Hello, guys. How are we today? We are just fine. Thank you very much, Carlo. Anders, doing fine? Very well. Very well from Calgary. Thank you for asking. Excellent. Well, Jonas, today Maha delivered its Q2 results. Could you walk us through the quarter and your outlook for the future, please? Certainly, Carlo, thank you very much for hosting this webcast again, and welcome everyone that's watching live here on YouTube. I'm very pleased to sit here. Actually, I'm in Oman today, like you said, and we are pleased to report a very busy and very eventful quarter. Before I hand over to Anders, I just want to make a few summary statements. The quarter was busy, like I said. The first thing that happened was that we closed our financing, which was hard work that we culminated in the closing at the end of March. That secured, really, our future as a company, but that also led to the warrants being exercised. If you recall, we had some warrants that were part of the 300 million SEK bond that we issued back in 2017. An astonishing 98% of warrant holders exercised their warrants for shares, which was a huge uptick for us and obviously really impacts our net cash position and also our exit net debt ratios today. The quarter saw a continuing increase in oil price. It was almost a linear gradient for the quarter. We started the quarter at $65 per barrel, ended it at $77. There has been some weakening since the quarter ended. Currently, we're back to about $65, but the strong oil prices really helped us. What turned out to be quite a troublesome quarter for us at the Tie field, we did suffer some mechanical issues on one of our best producing wells, TA1, which was down significantly for the quarter. All in all, we lost about 880 barrels of oil per day during the quarter because of these mechanical problems. I'm pleased to report, though, that as of mid of June, they were all resolved, and all our fields are producing as per plan since mid of June. We can breathe a sigh of relief there. We also accelerated our growth in the Illinois Basin, Indiana area. We are currently drilling. We're very busy there. We have some great results coming out of Indiana. In fact, with only three out of nine wells that are currently being drilled and stimulated, we are already at almost 400 barrels per day of oil production consistently. Lots more to come from Illinois. We also set a record, Wallgrove 11-06, which was one of the wells that we drilled here during the summer, came out on initial productivity over 120 barrels per day, which for Illinois and Indiana is an incredible achievement considering that just five years ago, six years ago, initial production from these wells would be in the 50 barrel per day range. We're very pleased with the outcome there. Last, before I hand over to Anders, who's jumping at the bit, we started drilling our first horizontal well in the Tie field. We did that on the 9th of July, and I'm pleased to report that as of today, fresh off the press, we are at 1,874 meters. We're going to 90 degrees. We're currently about 37 degrees. Without further ado, I'll hand over to Anders, who will walk us through the financial figures for the quarter. Thank you, Jonas. Good day, everyone. Welcome to another quarterly webcast. I'll just jump into our Q2 results. We have slide four up, which is a slide where we like to present certain financial highlights for this quarter and the past four quarters. These are in thousands of US dollars and unaudited figures. At a quick glance, you can see this was another strong quarter. Revenues surpassed $15 million. That's up 41% from a year ago and is down 4% from the most recent quarter. EBITDA was $9 million. That was up 1.6 times versus a year ago and down 10% versus the recent quarter. Mainly a combination of the lower revenues and the higher OPEX that we were referring to earlier. Net result was $2.6 million. That was 5.4 times higher than a year ago and down 53% versus Q1, for reasons that I will go through in another slide. One of the contributors to this, and as Jonas was referring to, was the lower production this quarter, just over 3,100 BOPD, mainly due to certain planned and unplanned well interventions. This in turn was partially offset due to the increased realized price this quarter. That was up 126% from a year ago and 16% versus Q1. This also lifted our operating netbacks. For the quarter, these were up 157% from the comparable period a year ago, and 5% from Q1 2021. The net result of $2.6 million translated into $0.02 of EPS for the quarter. Going to the next slide five, we present certain balance sheet highlights. As you can see at a glance, the balance sheet remains increasingly strong and conservatively leveraged. Cash and cash equivalents for the quarter ended up $34 million. This increased our working capital to be at a surplus of almost $23 million, mainly following the refinancing and equity transactions of the quarter, but also after contemplating the payables that arise from the capital activity in the quarter. Total assets and shareholder equity both significantly increased due to the capitalizations from the debt and equity transactions during the quarter. The SEK 300 million bond was repaid early in May, following the BTG financial transaction. At the end of the quarter, net debt was at $20.5 million. In connection to the bond, TO2 warrants were exercised during May, just under 7.4 million, which translated into proceeds of SEK 53 million. These warrants had an exercise rate of 98% over the four years. There's no dividend plans as Maha continues to grow. Going to the next slide, where we show our quarterly production. Following the record production quarter during Q1, Maha underwent certain planned and unplanned well interventions this quarter, which affected its production, lowering the Q2. Despite this, as we were referring earlier, revenues remained high due to the increased oil prices, the steady recovery in oil prices now surpassing pre-pandemic levels. We're looking at 135% increase versus a year ago and about 13% from Q1. Going to slide seven, there are certain key metrics that we like to keep track of, netbacks being one of them. Netback is basically what the return that is left on every barrel sold after royalties and operating expenses. This quarter was almost $35.5 netback. That's 1.6 times higher than a year ago, and about $1.70 versus the most recent quarter. The higher Brent was the main contributor for this being partially offset by higher OPEX this quarter. If we look at the chart in the lower left, we can see how these one-time items affect the unit operating costs. In this quarter, in particular, it's twofold. There's the higher cost and also the fact that during these well interventions, production had to be shut in. This creates a less cost absorption in our unit costs. Lastly, cash balances, obviously. At the end of the quarter, we were at $34 million. We can see that the company is well capitalized following the refinancing and equity transactions of this quarter. On slide eight, we also obviously track our net result. This quarter was a $2.6 gain, lower than Q1, basically from the lower sales, higher OPEX combination, the higher interest cost from higher loan amount following the BTG loan drawdown, and also from some unrealized FX from the USD appreciation on the USD-denominated loan. Another strong quarter. If we exclude for a moment the LAK impairment, this will make it number 15 of consecutive positive results. I will hand it back to Jonas in Oman. There we go. Now you should be able to hear me. Yes. I read somewhere that the second most used phrase in 2020 was, "You're on mute." I'm guilty on that one. Thanks, Anders, for that. I think it's fair to say that if we look at our first six months, I think our revenue for the first six months is coming very close to the full-year revenue of 2020. The result of that is the combination, obviously, of higher oil prices. Last year, of course, was a very tough year for the oil industry in terms of oil prices, but also our improved production. I'll give you a little bit of an operational update here. We'll start at the Tie field. The Tie field was really the main culprit for our reduced production numbers for the quarter, like I mentioned at the introduction. For the quarter, we were roughly almost 900 barrels per day lost production from the Tie field compared to plan. The reason for that is our star producer, TA1, was down almost for the entire quarter. It required, I think from memory, at least three different separate rig interventions, to not only re-complete it as a pumper, but also to clean out and recover some mechanically stuck issues in the short string. At one stage, we even had some slickl ine wire stuck in there that we had to fish out. All in all, the TA1 well was down for 56 days straight, and that obviously hurt our production. The second issue on the Tie field was we completed the drilling and the testing of TA3. As you recall, we found the Itaparica new formation that took some extra time to test. When we went to put TA3 on production, when we put it back to the battery, it produced slightly less than what we had planned for in our forecast. TA3 has since been re-completed, and is now on pump. It was free-flowing at first. That really led to the reduction in production for our Tie field. On a more positive note, despite this, I would say that we delivered almost a quarter of a million barrels from the Tie field. It was down slightly compared to Q1, and we continue to deliver gas to our gas customers. The new compression package that we installed late in 2019, early 2020 is working well. It's dehydrating the gas, and we are now waiting for more gas to come on after we finish the horizontal, which we spud at the beginning of July, so it's not really a quarterly event, but we can mention it as subsequent events. The TA4 horizontal, the primary objective, it's a single horizontal targeting only the Água Grande reservoir. Água Grande is about 2,000 meters below the surface. Like I mentioned at the introduction, we are very close now to the top of the Água Grande. We're at the 37 degrees to the horizontal. We expect to be finished with this well towards the end of September. This well, given that it is a horizontal, should produce quite handsomely. The idea is that once this comes on production, we will be at plateau at the Tie field. Go to the next slide, please. Little mention about Tartaruga. Tartaruga was slow and steady the quarter. The quarter was dominated by the testing of Maha-1 or the Tartaruga-3 well. Unfortunately, despite our best efforts, Tartaruga-3 continued to produce mainly water, despite our hopes that it would be dewatered and oil would increase. I think we will have to announce that Tartaruga-3 will be a subject of further investigations before we can do anything with that well. We will now focus on the southern fault block. If you recall also, the Tartaruga-3 well was targeting a northern fault block. Clearly we don't fully understand the geology there yet, so we will now revert back and place more wells in the southern block for the future. On the Petrobras divestment, we are told that Petrobras is in final negotiations for selling their 25%. We do not know who the incumbent might be, we are still awaiting that process. Last, I just want to mention that part of the reason why Tartaruga was slightly less than planned for the quarter was the impact of the Tartaruga-3 well testing. That has now been completed, and both wells are back on production. Go to the next slide, please. We should be on slide Yep, you are on the right slide. I see that. LAK Ranch, nothing to report on LAK for the quarter. It is still shut down, and we're still evaluating oil price scenarios on that field. On Illinois Basin, we went out in end of May with a revised budget for the company and a revised capital program. The original capital program for Illinois Basin was four wells for the year. We have revised that now to 12 production wells and one injection well. As of today, I can say that nine wells have been drilled. We are drilling three more. Each well needs to be stimulated, and out of those nine wells that have been drilled, most of them have now been stimulated. Like I said at the introduction, three out of those nine new wells are now starting to yield oil production. We still have another six plus three wells to join that production. The average for the quarter was down at 164 barrels per day, and the reason for that is that some of the producing wells had to be shut down when we were drilling some of the new wells in that area. Right now, current production out of Illinois Basin is growing. It's the highest it's been since Maha took over. We're steadily right now about 375 barrels per day. We anticipate production to grow further as these wells gets drilled, stimulated, and de-watered. I did mention that we have a Maha record on Illinois Basin, initial productivity on Wallgrove 11-06, which was 125 barrels per day of oil, and it's still doing very well. As of today, I see it's come down a little bit, but 120 barrels per day. The resume or the summary for Illinois Basin, so far it looks great, and we look forward to the U.S. taking a larger chunk of our corporate daily production numbers. We expect to end the year at about 700 barrels per day coming out of Illinois Basin. If we get more wells like Wallgrove, we will probably exceed that. Right. I think that summarizes the operation update. Day after tomorrow, we have Aktiespararna Live. There'll be a presentation by the company. Then we are presenting at ABG Investor Day on the 14th of September. We are also part of the Pareto Oil Conference in Oslo on 15 and 16. Then on October 7, we will hold our annual investor and shareholder information evening. Because of COVID, we will do that via this channel here, YouTube. It will be a digital event. It will not be a live event where we can meet. Hopefully, we can revert to normal operations sometime next year where we can hold a physical meeting. And then our third quarter report is released on the 22nd of November. With that, perhaps we can go to questions, Carlo. I know that you have received some already. Yes. Yes. Thank you for that. Well, the first is about the actual production versus the expectations, and in this case, my interpretation would be expectations based on not only the market but company communications, where the expectation seems to have been higher than the outcome for Q2. Would you like to elaborate a little bit on that? Not more than I've already sort of briefed in operational update. The reason for that was TA1 being one of our star producers. In fact, if you go to the ANP, which is the Brazilian regulatory authority on the petroleum operations in the country, you will find that two out of the top three producing wells in Brazil belongs to us. So when one of those key wells go down, it impacts us quite hard. Now, of course, we are busy drilling a new horizontal. The horizontal will be followed up with another horizontal in the Sergipe, and once those two wells are in place, we should have sufficient extra spare capacity in the system so that in the event, in the future, if a well goes down like TA1 it's been producing since 2019, and it's produced over a million barrels to date. It's been an excellent producing well. It's currently doing about 800 barrels per day. So when a well like that goes down, we feel the effects immediately. Well, sorry. On the fly of that, I received a question here on digital, you can answer this at your own leisure, of course, but what is the total production at the moment now that all the wells are producing as they should, if the reader understands this correct? What is the forecast for the upcoming month? Current production corporately is about 4,000 BOE per day at the moment. We do not release month by month forecast production numbers. I don't have it in front of me, and we wouldn't release that anyway. All I can say is that our estimate for the year, the production forecast for the year, between 4,000 and 5,000 barrels per day is still valid. It still holds. We see no reason to change that at this point. There's another question here regarding Tartaruga. Given the fact that you have gone through Tartaruga, it's just a very simple question. Will Tartaruga be producing on the same level as 2019? If so, do we have any estimates? The quick answer to that is that Tartaruga will not be producing in the 2019 numbers. The primary reason for that is natural decline. What we will look into is perhaps to recomplete one of the wells. We do have some shut-in production on one of those wells, and we are looking into that right now, which would be an easy gain for us. The overall objective now will shift towards the southern fault block, and we do have some proven reserves there that we can access relatively easy. That will require further drilling. In 2021, we have no drilling plans in Tartaruga. As you are now in Oman, do you still expect to start drilling there on the first half of 2022? Yes. Indeed. Jumping over to financials here. You mentioned that TO2, the warrant program there, and you mentioned the fantastic take-up on 98%, if I'm correct. Could you elaborate a little bit more about the significance of the full utilization, more or less 98% of this program? Well, of course, it's a funny thing. Those warrants, typically you would expect if economic theory serves you right, you should expect 100% uptake. That's never the case. As long as I've been in the business, I've never seen 100% uptake on these kind of warrants. 98% is excellent. I can only interpret that as apart from, of course, being from a capital standpoint, I can only interpret that as a great confidence in our company and that those funds, 53 million SEK that came in the second quarter, of course, that really helps us in the sense that we're very well capitalized at the moment. I might want to add to that with the stronger oil prices and our current production we are spending quite a lot of money on capital, we are still seeing free cash flow after all expenses, all operating costs, royalties, G&A costs, and CapEx. We're still seeing positive cash flow. We're in an excellent position. I'm really happy with our current financial situation. We are gearing up cost and capital expenditures. We will be drilling now pretty much nonstop in TA for the foreseeable future. We will also be drilling in Tartaruga sometime next year, and we are gearing up here in Oman. This capital will find a home. Obviously in line with that, also our production will continue to grow. I think I'm very happy with our financial position at the moment with strong cash balance and very low net debt ratio, really. Yeah, I don't know if I answered that question. I rambled on a little bit there. Well, basically- I hope that satisfies your answer. Yeah. Well, basically the strong oil price has increased the cash flow, which gives you an excellent situation and notwithstanding the warrant program. I think that was a granular answer, if any. The Illinois Basin, you touched upon that and you mentioned that this will be a significant part of your contribution. Would you like to put a number on that? Anything in the near future? No, I can't put a number on that. It's not going to be a significant contribution to the corporate bottom line. Right now at 400 barrels per day, you're looking at 10% contribution in terms of production. What I will say, however, is that Illinois Basin at these oil prices and these netbacks, it's bread and butter. It's slow and steady. It's safe, it's low risk. It is an oil price play. If oil prices go down to, say, $40 per barrel, we might have to take another look at our investment approach in Illinois Basin. We have lots of locations. I think our plan calls for drilling another 60 wells over the next five years, and I think that will suffice quite well. It really is a growth of a solid leg in the United States and also provides for further diversification security for the company. I will be jumping around here a little bit geographically because we have a question here from regarding TA1, the Well seven, TA1, has gone from, and I'm just reading here, 2,460 barrels in March 2020 to 961 in June 2021. Any comments on apparently increasing lower output from this well? Reading between the lines there, Carlo, I think that the reader or the individual posting the question is referring to test data from when the well was drilled and tested back in 2019. I think it came on in March or April 2019. You will see a natural decline with these wells. Like I said, TA1 has been on production now for, I guess, just over two years, and has produced cumulatively over one million barrels. It's an excellent well. It will most likely do better than GTE-4 and GTE-3, which both of those wells have produced well over two million barrels each. They've been on production for well over 10 years. I think that's what the individual is referring to. Current production is in line with normal decline of the field. don't forget, TA1 was on natural flow for the better part of 18 months before we converted it to pump. That should not come as a big surprise. I have another question here regarding the pandemic. The expectations, well, obviously, expectation for the COVID on the autumn/winter. Have you taken any measures there? Would you have any estimates on the future? On the effect? No. COVID continues to affect us primarily at obviously on all three levels. You've got the oil price, that's market volatility. I think we see that in the current oil price, the fear of this Delta variant. It impacts us logistically. It's very difficult for us to move around. As an example, I am currently in Oman. Oman had their borders completely closed for a better part of, I think, four months to all foreigners. That has delayed us getting boots on the ground here. They're currently opening back up so we will be able to start to populate this area here with our people and get things going. Getting people in and out of Brazil, although Brazil it has remained open, has been a real challenge in terms of getting flights. It really becomes a logistical problem. It's nothing that we can't overcome. It just means delays. The third, of course, is the impact of people being sick. We have had our fair share of COVID sick individuals, primarily in Brazil, where we've had some senior staff being taken out of action because of COVID. It continues to play havoc, but I think we've all adapted to these new norms and we all look forward, I think, to returning to normality as soon as we can. I have a question here regarding LAK Ranch. At what oil price will you motivate to start? Currently we are reviewing LAK Ranch. It's hard to put a number on that because it's also depending on inflow performance. We have taken the liberty of starting a few wells up here post second quarter. We are still evaluating LAK Ranch, I don't want to venture. There's no hard number that we can speak to. In the previous quarterly update, you introduced the creation of an ESG team and launched a sustainability review. How is that developing? Can you give us some examples on the contributions? Sure, yeah. ESG is obviously an important factor now that we are growing. I think towards the end of the year, I'm hopeful we'll pass some of our peers in Sweden in terms of production. It is taking more and more of a center stage. One of the examples that, for example, our ESG team is concentrating on actually at the moment is this authority here in Oman is requiring a greenhouse gas emissions report and also how we can monitor and improve our greenhouse gas emissions in the Sultanate. We've been quite busy on that. We're also very busy on HSE safety training, particularly in Brazil. We utilize this DuPont STOP system, which is a safety behavioral system program. It's very beneficial. It's been around for a very long time. A lot of efforts going into training all our people to those standards. We are also implementing quick response teams for potential environmental spills. They are keeping themselves very busy. I have another question here regarding, well, cost inflation or the price of the CapEx, as it were. Given the fact that the oil price is recovering, but we have the pandemic, do you see any development in increasing prices for the goods that you require, or is it stable? Flat? We have definitely seen an impact of I do not want to call it inflationary pressure, because with the downturn, a lot of equipment, a lot of people were laid off. With the uptick in oil prices, there has been sort of a scramble to get to that equipment and personnel. There is less equipment and less personnel in circulation. For example, in the Illinois Basin, I think our costs have been impacted by about 8% more than what we had budgeted for on our drilling campaign there. In Brazil at the moment, costs are somewhat stable. We have not seen as much of an impact in Brazil as we had in the U.S., but I think the reason for that is market-driven. U.S. has a different market than Brazil. I think that explains the cost increases in the United States. What can we expect from Maha going forward? Consolidating existing business opportunities, acquisition or a bit of both? We'll see that, yes, a bit of both. Well, thank you for that. It's been an interesting quarter, it seems like things are getting, well, if not back to normal, heading towards normality, whatever that may be. We thank you for the presentation. If there is any further questions, please don't hesitate and send them directly to the company and to Victoria. Well, with that, I thank all the viewers and I thank Jonas and Anders. Thank you.