient production.On the exploration side, we've seen a lot of activity, in particular, on our exploration Blocks 56 and 58, where we are now moving up to see an interesting work program. In Block 56, we expect to start within the next couple of months a 3-well exploration and appraisal program on the Al Jumd trend, the northern part of the block, where we will target combined prospective resources of some 7 million barrels and this is in the smallest sliver of the bock -- will be much more detail later in the call on the exploration upside and the exploration plans for Block 56.We are downgrading the full year production a little bit. We are now looking at -- to coming in at some 11,100 barrels of oil per day, which is down a little bit from what we expected at our August call. Mainly what we are seeing is a backlog of workovers and a backlog of ongoing surface maintenance.As we move back into a normal operating environment, we would soon be back in full rotation on crews. As we've also been able to open up more wells for production, the need for workovers have become more obvious, and we have a backlog of renovating wells and as we open up more wells, also work these over. This is something we are confident will be rectified over time. And -- but for the fourth quarter, we will be a little bit weaker on production than we originally hoped for.Turning to production. As you can see, as we entered the pandemic, we were around -- above 13,000 barrels of oil per day. Then with the pandemic decking on, we dropped down to just below 11,000, stayed there for a couple of quarters, came back up above 11,000, and started the year on our way up towards 12,000.Then we had to go a little bit easier in the second quarter. And as the third quarter moved on and into the fourth quarter, we saw an increased need for workovers. We had some delays in going back to full rig capacity. We are now running at 3-rigs for the drilling and have fully employed workover rigs, but the fourth quarter will be a little bit weaker than expected. So stay tuned for our monthly updates and, of course, our guidance for next year as we move into 2022.Let's have a quick look at the oil price also. This is rather interesting slide that we see here, and that's how demand for oil has actually developed over the year 2000. And as you see, we started the Millennium at below 80 million barrels of oil consumption a day. And before the pandemic, we were up to close to 100 million barrels a day. This is, of course, quite a high number. And for the oil industry to sustain this when we are now roaring back at the speed we are, dropping down to 90, which actually what is not worse than dropping down to 2013 levels during the 2020 year. We came back to 96 million a day in 2021 and are currently looking at more than 100 million barrels, i.e., record oil demand after the pandemic.The main take here, I think, is that notwithstanding the need to move into other source of fuel than fossil fuels, the trend of increased use of oil, not necessarily other fossil fuels, but oil, is still unbroken. And with the underinvestment we have seen since the onset of 2020, we would expect the next year and couple of years to still see a need for a rather buoyant oil price to simply meet the demand that we have.And turning to the next slide, which is a little bit more detailed. We clearly see no downward pressure on oil price in 2021. The OPEC+ maintenance of production increases seems to be very well managed and quite predictable. And the uncertainties as we will move into next year, is partly over U.S. shale, where we have seen an admirable fiscal discipline from the U.S. shale companies, where cash flow is, I think, for the first time in the U.S. shale history, actually held higher than increased production, which has helped, of course, to stabilize the market. And then the internal discussion with Iran -- will Iranian production be allowed back and in that case, when and under what circumstances.So for 2022, we believe that we will have -- continue to have a strong and well-managed oil price. We would not expect any major surprises on the upside. If there would be any surprises that will primarily be on the downside. And given that we are actually below average storage and inventory at this time, we would be quite optimistic for a continued strong and buoyant oil price also for 2022.On that note, let us take a little bit of a look at our own oil price development, how it has developed over the year and taking into account also that we have a 2-month lag in our sales price. For that, I will turn to a detailed discussion from our CFO, Petter, who, I'm sure, will be able to explain the intricacies of our official selling price calculations. Petter, please.

[Petter Hjertstedt, Chief Financial Officer]

Thank you, Magnus. Yes, let's start the financial discussion with a look at the pricing that forms the basis of our income. The official selling price for the Omani blend, which is the crude quality that Tethys Oil produces, is set on -- through a mechanism of whereby there is a monthly average price based on the front month contract as traded on the DME Exchange in Dubai. So the fact that the so called spot contract over a course of a month forms the basis of the selling price 2 months thereafter, this should be familiar to most of you, but it's worth reminding.And as you can see in the graph, for instance, if we look at the average price for October, which was just above $81 per barrel, that forms the basis of the December official selling price. So any oil we sell in December will be priced on the basis of that. This effectively means we do have a 2-month lag in our selling prices versus the sort of market spot price that we see. So the current spot price we're seeing in November will form the basis for the Q1 -- for the January pricing in Q1 2022.And also here, you can see how the average OSP for the third quarter and the fourth quarter. And this is completely based on the average -- or sorry, the official selling price and average. And might not necessarily be reflected in the actual achieved price that Tethys receives, which we will look at in the -- on the next slide.So Tethys Oil, we sell our oil on a monthly basis. We have a monthly lifting at the export terminal just outside of Muscat. And for each lifting, we use the monthly official selling price. Of course, the volumes are nominated -- proposed 2 to 3 months ahead of time. We are not aware of the pricing as that's done, then the pricing is set thereafter. So there is no linkage between volume and pricing as such. But it's rather based on an expectation -- production in conjunction with trying to balance out the overlift/underlift balance, whereby we can only sell as much oil as we are entitled to. And we will get back to the question of entitlement later.But as you can see in the third quarter, our achieved price was $66.7 per barrel. Now this is a bit lower than the average OSP, as you saw on the previous slide, but that is down due to timing effect. Throughout this year there has been some logistical issues and congestion at the export terminal, which means that we haven't been able to actually physically lift the oil within the months it has been nominated, which means that it has slipped into the following months, but still retained the pricing from when it was nominated.So in Q3, for instance, we have, in our accounts, recorded a lifting for June, which normally would be part of Q2, July, August, which, of course, normally would be Q3, but the September lifting was listed early October and thus recognized in Q4. So our achieved price is slipping by about a month. So there's no real difference in pricing versus the average OSP. It's rather a question of slippage in time and a bit of waiting between the liftings.And as you can see, in the quarter, we sold 448,000 barrels, just a bit down versus Q2, but at a significantly higher price, obviously when it comes to revenues, which brings us to the next slide.So revenue and EBITDA, you can clearly see stepping up quarter-by-quarter since Q3 last year. This is very much driven, initially in part by production, but in recent quarters, particularly by the oil price, while maintaining cost discipline in OpEx. So we see a 13% increase in revenue and other income in Q3 versus Q2. And we see EBITDA going up by 14% to 16.5%. So a clear progression, very much driven by the flow-through of high oil prices.Which brings us to the next slide and our operating expenditures, which have been maintained at somewhat lower level than a few years back. We see a slight rise in this quarter from an exceptionally low level in Q2. So it's up by 9% sequentially and $10 per barrel -- just by $10 per barrel -- OpEx per barrel and admin costs are just above 2%, which is in line with the historical level in general. So this OpEx level -- maintaining this OpEx level is ensuring that the increased top line is flowing through down to the bottom line.Now on to the subject of net entitlement, which has been much discussed recently and just as a sort of extra clarification just to ensure that everyone understands the mechanics behind it, which is not always clear when looking at our financial accounts. Tethys Oil's production comes from Blocks 3&4, which is a production sharing contract, which essentially means we get paid -- we received a portion of the oil produced as a contractor. It's split into 2 components. We received cost oil to cover the costs incurred in production, and then we receive a portion of what remains, the profit oil, which is shared then with the government of Oman.What this means is, first, a portion of the production is set off as an allowance for cost oil. This is typically somewhere in the portion of 30% to 50%. In the case of 3 and 4, it is fixed at a level between that. And that is a maximum amount of production that can be set aside to cover costs in any given period. Anything that exceeds that cap is rolled forward and put into a cost pool. If the costs incurred are below that, well, then the lower amount is recovered.This means that the costs incurred in U.S. dollars is then converted to barrels of oil that we get to sell to cover that cost. That conversion is done at market price. What then remains is profit oil, and that is split between contractors and a government, where the government takes majority share.It's important to remember that the cost oil is 0 margin. While it makes up a big proportion of the oil we receive, it is purely to cover the costs incurred. There is no margin on it. The value creation lies in the profit share and maximizing that over time.So moving forward. The net entitlement that Tethys receives is the combination of cost oil and profit oil barrels. And as cost, either declined or declined as a relative portion of the total value of production, the total volume of oil that we received to sell may decline. And this has been the case in recent quarters, whereas we now are at 41% of production as our entitlement.However, this is in part due to the increased oil price. Given the costs incurred and the increased oil price, we need fewer barrels to recover that same cost. So the amount of barrels going into cost oil, while the value is intact, it becomes fewer. This means a higher proportion is available for profit oil, which is increasing with the oil price, as you can see in the graph to the right.So while it's not so much about volume, it's about value and this becomes most apparent in our free cash flow. So while that might seem counterintuitive that we received lower volumes and potentially, slightly lower revenues than in the past, we are now making more profit from those same barrels.In case in point, moving forward, if we look at the cash flow for the year, we can see that we started the year with $55 million in the bank, and we have had free cash flow of $20 million. We've distributed $15.5 million, and yet we end this quarter on $59.4 million in the bank. So strong cash flow from what has been a year with, what I would say, a decent, but also somewhat disappointing production and yet very strong cash generation, enough to cover our investments and the distribution.Moving on. One of the factors that can impact the cash flow between the quarters, just worth highlighting is working capital. This recent quarter, we had a positive working capital effect, mainly driven by the receipt of funds from the EOG farmout. But there were also some other counteracting factors such as some delays in the receipt of funds from liftings.As you can see, this can swing quite a lot from quarter-to-quarter, while it's good to have a look at the year-to-date in big picture.Which brings us to free cash flow in the quarter, $13.1 million, $20 million in the year, very strong cash generation throughout the year. And investments in the quarter, $9 million, we still have a full year CapEx outlook of $47 million that is adjusted for farmouts. And as we've said in the past, we do expect CapEx to be ramping up towards the end of the year, so we do expect higher CapEx in Q4 as a result.And on that note, we end the financial section with -- we have a very strong balance sheet of $59 million in cash. We have solid -- we have oil and gas properties of $200 million, and very solid, and even after the distribution of $15.5 million to our shareholders earlier this year.I hand it back to Magnus.

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

Thank you very much, Petter. And as you heard, we remain financially a very strong oil company.Turning to the operating part. Let's go straight to a map of Oman and showing where we operate and where we invest and where we also derive our oil sales from. So the Sultanate of Oman, at the tip of the Arabian Peninsula. We have been active in Oman since 2006, and we currently have shares in 5 different licenses with Blocks 3&4 are on the Eastern, in decent part of Oman being producing star performer, and this is where we get our revenue from. This is where we get our free cash from. This is where we have -- provides our ability to distribute cash to shareholders and also invest in projects to find more oil and increase production. We do this in Blocks 3&4, but we also do it now in Blocks 49, 54 -- 58, sorry, and 56.Oman has been very good to us, and hopefully, we have been very good to Oman. We are certainly not the only oil company active in Oman. We have some of the majors and some of the major national companies and also some of other smaller colleagues active in country. And all-in-all, we are seeing a renaissance for the Omani oil industry with the return of several of the majors that were a bit reluctant in -- and actually creating opportunity for us to enter.Turning to the next slide, little bit of details. 3&4, we have a 30% stake. Originally, we had 50%. We farmed out to Mitsui of Japan in 2010-2011, in effect, de-risking the entire appraisal and development phase of the known fields, Blocks 3&4.Block 49, we signed that block 100% in 2017. We farmed out to EOG of Houston, a -- really an expert in tight reservoirs and unconventional production. In effect, we de-risked the first exploration phase that way by EOG offering to pay for the first well that we drilled in Block 4.56, we actually farmed into an existing block, and we completed our farming campaign of 56 earlier this year when we took up operatorship from Medco. We now hold 65% of Block 56 and are about to start an active and interesting exploration appraisal program for the upcoming year.Whereas, Block 58 is our block for 100%. We signed it last summer. We've done all the preliminary work. We are quite encouraged about what we've seen. And it's -- we will start more seismic and then move on to drilling wells. At the moment, we have 100%. We are quite happy with having 100%. We will keep 100% through the seismic campaign. And then we'll see whether we will try to farm that out and get some interested partners in or if we will continue going at it alone.Blocks 3&4 remain our source of production and cash flow. The 2021 work program has been somewhat curtailed by the uncertainty regarding what would happen to oil prices in 2021, what would happen to our ability to produce in 2021. And of course, the general picture, what would happen to the world in 2021.As we approach the end of 2021, we can see that we have maintained cost control. We are a little bit underinvested when it comes to the production. And we would expect for next year to see an increase in capital expenditure on the block, primarily in the development side, but also as we continue to explore for more oil in Blocks 3&4.As you can see from this now rather familiar slide. The main play fairway is the here -- is the blue -- light blue area, where we have 3D seismic. We are adding 3D seismic in -- or we should say, interpreting 3D seismic in the dark blue area with aerial shots more recently.The Farha South fields and the Shahd fields are the main producing fields, both approaching some maturity. They are backed up by more recent discoveries, the Erfan field, for example. And some scattered exploration over the last 3 years.Exploration record this year is mixed. We found some oil, but not as much as we were used to from the past. And on that note, we have seen exploration efforts step up. We will do more seismic. And in particular, we expect to see continued exploratory drilling. Both in the near field area between, say, the Saiwan East field, the Erfan field and the Shahd field, but also in the far field area, where we would be targeting some slightly larger structures in the South within the [ large 2 ] area, but also those to the East and to the West.As we learn more about the potential of Block 3 & 4, we can still conclude that virtually every single well we have drilled has encountered some sort of oil. So a lot of oil has been generated here. And sometimes, we have reservoir problems, sometimes we have excellent reservoirs, sometimes there is a trap problem, sometimes, we have excellent traps. But the blocks are still very much aligned, not only from a cash-generating perspective, but also from an upside perspective.Turning to Block 49. We drilled well here in first quarter, encountered large oil column, got no flows and concluded that there was oil there, but the reservoir is quite, quite tight. We are lucky to have one of the world's best tight reservoir companies as partners, EOG Resources. And over the last 3, 4 months, we have talks both with EOG, with our respective technical departments and also with the ministry in Oman for the best way to take the Block 49 forward.We know there is oil there. We know there is reservoir. We also know that the reservoir is quite tight. We would expect to be able to present a clearer picture for what we're going to do with Block 49 in the near term. But we remain quite optimistic that 49 has created value and will continue to create value for us.Turning to Block 56. We have more activity upcoming. We will be focused primarily at the Al Jumd area where we are going to do 3 wells with a combination of development appraisal well and exploration wells. The Al Jumd trend has more than 10 leads and prospects and initially, we are targeting some 7 million barrels of expected resources. And in parallel with the drilling campaign in the Al Jumd area, we are also looking to do seismic in the central parts of Block 56.This will be a lot clearer at this picture. Block 56 covers nearly 3 potential play areas. We have Al Jumd where we have ample 3D seismic, where we have discoveries and where we are operating an extension of a producing field just to the left of this slide to the northwest of the Al Jumd area, the Karim, small fields.So the drilling program we are putting in place for the next couple of months is to appraise the discoveries made within the Al Jumd trend in the block and also drill at least one additional prospect within that trend to get a better picture of what is the -- actually the full potential. The target of the program is to prove the commercial viability of the Al Jumd trend in Block 56, get long term production tests and eventually get sustainable production from the -- from the prospects and the potential fields in that area. That's our first and primary target. And of course, we would be delighted to have a second production stream to complement what we see from Blocks 3&4.More exciting on the long term value creation is what goes on in the Central area. As you can see, we have a number of interesting leads generated from our interpretation of the 2D seismic. And we are focusing on doing an extensive 3D campaign in the South Central part of the block. We have a central fault running virtually in the middle of the block, which has created a lot of the interesting traps, and we believe it's sourced from a tertiary basin that is to the east of the central fault with ample migration routes from that side.We hope to prove up a number of sizable drillable prospects through this seismic campaign. And as Al Jumd hopefully moves into a production stage, we'd move the Central area into a drillable prospect stage. Probably the most exciting area that we are working with for the upcoming, so to say, 6 months probably portfolio.Turn to Block 58, it's a slightly different story. No oil -- known oil discoveries here but known petroleum systems that work in other places in Oman. And we are quite encouraged with what we see here, but the main target here is to get additional seismics. We turn quickly to the next. Again, leads identified. They stand up to the scrutiny we've conducted so far. But before we drill, we would like to have some 3D seismic to make sure that we drill in the right spot, and that the trap integrity is confirmed.We would not expect any wells here until at the earliest -- the latter part of Block 58, but we would hope to have confirmation that the leads hold some drillable prospects within the next 6 months. So the Omani portfolio is evolving and increasing speed on the exploration side, supported by strong cash flows from Blocks 3&4.So turning to the final slide. I'd like to remind you that we stand very strong financially. We generate -- we regenerated a lot of cash in Q3. With increasing oil prices we would expect to have a strong fourth quarter. Al Jumd, you should see some exciting drilling coming up, and 58, some interesting seismic.So on that note, we will shortly turn to questions. And I do hope that you will follow us closely as we move into one of the more work program quarters, fourth and first quarter of 2021, while we maintain a strong cash flow from Blocks 3&4, but also, of course, not without exploration upside.On that note, may I open the floor for questions, please.

[Operator]

[Operator Instructions] We already have the question from Stephane Foucaud from Auctus Advisors.

[Stephane Guy Patrick Foucaud, Head of Research]

I've got some questions around production at Block 3&4. And I was wondering, assuming that there would be no OPEC restriction, would the production in Q3 and Q4 be where it stands? In other words, I was trying to understand what's the -- what has most impact on the production level, whether it was the technical backlog of workover or whether there was still limitation associated to OPEC. And as we move to next year, on the same sort of question, assuming there would be no restriction on OPEC, where could you potentially see Blocks 3&4 returning to? And how should we think about CapEx return to that level? Do you see -- for instance, is 13,000 still something that you could see the field production going back to without OPEC restriction.

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

Okay. Thank you, Stephane. Let's say that as the OPEC+ ceiling moves up, we would -- I think it's fair to say we would not really expect to be too impacted by OPEC restrictions going forward. That said, the work program for 2021 was based on the potential of being restricted, and therefore, of course, we haven't really planned maybe to be able to produce all out. And what we have noticed also is as we put back wells on production, they need a bit of work to perform as well as they did when they were shut in, thus the increase for additional workovers and the backlog we see on both development drilling and on workovers, also based on the fact that it took slightly longer to get 3 rigs up and running than originally planned once the decision was taken to bring them on stream.So I mean, it's all connected. The work program is based on expected production. If an expected production turns out to actually be higher than the work program this was designed for, ramping up takes a bit of time. And as we move into the fourth quarter, we are seeing the effects of -- those effects. Going forward, we will certainly be in a position to offer more guidance in the next couple of months as we also establish the budget for next year. But I can certainly say that it would be our intention and the operator's intention and the JV's intention to go for a ramped up production for next year. And as we get more data on what will be available and also on what work program will look like, we'll be able to get back to you and then offer more guidance then.

[Operator]

We have another question from ABG.

[Karl Fredrik Schjøtt-Pedersen]

This is Karl Fredrik Schjøtt-Pedersen from ABG Sundal Collier. I have a question regarding the drilling of Block 56. In terms of results, what are you looking for in order to classify this as a successful activity? And what would be the time line of announcements to the market?

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

Okay. If -- I mean, what -- the most interesting part of the first well, the Al Jumd appraisal, would be a horizontal section and we would certainly like to see a sustained flow of, should we say, sufficient flow to go for a long term production and eventually and sustained production. We will be able to get back with more details as we approach drilling of the well. And we are currently negotiating the rig. A rig has been identified. The rig is currently actually drilling for our partner EOG in their Block 36. We expect it to be released over the next couple of weeks, and we would expect to have more information on both the schedule and the drilling program during the course of December.We should certainly be -- barring any unforeseen delays or any drilling problems, we will certainly be in a position to both guide as the work starts, but in particular, as we approach the end of the first quarter next year, we should be in a position to have a much clearer view of what we expect or will expect from Al Jumd over the next couple of years. So now the trend line really is more info as we move into the drilling sequence, and we should be in a position to evaluate the wells well before the end of the first quarter.

[Operator]

[Operator Instructions] We have another question from Stephane Foucaud.

[Stephane Guy Patrick Foucaud, Head of Research]

So back on this production, more for modeling purposes and CapEx. As we look forward, what do you think would be the level of CapEx required on Block 3&4 to maintain production flat? Is the current 32 or something the right number or would it be a bit more?

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

Yes. I think, Stephane, I'd like to defer that question until we present the CapEx spending for next year. And so we should be in a position to discuss that in much more detail for our February call when guidance and budget for next year have been established. We expect that -- at latter stage, especially since we're going to operate the block.

[Operator]

[Operator Instructions] So it seems that we have no further questions.

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

In that case, thank you for listening and tune in again in 3 months' time. Thank you.

[Operator]

Ladies and gentlemen, this now concludes our conference call. Thank you all for participating. You may now disconnect.