Maha Energy AB
STO:MAHA A
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Maha Energy AB
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[Foreign Language] Jonas, Andrés, good afternoon. How are you?
Good morning from Calgary.
Excellent. Jonas and Andrés, please take it away. The floor is yours.
Thank you, Kaarlo, and thanks for the introduction, Kaarlo. So welcome to another quarterly report webcast from us here at Maha. Today, we come to you from Calgary. And we'll spend some time today. It will be quite a detailed presentation because we have a lot to go through, so fasten your seat belts. We have lots going on in Maha. It's been a really tough quarter for us. Having said that, we've had some very positive news come at us, particularly here at the beginning of this year. As normal, if you have any questions for this webcast, please post them in the YouTube field or you can also e-mail them to Victoria at mahaenergy.ca. So before I hand over to Andrés to go through the figures, I just want to make a few comments. Like I said, it's been a very tough quarter. Q4 was a very tough quarter for us. If you look at oil price, oil price was very depressed in October and November, started to recover sort of towards the end of December. It coincidentally followed our production. Our production was very depressed during October and November. And for many reasons, which we'll get into here later, we recovered towards the end of the year. Having said that, we've had a record year in terms of production in Maha's short history. We produce, on average, just over 3,300 BOEs per day. And we have actually completed our, what I call our 3-legged stool, for our strategy of building the company, and we'll touch upon that later as well. We've laid a first-class foundation with the acquisitions of Mafraq in Oman and the Illinois Basin in the United States. And we have fantastic reserve numbers. Our 2P reserve replacement ratios well over 350% for this year. Our proven reserves are up 180% year-on-year and our 2P are up 14%. And we've actually also added about 22 million barrels in contingent resources in Oman. But more on that later, so I'll hand over to my colleague at the office in Calgary, Andrés Modarelli, and I think we should be on Slide 4.
That's right. Thanks, Jonas, and thank you, Kaarlo, for having us today. Happy Friday, everyone, and welcome to another quarterly webcast. I'm pleased to present today our Q4 results. So going to Slide 4 and jumping right to it. Here, we present certain financial highlights for the most recent quarters, expressed in thousands of U.S. dollars and for unaudited figures. So as you can see, revenues were $8.7 million. That's down 23% versus the most recent quarter and 37% versus the comparable quarter a year ago. A positive EBITDA of $2.7 million was down about 50% versus the most recent quarter and 67% versus the comparable quarter a year ago. And as Jonas was referring at the beginning, this was a tougher quarter. And mainly from lower produced volumes during the quarter, that were down 14% versus the comparable period a year ago and 24% versus the most recent quarter. Year-over-year production. On a full year basis, production was up over 8%. Combined with this was the lower realized selling prices of $38.8 for the quarter, and that's down 28% from the comparable quarter a year ago, and up slightly versus the most recent quarter. This, in turn, affected our operating netbacks, which is the return on every barrel sold after deducting royalties and operating costs, which were $17.5 per BOE, and that's down 50% from the comparable period a year ago and 17% from the most recent quarter. This quarter's result was a loss of $15 million -- $15.7 million. And this was in relation to the LAK impairment, which significantly impacted the results for the quarter. We had previously announced this, and it's something that we've been seeing in a lot of oil and gas companies during 2020 as a result of the lower oil price futures. And in our case, at year-end, that made the recoverable amount of the asset lower than its net book value and therefore, needed adjustment. So this impairment was strictly pricing-related. And although prices are now improving, the recoverable amount measurement needs to take place as at December 31. But it could be reversed down the road as prices continue to improve. The reserves remain accounted for. And the company still intends to develop these assets when the price is supported. So if we were to exclude the effect of the impairment, we would have ended at a profit of $5.3 million for the quarter, which would have been quite good. And -- but that resulted in an EPS of negative $0.15 for the quarter or positive $0.05 if we were to exclude this impairment charge. And on a yearly basis, it would have been a negative $0.10 per share or $0.11 if we excluded the impairment charge. So if we go to the next slide, Slide #5. Here we highlight certain balance sheet items. And you can see our net cash and our working capital have come down in the quarter, following high capital activity during the latter part of 2020 from well operations, facility upgrades and also the acquisitions of Mafraq and the Illinois Basin earlier in the year. And in spite of the impairment, the total assets increased this quarter. We have our bond outstanding with the next interest payment date on May 29, and there is no dividend declaration expected. So we go to Slide #6, where we show some quarterly production charts and we can see how the production has -- have been increasing in the recent quarters and the past quarters until Q4 where some operational issues affected production, and which we will go through in the -- on the operational slides. But basically, this lower production in Q4 and prices remaining lower had the impact in this quarter. As you can see, though, towards the middle of Q4, the pricing recovery began and we're now in the 60s. So with these operational issues mostly behind us now and the pricing recovery underway, that should lead to a better Q1. Next, Slide #7. We present some key metrics that we like to follow. Our netback of $17.60 per BOE remains healthy. It was affected this quarter by higher OpEx, as you can see on the lower left chart, and these mainly related to onetime items for well reentries, water handling and gas take-or-pay penalties that were paid during the quarter. Also versus the quarter a year ago, this quarter includes the operating cost from the Illinois Basin. Lastly, we keep track -- close track of our cash balances. And in Q4, it's lower, as you can see. And as we referred to earlier, we did have a very active Q4 with drilling operations and the Mafraq acquisition and also the interest payment on the bond. So next on Slide 8. Another metric we follow closely is our net result. And as referred to at the beginning, this was impacted -- significantly impacted by the impairment charge, which got partially offset by deferred tax asset recovery of $5.8 million that was recorded, both of these noncash, but if we would exclude the impact of the impairment, this quarter would have been 5.3% in the black, positive, or 10.7% for the full year. And that would have been our 13th consecutive profitable quarter. There were some also -- there were also some onetime OpEx charges, and that I referred to before. And also in terms of G&A, we had our uplisting costs impacting this quarter. As you recall, we uplisted towards the end of December. So with that, I will hand it back to Jonas.
Thanks, Andrés. Obviously, a lot of things to unpack in that quarter. So let me just start. If we go to the next slide, which I believe is -- what is that, Slide 9. I wanted to go through some of the key events of the year before we look at the future. And of course, if you recall, if we go back to the beginning of 2020, this time last year, we were just starting to see COVID unfold across the world. And like everyone else, back in March and April we decided to postpone some of our key capital activities, which then had a knock-on effect on our production numbers for the year. So the key impacts for us for COVID-19 was, obviously, the oil price for the year. I think it ended up at just under $42 per barrel on average for Brent, but it also impacted us in our drilling schedule. We were actually ready to start drilling in March, April of last year the Tie-2 and Tie-3 development wells. We decided to postpone that with most other companies as the world went into a lockdown. And we resumed those activities towards the end of Q3. So one of the first things that happened for us in -- at the end of Q3 and beginning of Q4 was that the GTE-4 well, which had been free flowing up until about March, April, we discovered that the Agua Grande, the shallow zone was not contributing to the pumping operations there. That well went through a number of very costly and time-consuming workovers. But eventually, we restored production from GTE-4. But pretty much since about March, April of 2020, GTE-4 was really a real problem child for us in the Tie Field. I'm pleased to say that GTE-4 has now been restored, and both zones are contributing to production there. The other thing that happened in these sort of unplanned unrelated events was that Tie-1, again, Agua Grande shallow zone stopped free flowing from the Tie-1 well. And that required some workover and interventions, and we eventually had to put a pump on the short string. So Tie-1 has also been restored now. But these events accumulated in production loss for the quarter. If we move over to Tartaruga. Tartaruga, the testing of the Maha-1 well was also postponed at the beginning of the year. That operation resumed in Q3, Q4. And when we were testing that, it impacted the battery at Tartaruga. We were unable to flow both wells at the same time. So that impacted production. That's why you will see for Tartaruga, production has decreased for the quarter after recording a record production quarter the prior quarter. Last but not least, of course, the Tie-2 and Tie-3 wells were delayed and we suffered significant problems on the Tie-2 well, which resulted in unwanted expenditures and the loss of 2 bottom hole assemblies due to stuck pipe, and also delayed production by about just over 32 days. So all those events accumulated in loss of production for the quarter and indeed the year, and also unwanted expenditures. We are confident that those events are now behind us. As we exited December, production was restored, pending the hookup of the GTE-4 pump -- permanent pump system on GTE-4, which will add another 500 or thereabout barrels of oil to the Tie Field. Tartaruga is still being addressed. We are hooking up the Maha-1 well to the permanent production facilities there. That has taken some time because of some long lead items that were required. On a more positive note, during the year, on 2020, we purchased 2 assets, 1 in Illinois Basin in the United States. And I'm pleased to report that, that's doing extremely well considering the circumstances. We signed Mafraq, which is a huge addition to the company, and we'll go through that in a minute. We also uplisted to NASDAQ main board in Stockholm. That was the result of almost 18 months of hard work by a lot of people to get us over the goal line there. So we are now traded on the main board in Stockholm. And I mentioned this at the offset, we have a great 2P reserve replacement, which means that we are replacing almost 4x more oil than what we produced during the year, and that's a measure of how the company is growing. So those were the key events. We'll jump into -- if we go to the next slide, I just want to touch really quickly. This is Slide 10, Jonathan, if you have it up. I want to touch on the Maha strategy, which is now -- is completed. If you recall, we have 2 main leg -- 2 main lines of strategy. We have the 50-40-10, which is this pyramid where we want to assign all our assets to different risk categories. So we are not an exploration company. We are an exploitation company. Therefore, we want to base most of our revenue on low-risk oil-producing assets. Our growth comes through the sort of appraisal development fields that we've acquired. And then we do have a small amount of near field exploration. So the Illinois Basin and the Tie Field, they fall smack right in the middle of the very low-risk well producing foundation of the company. Mafraq and Tartaruga fall into the appraisal/development phase. So 90% of our assets are in those categories. We have finished our 3-legged stool, as I call it. That's our diversification process. We are now active in the United States, Brazil and in Oman, which gives us a safeguard against political risk and financial risk across the globe. So if we go to the next slide, Slide 11. I'll give you a quick operational update on the Tie Field. COVID-19 seems to have sort of gone into a flat phase in the Bahia Province. We delivered just over 190,000 barrels from the Tie Field. Gas was somewhat down as well at 115 million cubic feet. We talked about the GTE-4 workover. Tie-1 AG was based on pump and is now producing. We had 2 stuck pipe incidents. We had some delay on that, and the rig was moved to Tie-3, where it's currently drilling. The Tie-2 tested just over 2,000 BOEs per day, mainly oil. This was well above our expectations. The well came in, I think, 2 or 3 meters higher than expected. And if you're a geologist, you will know that, that's a good thing on that oilfield. The higher you are on the structure, the better it is. And also, we saw higher-than-anticipated reservoir pressure at this location. This was in the southwest of the field. But probably the biggest and the best news that came out of Tie for the year is the incredible movement of proven reserves. We are now in a mature -- entering to a mature stage of this field where exploitation and/or, let's call it, harvest of the oil has begun. And our reserve auditors, Chapman Engineering (sic) [ Chapman Petroleum Engineering ] here in Calgary, agreed with us that a lot of the probable reserves are now moved to the proven category, which is a probability of 90% or more that those reserves will be recovered. We were very, very pleased with that movement of reserves, and it just signals again the strength of the company in terms of a foundational state. If we go to the next slide, let's talk a little bit about Tartaruga. Tartaruga delivered slightly less oil this quarter, 26,000 barrels. We completed the Maha-1 well testing operations. And the test results were somewhat different than what we had anticipated. We had a slightly tighter sandstones in the Penedo at this location. And the location of this well was in what we call the Northern Fault Compartment. And the idea of this well was to appraise the Northern part of the structure. The good news are that the sands are continuous. We track all 27 sands across the Northern Fault Compartment. And indeed, we did test some noncommercial quantities of oil in the deeper sands. They were also very, very tight. Probably the most surprising outcome was that we have produced quite a lot of water out of the Penedo-1, which is an enigma to us. We don't know where that water is coming from. And therefore, we have hooked that up to the main battery to see if we can dewater that zone. We're still getting amounts of oil with that water. And that's just not possible if it's a water-wet reservoir. So that remains to be seen. But I must underscore that this does not at all impact the overall development of the southern part of this block. That's why you see on our reserve replacement, this well has actually -- because we can prove continuity of these sands, it has actually moved some of the probable reserves into proven and this is all allocated in the Southern Fault Compartment. And we are working towards a development plan for the Southern Fault Compartment, which will involve some horizontal drilling there in the future. So a mixed bag of results from -- on Tartaruga. Last note on that is the Petrobras divestment process. We did participate in the divestment of Petrobras being our 25% partner there. They were looking to sell their 25%, they went through an open tender. And as far as I understand, we were unsuccessful in that bid. But the bid is not yet finished, so we'll see how that progresses. Let's go to the next slide. I'll give you a quick operational update on LAK Ranch in the Illinois Basin. LAK Ranch, as you know, we shut in at the end of March. That is an oil price play. We'll see when oil prices recover, we'll see if we'll start that back up. At the end of the first quarter of last year, we purchased operating working interest in the Illinois Basin. We have roughly about 95% working interest there. It produces from 3 separate reservoirs, stacked reservoirs. It's a very, very low-risk play. Thousands of wells in the area. So we have great stratigraphic control across that area. So really, it is more or less of a manufacturing process of drilling wells. I think we have well over 100 drilling locations there. Having said that, these wells are -- the ultimate recovery of these wells range between 50,000 and 75,000 barrels in total. So again, they are somewhat oil price-dependent on how you develop and in the manner in which you develop, and scheduling-wise. They are very low risk. We know that the oil is there, and they will produce. You put a well down there, it will produce anywhere between 50 to 75 barrels a day at initial production. During the year, we completed 3 wells. One, we drilled ourselves. One was a drilled but uncompleted well that we completed. And we are also a partner with a joint venture partner who drilled a well there. We have about just under 50% of that well. The average for the quarter was 148 barrels per day. So if you look at it since we acquired this asset, production has been very stable there, about 150 barrels per day. But towards the end of the year, after the additions of these wells, our exit rate was 270 barrels per day. And we actually peaked over 300 barrels a day by these well additions. So we're very pleased with that, and further work will occur there as well. You can see from the reserves, the reserves stayed somewhat constant through that period. And again, it just underscores the quality of those assets. And we picked them up at a song (sic) [ for a song ] because of the COVID crisis that was unfolding at the time. I would be remiss if I didn't spend some time on Mafraq or Block 70 in Oman. We picked this up at the end of 2020 in October. This is a process that we started back in February of 2019. It was a public tender for an exploration block. And as you can see on the right of Slide 14, you can see that the block is located pretty much smack in the middle of Oman, just about 5-hour drive south of Muscat, the capital. We are surrounded by good neighbors. If we look at the next slide, you can see, which is an enlargement of the previous slide, we are right in the middle of what's known as the Ghaba salt basin, which is the main basin in Oman. We have Tethys Oil to the east, their discoveries are just to the east. And to the west of us, we have Shell and PDO's long time producing assets. Qarn Alam, [ Sirol ] are just a few of those fields that have been producing. Block 70 is a relatively small block in terms of size-wise in Oman. And it contains the discovered and delineated and tested heavy oil field called the Mafraq oilfield. This field was discovered by PDO or Shell back in the late '80s, and was then delineated through the '90s. And a preliminary development plan was put together in the 2000s. And work was halted in 2008 after the financial crash and oil price crash of 2008, after which this field was given back to the government and the government then provided this -- the field on a bid basis. We're very fortunate to have picked this up. We have a lot of good information on this field. A total of 4 wells have been drilled on the structure itself, 2 horizontals and 2 vertical wells. And all the -- sorry, 2 out of those 4 wells have produced oil. 1 well, which was a horizontal Mafraq-5, produced over 15,000 barrels over a 22-day period when they put it on a long-term test back in, I believe, it was 2006.In terms of -- so the plan here is to put this field on production. It contains anywhere between 180 million and 280 million barrels of oil in place. We estimate we can recover about 9% with the primary recovery methods. And so the race is really on there to develop this field. It is heavy oil and quite viscous, but it is also very shallow. So its development costs are likely to be manageable. It's only about 500 meters deep below the surface, so. And again, this is nothing unusual for Oman. Oman has lots of heavy oil that they produce on a continuous basis there. So we're very excited about Mafraq. It is primarily a development block, although it does have some exploration potential on it as well. So lots of great things happening in that part of the world. So that concludes my presentation. Before we go to questions, I just want to remind everybody on some upcoming events on the next slide. Slide 16. We have -- we are presenting at an Investor Day at ABG Sundal Collier on 9th of March. We then have the Pareto Independents Conference that we also participate on. These will be streamed, I believe, on the web. So you can surf and take a look at those events. We produce our annual report towards the end of April. And our first quarterly report for 2021 will be published on the 26th of May. And then we have our Annual General Meeting very shortly thereafter, at the end of May. So that concludes the presentation. Kaarlo, it's been a long one. We had a lot of things to unpack. And we can go to questions.
Yes. Excellent. Interesting. Well, there are a number of questions coming in here regarding the production. But can I just say that am I right in understanding that your main stop in production came during the trough of the oil price. Is that correct?
That's correct. Yes. We started suffering quite badly September, October, November. And we returned to sort of pre -- and actually higher production numbers at the second half of December.
So it would be fair to say that comparables from this year's trough -- sorry, last year's trough to 2021 will be quite positive?
Well, you can look at it that way. Of course, these events were unplanned. They were unfortunate for us, and they consumed a lot of our resources. But I guess if you want to lose production -- or defer production, I should say, not lose. We deferred this production. You want to do it when oil prices are low. And that -- but let me assure you that was not by design from our side.
No, that's -- I think we all understand that. I have some question here. In the 2025 year guide, you were referring to GTE-3 to give you 100 -- 1,166 barrels. And today, there is nothing in the report about this well. Is there any status? And I can just tell you that there's a lot of questions regarding TE -- sorry, GTE-3.
GTE-e is one of the older wells on the block on that field. It was drilled, I believe, back in 2012. It's also drilled in a -- on a flank position of the field. It is still producing. I don't have the exact oil-producing volumes in front of me here, but it is still producing. And it's one of our core producing wells. That has not given -- knock on wood -- has not given us any trouble.
Well, thank you for that. And there is a general question here about the production here. Could you give us some sort of feel on where you are in general? And is there a possibility to have a higher plateau on Tie than the 5,000 mentioned?
Well, the current production, we're very stable. We've been stable since the end of the year. We are missing roughly 500 barrels a day from GTE-4, which is due to a surface pump that needs to be installed. That was already ordered back in, I think it was March or April of last year. Last I heard, that was due to come on here pretty much any day. And then we're waiting on additional production from Tie-3, which is currently being drilled. And once we get the next well Tie-4 on production, we will have more than sufficient spare capacity to address any unplanned events like we've seen in 2020. So we'll have great -- lots of spare capacity. Now with respect to increasing above the plateau at the Tie Field, I don't want to say anything on that. We have -- currently, we have 4,800 barrels or thereabout of take-off agreements. Right now, we are not able to provide the full 4,800 barrels, but that will change as soon as we get Tie-3 and GTE-4 back on production. Can we increase it? Well, the plant can certainly handle more. We have storage capacity of about just over 6,500 barrels. But until we get, obviously, the production up to the plateau that we're striving for on a regular basis, and a continuous basis, I should say. And at that point, I think we can start to look at -- if there's a possibility to increase offtake. I don't want to say if that's possible or not today, but let's get there first.
And another question here is also about production guidance here for 2021. How much of this do you expect the Tie Field to contribute? And I believe that the guidance would be between 4,000 and 5,000 barrels a day?
Yes. So the Tie Field, obviously, is our core asset. It will contribute the majority of our production for 2021.
And I got 1 question on the fly here regarding Tie-3. It says that it's supposed to be ready in February according to the report. Will it?
Most likely not. We've had some operational issues there as well. We've had quite a lot of downtime on the drilling rig because of repair work requiring on the derrick. So I don't think that we will be ready by the end of February. In fact, I know we will not be ready at the end of February.
And another question here on the fly and it's referring to Petrobras here. And it's not clear that you are out of the bidding. You haven't seen anything? Or could you just clarify what the situation is there with Petrobras and Tartaruga?
Yes. We have been notified by Petrobras that we were not successful in the bid, and that there are 2 other bidders that they are talking to. Now we know from Petrobras's previous bid rounds that sometimes what happens is that when they select a winning bid, that bidder, for whatever reason, negotiations fail. And then they come back to the next lowest bidder. So -- but we've been informed by Petrobras that we were not successful in that bid round.
And I have a question referring to the proven reserves, because they have increased tremendously here. And the question is, I'll just read it through here, how come the company doesn't produce and sell more than you already do with -- in connection with the proven reserves?
Yes. It's -- that's a good question. But we are limited to handling capacities and we're limited to offtake agreements, particularly in Brazil. As I've often said, yes, great, we can produce 15,000 barrels a day for 6 months, but it's better to have a plateau, say, 5,000 barrels for 4 or 5 years. That way you don't have spare capacity sitting idling when your well capacity cannot deliver. That's the reason.
Yes. Okay. That makes sense. And with all these proven reserves -- and we already touched that on one field here -- is there time to increase the plateau or at least the communication around that?
No, I don't think so. I mean, we continuously update our reserves, of course, with the Tie-2 results and now Tie-3 results when they become available, that all goes back into the model. But the plateau on the Tie Field is -- will remain the same.
And I have some questions about expanding in Tartaruga here. There's been a lot of questions regarding this, as I understand. So I get -- I'll just sum it up here. Why haven't you started? What's holding your back? What's holding you back?
Yes. What's holding us back is the well deliverability, right? So we have 3 wells on Tartaruga. And Maha-1, which was the last well we drilled, we had planned and we had anticipated higher production volumes from that. That's given us a bit of a curveball in terms of information. We are unable at this -- today to explain why we're seeing water in the Penedo-1. It is at a very similar level to the other Penedo-1s in the other 2 wells. They really shouldn't be any water there. So we have to do some more work to understand that. So right now, even if we had facilities that could handle 2,500 barrels of oil per day, we don't have well capacity to provide that throughput. So that would just be wasted time and wasted money today. So the plan there is to go back to the Southern Fault Compartment, drill 2 horizontals, and parallel to that upgrade the facilities. We know that horizontal wells work extremely well in Tartaruga. The sands are continuous. The Penedo-1 and the Penedo-6 are very thick sands. And just by the nature of the reservoir, we know that by stepping away into new parts of the field, in these tight reservoirs, we see very high reservoir pressure. So these horizontals do extremely well, and that's the way to go in Tartaruga. So even though this well was disappointing for us, it's giving us a lot of very valuable information on which we can further build on. So the long story made into a short answer is that we're scratching our heads a little bit and we're regrouping. And we are coming back with a vengeance in 2020 -- at the end of this year, beginning of next year.
Can I just move quickly to the U.S. operations, conscious of time here. But you did a write-down. Could you walk us through the mechanics? Because I believe this is a noncash item. And if so, it could be reversed. And I'll add another question here, and that is coming in from the web here. Are you able to expand production in LAK?
Well, I'll hand over the first one to Andrés. He can explain the mechanics of this noncash item. And this is not an unusual event. I think ExxonMobil, they impaired, I don't know, a couple of billion dollars at the end of the year. So -- but Andrés, maybe you can explain the impairment mechanism of LAK.
Sure. So at year-end, as part of our year-end procedures, you go through impairment indicators of your E&E and producing assets. And LAK is one of our E&E properties. And it did trigger an indicator of impairment. The fact that, although the plan is to continue the development of the block, that the recoverability of the investment at current -- or at least at the pricing at year-end could be challenged. So at that point, that triggers an impairment test, which is performed at the year-end pricing. And that resulted in a carrying value lower than our net book value, and therefore, we have to adjust for the difference. And that triggers the impairment. Pricing has been recovering since. And because this was pricing related and not because of operational events or a dry hole, there is the opportunity to reverse this down the road. So I hope that answers that part.
And then we have the questions about expanding in the U.S. field. Is that connected to the oil price? Or is there anything else that is the bottleneck?
No, it's -- LAK Ranch is definitely an oil price play. The oil is there. We know it's there. It's been there for a long time. It's produced steadily in the past. And when oil prices recover to such an extent that it warrants further investment in LAK, we'll look at it. But you've got to remember, it also competes with other projects in our portfolio. So -- but the great thing about the LAK Ranch is, again, it's shallow. It's the classic 19 degree API oil that everybody sort of thinks when they think of crude oil. And it's large. You're looking at about 60 million barrels in place. But it is tough to get out. Obviously, it's been a challenge for us. And I'm convinced that somewhere, somehow, we will unlock the key to LAK at some point. But at these oil prices, it's just not worth continuing for the time being.
And I'll have another question here that I'll just throw in here. And given the backdrop here and all the -- what problems that have been heaped together, what is the total production at the current situation? Are you able to give us a number? Or is it just that it's increasing on back of everything coming back on track?
The production has been very stable since the year-end. And I believe we issued a production number at the year-end. And we're around that figure. We're waiting on additional production from GTE-4, as I mentioned, and then GTE-3 when that comes on. So it's been very stable since the year-end.
Well, thank you for that. And conscious of time, I'll just throw in one last question here. And that is about the market conditions in Brazil. We saw some management changes in Petrobras, due to the main owner, I take it. And at least the currency market made its opinion clear on how they viewed governmental interference there. Would you be able to have any comments on the business environment in Brazil on the back of that?
Well, I can tell you, I'm not going to comment on Petrobras and the politics going on there. But I can tell you that Brazil is smoking hot when it comes to oil and gas. It accounts for a large part of their income. Lots and lots of opportunities bound in Brazil, and we're very happy to be there. It's not without its challenges, but the investment climate in Brazil is -- for oil and gas is outstanding.
And with the risk of outstaying my welcome here, I'll throw in the last question here. And basically, it's connected to one of the Investors Day here. Could you please provide us some guidance on the cost outlook for 2021 in light of the increase in the unit OpEx and any other costs of goods?
Well, we issued our capital plan for 2021, and we would expect OpEx to -- the high OpEx we saw in Q4 is -- obviously, we're not happy with that. It's a large deviation from our previous trend. But they are mainly -- they are, I'd say, 100% due to these problems we saw during the last quarter. I think Andrés touched upon a few. The GTE-4 was extremely costly for us. A lot of that cost made its way into OpEx. The reduced production number, obviously, also has an effect on a per barrel cost. We had some onetime penalty payments we had to pay for not delivering the sufficient amount of gas to our gas customer. So all these things sort of accumulated and conspired against us in the fourth quarter. We expect that we will be well on track to deliver our OpEx per barrel numbers for 2021. So far, knock wood on January or February. We are following our internal plan almost exactly online, so we view this optimistically. Now if I can just -- again, to use your words, maybe outstay my welcome. We've seen an unbelievable recovery in oil price. And I was trying to find -- I was trying to find a -- I did make a prediction. I think it was beginning of '20 or sort of March of 2020 last year. I foresaw that the oil price would recover. I think I mentioned as high as $80 per barrel. We're obviously not there. But with this increased oil price with our excellent netbacks and our unbelievably good foundation now that we've accumulated in terms of assets, we are poised. We're sitting very, very nicely for further growth and to harvest these investments that we've made into Mafraq, into Illinois Basin and into Brazil.
Excellent. Well, thank you for this. And there are a lot of questions still going around, but we'll have to forward those to Victoria Berg at Maha Energy. And you've seen the e-mail address. Jonas, Andrés -- and Andrés, thank you so much. It's been very interesting, and we will look forward to follow the company and to the next report. And as you mentioned, if people like more information, they will be able to see the live streams of your upcoming events. So with that, I'll thank you and I will thank all the viewers and particularly those who had forward questions during and before. Thank you so much.
Thanks, Kaarlo.