Tethys Oil AB

STO:TETY

Earnings Call Transcript 2021-Q1

[Operator]

Welcome to the Tethys Oil Q1 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. Good morning, everyone, and welcome to a rather sunny and spring-like Stockholm, where we will share our thoughts on the first quarter of 2021 for Tethys. It's been rather a transformational quarter for us primarily from an operational point of view, in that we established ourselves as a full-fledged operator again, having really been a nonoperating company several years with the drilling of the Thameen-1 well in Block 49. And also, after firming up to 65 percentage points in Block 56, also on -- for Oman, we assumed the operatorship there in addition to Block 58, where we already have operatorship. So supported by our perfectly decent production from Blocks 3&4 to 11,585 barrels of oil per day, we are now branching in as an operating company in Oman. And so far, Block 49 turn out to be an operational success with an interesting gross response from the Hasirah Sandstone where we have an indication of 40 meters gross hydrocarbon column. A bit disappointing now, we didn't get any flows to surface or any flows to surface, and we are now analyzing what we have, but do stay tuned. Block 49 has more to give, and so does Thameen. We are very hopeful. Block 56, we are -- having assumed operatorship, we're now looking at the continued work program, and I'll give you some more details on that later on. 49, we finalized the farmout of 50 percentage points to EOG Resources of Houston, Texas. In effect, the farmout means that we'll have very nominal expenditure for the Thameen well. And of course, we are very grateful to have EOG as a partner in this promising and interesting block. And last but not least, we continue to distribute cash to shareholders, and the Board of Directors has proposed the AGM to be held next week to distribute SEK 2 of ordinary dividend and SEK 2 per share as redemption shares. Turning to the financial highlights. I don't think there are any major surprises here. Revenue and other income at $25.4 million, with an EBITDA at $12.3 million, moving back up from the lows of 2020. Operating results, positive. Free cash flow positive. And of course, it's all very much a function of the production and oil price. And oil prices came back from the low 40s to the mid- to high 40s during the first quarter. And of course, as you are all aware, the second quarter oil prices have continued to move up. And of course, we are looking at the prices way above $60 for our second quarter sales. OpEx per barrel came up a bit from $9.80 in the Q1 to $11.40, part seasonal, but I will leave it to Petter to give you much, much more flavor and detail on the OpEx number. So turning to, again, reiterate the point. We are a very shareholder-friendly company when it comes to distributions. And as the black line on this slide suggests, the accumulated amount of cash distributed to shareholders is now moving way above $100 million since we started dividends in 2015. And for the current year, we are doing SEK 2 plus SEK 2. This, of course, is underpinned by a strong balance sheet, but it all emanates from the production in Blocks 3&4 which -- where we have seen a return of production above 11,000 after the trough of the second quarter 2020, which then, of course, was impacted by the immediate responses to the then new COVID pandemic. And as, of course, you're all aware, the pandemic is still raging, although it seems to be coming under control in several parts of the world. We are, of course, hopeful that this road to normality will continue. We are still experiencing the OPEC+ production limitations. But as you see in Q1 2020 -- Q1 this year, Tethys was allowed a production well over 11,000 barrels of oil per day. We are, of course, grateful that. On that note, I would like to leave the floor to Petter to give you some more details on our finances.

[Petter Hjertstedt, Chief Financial Officer]

Thank you, Magnus. To start with, we can have a look at the achieved price in the quarter. In the first quarter, we had an achieved price per barrel of $46.7, up some 10% versus Q4, which was at $42. And the achieved price, I'd like to remind you, is based on the actual revenue from liftings in the quarter. So that's before any under- or overlift adjustment. And in the case of the first quarter, the March lifting -- as you know, we have monthly liftings. The March lifting slipped into April and did not get recognized in the quarter. So the $46.7, that reflects the liftings only from January and February. Had the March lifting been included, the achieved price would have been $2.70 higher, so at about $49.40. And as you know, there is a 2-month lag in the calculation of the price based on the OSP and as we'll see on the next slide, how that is expected to impact us going forward. Here you can see to the left on the graph, the official selling prices that we were to receive during the first quarter, starting at $43.80 going to $54.79, that $54.79 slipped out to the first quarter and into the second. Looking at the OSPs for the second quarter, you can see that the unweighted average is at about $63 per barrel. Unweighted that is because it's not weighted by the size of the respective lifting. Now if we are to include the March lifting in the second quarter, that average would be just around $60 per barrel for those 4 liftings, assuming that all those get recognized in the second quarter. And that's unweighted, of course. Moving on. Net entitlement. As you know, we have, since a few quarters back, had no or minimum cost pool, which has meant that we have fluctuations in the entitlement oil that we receive and that is ours to sell and forms the basis of our revenues. In the first quarter, we had net entitlement of 50%. That's 2 percentage points shy of the maximum of 52%. And as you know from previous quarters, any unutilized cost oil or entitlement allowance can be carried forward to later in the year. So in this case, we have 2 percentage points that can be carried forward to later in the year. During the first quarter, the cost pool was depleted. But -- having a cost pool at the end of last year. But as you know, unrecovered cost, that can be carried between the years. However, the unutilized allowance in that entitlement expires at the end of the year. But last year, we did achieve a full entitlement of 52%. And this year, well, it remains capped at 52% and is, of course, a function of expenditure, production and oil price. Moving on to over- and underlift. As you all recall, we nominate our liftings 2 to 3 months ahead of time, which means that the lifting volumes do not always match the produced volumes in a month, and that can result in an under- and overlift. This is a position that, over time, needs to be balanced and neutralized, which means we -- from time to time, it will take bigger or smaller liftings to try to balance that out. In this quarter, we have a underlift as a result of the March nomination being lifted in April as it is not uncommon. It's happened a bit in the past, and it's for logistical reasons and at the terminal. So this case, 189,000 barrels were lifted in April, and that means we have an underlift position at the end of the quarter of about 148,000 barrels. And this gets, of course, reflected in our under- and overlift adjustment, which if we move to the next slide, you can see the revenue and other income that is made up of the revenue recorded in the quarter from liftings but also that adjustment of value relating to the under- and overlift position. In this quarter, we have an increase of revenue and other income of 14%, up to $25.4 million, and that's the higher achieved oil price offsetting slightly lower entitlement compared to the fourth quarter but still shy of the levels we had in the first quarter a year ago. Now moving on -- down on -- in the P&L. We look at expenses. You can see that our operating expense went up 19% versus the previous quarter. And the OpEx per barrel is $11.4 per barrel compared to $9.8. That's a function of 2 things primarily. It's the increased production, putting online higher-cost wells that were shut-in during a period of last year, particularly the second half of last year. Those high-cost wells are being brought online, pushing up the OpEx per barrel. But also in the first quarter, the yearly benefits and the bonuses are paid out, meaning we always have a bit of a bump in absolute terms in the first quarter production expenses. Admin expenses, lower in the first quarter. Primarily, that shift is due to accruals at the year-end that were reversed. So our Q4 admin expense is slightly higher than would have been otherwise and Q1 slightly lower, it's about $0.4 million difference that should -- that could be moved between the quarters. Moving on to EBITDA. That's, of course, a function of revenue and other income and the OpEx, up 21% in the quarter compared to fourth quarter at $12.3 million. We have an EBITDA margin of 48%, up from 46%, and it's the increased revenue and other income offsetting the increased operating expenses. Moving on to investments. This was a peculiar quarter in that respect, very low combined investment of only $0.5 million, and that's mainly due to the negative or the -- sorry, the negative investments that is positive from Block 49. In Block 49, we received the initial consideration from EOG and also recorded the effects of that transaction, resulting in a positive number of $9.4 million, which is, of course, a negative in investment terms. On Blocks 3&4, we invested $4.9 million, slightly lower than we've had in previous quarters as activity is slow to pick up at the start of the year and in anticipation of increased activity later in the year. And on Block 56, we had $5 million, which is reflecting the consideration paid for the additional 45% interest in Block 56 as that transaction closed during the first quarter. Moving on then to free cash flow, $2.3 million. That's down from the previous quarter, but that is impacted by a negative working capital of $9 million. A big part of that is relating to the EOG transaction as we are yet to actually receive the final part of that consideration, but solid free cash flow underlying. Moving on to the cash reconciliation. You can see how that works out. Operating cash flow was $11.8 million. Small investments; free cash flow, $2.3 billion and $0.7 million in share buybacks at the very start of the first quarter, leaving us with a cash balance of $57 million at the end of the quarter, which brings us on to the balance sheet, which remains strong, solid and debt-free. You can see oil and gas properties decreased somewhat. That's the effect of 2 things primarily. It's the reflection of the EOG transaction as we reduce the carrying value for Block 49 but also the Blocks 3&4 with the DD&A rates or the DD&A, of course, being higher than the actual CapEx incurred in the quarter. Otherwise, it's very much -- the picture remains very much the same as in the past with a strong equity position on the balance sheet. And with that, I'd like to hand it back to Magnus to take us through the operations. Thank you.

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

Thank you very much, Petter. And no major surprises in the financials. So let's turn to the operational part, both where our production today comes from and of course, where we hope that future production will add on from our rather extensive license portfolio in Oman. What you're seeing in front of you is a map showing the Sultanate of Oman with all the licenses in the sultanate numbered. And there are 2 features that I think stick out here. One is the greenish area in the central Oman, which is the -- where most of the Omani oil production emanates from the PDO, Petroleum Development Oman, license area, which is a joint venture really between the Sultanate of Oman and Shell and Total primarily. And then you have the dark bluish areas surrounding the green areas, and that's Tethys Oil. And thus it's very clear from this picture, we have a very sizable acreage position in Oman and 18% of the total area translates maybe to even more of the -- what we believe to be the more prolific parts, from an oil perspective, of Oman. And over the last 4, 5 years while maintaining a strict fiscal discipline, maintaining our distribution to shareholders, we have also built a portfolio of license areas, where we've drawn on our expanding technical capability and understanding of Oman geology to get to the point where we are today. Just a very quick background. When oil was originally discovered in Oman in the mid-60s, it was done in the center of the sultanate in what is known as the Omani Salt Basin, which is basically, no pun intended, equivalent of the PDO concession, and received wisdom very -- solidified into saying that all oil in Oman is related to the salt basin and what else is, is not prolific. That included Blocks 3&4, which we became 50% owners of in 2007, 2008. And 3&4 was actually instrumental in disproving that received wisdom, in showing that there are separate petroleum systems on the flanks outside of the central basin. 3&4 were the ones important where Tethys was quite active in disproving the original thesis. But we believe the same can be the case for 58 and 56, which is also separate basins outside of the Omani Salt Basin. And also 49, which primarily covers an entirely different basin, the Rub' Al-Khali basin, which is a quite prolific in Saudi Arabia and Abu Dhabi. So behind this map of Tethys acreage is also a thought-out geological strategy where we want to replicate and build on what we've learned from 3&4 and implement that in 56, 58 and 49. And 49, of course, we drilled our first well with interesting results. 58, we signed in July and we are in the preseismic stage. And 56 is turning into what 3&4 ones was, a smorgasbord of opportunity. And I will now happily give you more detail on all of these projects. Put in perspective, we have the 3&4, 56, 58, 49. Tethys operates 49, 58 and 56, with respectively, 50%, 100% and 65% interest. And we are partners with a 30% interest in the CCED-operated producing Blocks 3&4. 3&4 is where we have most of our investments today. It's where all the production comes from. We had a limited work program and investments in the first quarter, but we expect that to continue to gear up. And as you can see, drilling activity and rig activity picked up during the quarter and will continue to pick up during the second quarter. It's very much an ongoing project, no major surprises, with production and reasonably stable production but also not without exploration opportunities. If you have followed us, you've seen this slide for several years. It becomes continually updated as we do more and more 3D seismic. A large array of leads and prospects and ongoing exploration. We had some success last year despite the limited activity during that year. And we are currently drilling the Safi exploration well. It's nearby. It's a near-field exploration close to the Shahd producing field. And we expect results over the next month or so. Additional wells will be drilled later in the year. And the inventory of leads is continually being upgraded to prospects as the seismic becomes interpreted. And as you see in the northern parts of Block 3, where we have the most recent seismic campaign, we have a number of leads now that we are also abutting into to -- turning to prospects. So while 3&4 remains extremely important to us for the production and cash flow, there is also ample exploration opportunity that will be assessed over the coming years. But our -- the blocks we operate ourselves, of course, will become more and more important to us, as we learn more about them and as we will get into investing more and having a more active work program. For the 49, a case in point. We signed the block in 2017. We interpreted seismic, did some seismic and focused on drilling of the Thameen well, which spudded on New Year's Eve in 2020. We drilled below 4,000 meters and on time and according to budget, no major surprises while drilling. And then we came into the main target, the Hasirah Sandstone, where we -- logs first indicated gas and oil and logs eventually indicated, when interpreted, hydrocarbon column of some 40 meters. We proceeded to evaluate several cores, we proceeded to collect data and also had to do a testing program. Unfortunately, no flows recorded to surface, but fluid samples were recovered, and all this is now being assembled and analyzed. It's still too early to do any final conclusions, both for the Thameen-1 well and the block. But a well where we had hopes, but maybe limited hopes of what you actually would encounter gave us a lot more data and a hydrocarbon column, certainly outside of our expectations. The block is upgraded for hydrocarbon potential. And we are eagerly awaiting the data, and we'll be able to give more guidance as to how we will proceed with the block. And of course, we are happy to have EOG as 50% partner and also happy to have the well almost 100% financed from the farmout transaction that we concluded during the quarter. All in all, 49 has proven to be quite interesting, both geologically and operationally, and we will spend a lot of time and effort and try to unlock the hydrocarbon potential that we certainly believe is there. 56 is a bit of a different story. It's adjacent to current production. It borders Block 6 and Block 55. There is a discovery, the Al Jumd discovery, on the block, which is on trend with and a look-alike play to the producing fields on Block 6, just bordering Block 56. And then there is a central area along a major fault line, which has a number of highly interesting and, in some cases, quite large leads. Let me quickly move to the next slide and just briefly want to highlight that the circle on top is the Al Jumd area, the Al Jumd discovery, which has flowed heaviest oil to surface. It's a complete look-alike of the producing fields in Block 6. There are a number of other structures in that area discovered by 3D seismic. We are currently interpreting that 3D seismic, and we are planning for a drilling campaign in the second half of the year to both further appraise the Al Jumd discovery and also further understand the additional prospects in that area. Then in the central part, and maybe in particular, in the south-central part, a number of leads. And here, they're all identified on 2D. And the first step will be to get 3D seismic over the most promising leads. And that's a program that's currently ongoing. And we hope to be able to start a 3D collection also later in the year. 56 holds lots of different opportunities that we will be able to tell you more about as the year progresses. 58 is in a somewhat similar situation. We moved back into the country, but we are outside of the Oman Salt Basin. We signed the block in July. We have 100%. And there are some 3D seismic done over the last 3, 4 years that we are currently reviewing. But if we turn to the next slide briefly again, you have producing assets, the green stuff in Block 6, bordering and adjacent to 58, and then you have a string of prospects. The ones that are on this map stand out, they are covered by seismic. They will need additional seismic to be drillable prospects. But they remain our main targets so far. But we've also seen additional leads, less well-defined, between those 2 leads that stand out. And they will be -- and we're trying to assess now how much of the 3D seismic campaign we need to make and where it will be carried out. And that's also something that we will update you on as the year progresses. But we are looking forward to, if I now quickly turn to summary and outlook, activity -- seismic and drilling activity in Block 56, seismic activity in 58, and of course, the valuation of Thameen and update on the continued program in 49. While we continue to enjoy the benefits of 3&4 production, be excited about the 3&4 exploration program, and of course, very excited about the increased oil price for the second quarter and hopeful that prices stabilized at these or possibly higher levels. So a good quarter behind us and high hopes for the rest of the year. Questions.

[Operator]

[Operator Instructions] Our first question comes from Teodor Nilsen from Sparebank 1 Markets.

[Teodor Sveen-Nilsen]

Three questions from me, if I may. I just wonder on -- Magnus, you mentioned, of course, the OPEC restrictions and that limit to ramp production slightly. Could you comment on the outlook for 2021? Of course, we see now that OPEC+ easing the limitations. So how should we see the production path through the rest of the year compared to Q1 production levels? That's my first question. Next question is on net entitlement, if you were able to provide guidance for that going forward. Will it stay at the current level? Or should we expect it to dip some going forward? Third question is on dividend policy. In early April, you announced a new dividend policy. Should we interpret that as a slightly more aggressive dividend policy with higher payout ratios going forward? Any comments around that would be useful.

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

Thank you, Teodor. Excellent questions, as always. The first one on production. We still refrain from guiding for the year. And we believe there is still, shall we say, macro uncertainty as to what production levels will be obtained. Production is, of course, a function both of what -- if the -- whatever limitations we may or may not see. I should point out there that OPEC is a signatory to the OPEC+ -- sorry, that Oman is a signatory to the OPEC+ agreement. And thus, the sultanate has limitations as to how much oil Oman is able to export and sell. But how that is divided between the various producers in Oman over time and from month-to-month has varied historically and could very well continue to vary going forward. And we are just hopeful that we will continue to -- or be allowed to continue to produce at a high level as we -- as possible, bearing in mind, of course, that we much rather sell 11,000 barrels of oil per day at $65 than 12,000 barrels of oil per day at $35. So I'm afraid we'll -- we are hopeful that we will have a good production for the continuation of the year, but we still refrain from given guidance. Maybe we'll be able to give you a better guidance for the full year as we -- as the year progresses. When it comes to entitlement, well, as Petter will soon be able to explain in much more detail than I can, but I mean, it's a function of getting our costs back. And as Petter mentioned, the cost pool is very limited at the moment, which means that we get most of our costs back as -- immediately, which, of course, is good for the bottom line. That means that we have higher profits, less cash flow. But what we actually foresee for the development of the cash cost pool going forward, Petter, you want to see if you can give a little bit of guidance to Teodor on that?

[Petter Hjertstedt, Chief Financial Officer]

Yes. Well -- thanks, Magnus. I mean as we know, net entitlement is a function of cost incurred, production and oil price and not all those factors are known to us or can even be planned. So it is always a challenge. Now at least given the situation we're in now where we have depleted the cost pool so there's no unrecovered costs and what we -- the cost allowance is used only by cost incurred. We indicated, I think, in the last call that 3&4 CapEx is expected to increase over the course of the year so be back-end loaded. That's probably a function of bringing the rigs on standby back. We have 2 rigs now as of the second quarter and expect a third rig later this year. So we do expect expenditure to go up, but we've seen oil prices come up as well. And so that -- which counteracts that effect. So no, it's difficult to give an explicit guidance as such. But I mean if you look at the kind of fluctuations we saw last year, I mean, it's -- that might give you an indication. I wouldn't expect any huge deviations from what we know today, but then there are some unknown factors on that -- in that. And I think it's worth remembering that, I mean, when you don't have a cost pool of unrecovered costs, a high net entitlement is not necessarily something that's desirable because it's -- the cost of portion is money in, money out. What we want to do is maximize the size of our profit oil, and that, we do by minimizing costs. So a low net entitlement as such in this position is actually a good thing because that increases our profit oil portion. But then, of course, if we do have long-term value-accretive investments, we should not refrain from doing those, but there's no reason to have high costs as that's cash flow neutral and reduces the profit oil portion. Then we had the last question on dividend policy. I think you have to see that dividend policy that --n as a more of a clarification of the way we have reasoned and will continue to reason around dividends and distribution. And that's very much that the ordinary dividend certainly underpinned by the cash flow from our producing assets. And our target operationally is to grow our production and grow the cash flows from that. And as that grows, we would hope to be able to grow the ordinary dividend at a pace that is sustainable. And any excess cash on top of that, that is not being used for our operations, that could be open for distribution. But this is a -- I mean this is a -- it's -- as we said, there are several factors coming into that. That's future commitments and investment need but also access to financing and how that impacts our need for liquidity in the balance sheet. I think it's very much in line with our thinking in the past and should not be seen as a -- any major change in our position when it comes to distribution, which we know -- which you know, I mean, has been quite generous. We distributed over $100 million the past few years. So it's certainly high on our priority list.

[Operator]

Our next question comes from Karl Fredrik from ABG.

[Karl Fredrik Schjøtt-Pedersen]

A question regarding the current oil price environment and your planning, looking somewhat further ahead than 2021, for the full year and also looking into 2022. Assuming oil prices couldn't stay at the current level, would you expect to see a higher spending than what you've guided -- what you have guided for the full year? And also looking into 2022, what would be kind of a fair assumption for Block 3&4 investments at that point in time? That's the first question. The second question relates to your balance sheet. What do you find to be -- or what metrics do you use now to assess the cash requirements on your balance sheet? Will it be fair to assume that at some point in time, you will draw down your cash position? Or is that something you find to be a competitive advantage in discussing with your subsuppliers, et cetera?

[Petter Hjertstedt, Chief Financial Officer]

Yes. I mean I think it's difficult to give a real long-term indication of spending. We know it's very much a function of external factors that are beyond our control. So we try to plan with an element of flexibility that I think we demonstrated last year in being able to cut back expenditure and both reduce cost and defer expenditure. Having said that, certainly, last year, there were plenty of projects we wanted to invest in. Those have been pushed forward and deferred into this year. And we are still, in the first half of this year, not at full operational level, not least when it comes to rigs. So I would say there's -- all else being equal, I think we would expect spending next year more in line with the spending we're looking at for the second half of this year. That's a good indication, although, I mean, it's not -- it's still a moving target. We have to see where production and oil prices at -- land. And also, there's always an element of success-based spending if we make discoveries that will require expenditure to develop. And equally, there's always a long list of prospects to drill for exploration. And this is a balance. So you can use that as an indication. It's certainly no guidance, but it's an indication. And sorry, what was your second question? It was which metrics? This with regard...

[Karl Fredrik Schjøtt-Pedersen]

Yes, exactly. So whether it's a competitive advantage and/or what you used to assess the required cash balance.

[Petter Hjertstedt, Chief Financial Officer]

Well, I think we all know the debt markets and even equity markets, to the extent they even exist for our industry and junior companies at the moment, but the debt market is fickle. The equity market even more so. That means if we are to be able to maintain our long-term plans, this is a long-cycle industry. There needs to be an element of planning of having cash and cash available. So that's certainly something we have to keep in mind. So it's balancing the long-term plans that we have with expected cash flows from -- with an element of caution. And to the extent there is financing available, and that's proven to be volatile and increasingly challenging for companies of our size in our industry. So yes, I think having cash on hand without saying which level, but having cash on hand certainly is a competitive advantage. Yes.

[Operator]

[Operator Instructions] Okay. There seems to be no further questions registered. So I'll hand over back to the speakers.

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

In that case, thank you very much for listening. Stay tuned. And if not before, we'll speak to you again in August. Thank you.

[Petter Hjertstedt, Chief Financial Officer]

Thank you, everyone.