Hello, everyone, and welcome to NorAm Drilling's First Quarter 2025 Results Presentation. My name is Marius Furuly, and I'm the company's Director for Investor Relations and Strategy. With me today, I have the company's CEO and CFO, Marty Jimmerson, from Houston. We will first go through a presentation of the quarterly results and recent market developments before we open up for a questions and answers session at the end of the presentation. Before we begin, I would like to bring your attention to our disclaimer page. This conference call will contain forward-looking statements. Words such as expects, anticipates, intends, estimates, or similar expressions are intended to identify these forward-looking statements. Forward-looking statements are not guarantees of future performance, and these statements are based on our current plans and expectations and are inherently subject to risks and uncertainties that could cause future activities and results of operations to be materially different from those set forth in the forward-looking statements. You should therefore not place reliance on these forward-looking statements. With that said, Marty, please go ahead. Thank you, Marius, and hello to everyone joining us today. I am pleased to report that NorAm continued to deliver operational excellence with 10 of our 11 rigs in our fleet employed during the first quarter. Permian rig counts finished the quarter at 300, down 4 from the beginning of 2025. WTI began and finished the quarter at approximately $72 a barrel, with a high of $ 80 and a low of $ 66. Our revenue was $25.8 million, down $800,000 from the previous quarter, primarily as a result of slightly lower utilization. Our fleet utilization decreased to 89.7% from 90.6% in the prior quarter. Adjusted EBITDA was $6.7 million, up $100,000 from the previous quarter. Our net result was positively impacted by, excuse me, our profit after tax was $5.2 million in Q1 2025 versus $1.9 million in Q4 2024. Our net result was positively impacted by a change in our rigs' estimated remaining useful life estimates effective January 1, reducing accounting depreciation of our assets. Ten of our eleven rigs were under contract and working at the end of the first quarter. Our backlog was $17.6 million as of May 28, with nine of our eleven rigs under contract and working. Next page, regarding recent events and outlook. During the first quarter, we paid dividends of $5.2 million, or NOK 1.33 per share. Subsequent to quarter end, we announced two additional monthly dividends, and our latest distribution represents our 30th consecutive monthly distribution since our listing. As mentioned on the previous slide, our current backlog was $17.6 million as of Wednesday. Seven of our rigs are currently operating under contracts of at least six-month terms. Two of our rigs are on a pad-to-pad contract. I am pleased to report that we signed a contract with a major E&P customer yesterday for a previously announced anticipated third rig that would be released, and that will be transitioned from the existing customer with little or no white space. This initial pad-to-pad contract will add an additional $1 million to our backlog. As of last Friday, the Permian rig counts had declined an additional 21 units, or 7%, to 279, as a result of WTI prices declining from around $71 to a low of $57 and is currently trading around $61. This has been driven by continued economic and geopolitical uncertainties, E&P consistently operating and demonstrating fiscal discipline, and then, obviously, the OPEC announced production increases. Now turning to the next page. On the market side, we see that the Permian rig counts continue to drop, as mentioned earlier, since the beginning of the year, as oil companies respond to lower oil prices by cutting activity. Accordingly, oil well completions are dropping. Data from EIA suggests April 2025 well completions were the lowest since the lows of 2021 when COVID disrupted the supply of people and rigs. Oil production growth has continued to slow, and the latest EIA figures point to only 260,000 barrels of oil per day growth year- over- year during Q1. We are firm believers that we would need to see an increased rig count to accommodate material production growth in the Permian going forward. E&P commentaries vary, but the sentiment is currently consistent. U.S. oil production has peaked and will decline at the current rig count levels. Break-even WTI prices vary, but estimates range mostly from the upper $50 to mid-$60 range. Seems EMPs are coming clean with their full cost break-even estimates. CapEx will likely continue to decline if WTI prices drop below the current levels, as EMPs likely will elect not to drill their tier one acreage, as these prices and their tier two acreage break-evens are more than likely higher than the current WTI prices. In closing of my opening remarks, I would like to thank all of our employees for their hard work and their dedication. We continue to be a top contract driller with our talented employees and Ultra Super Spec rigs. We're very proud of everyone. Marius, let me turn it back to you for a review of our key operational figures for the quarter. Thank you, Marty. In the first quarter, we achieved a rig utilization of 89.7%, down from 90.6% in Q4. We had one rig stacked during the quarter, and subsequent to quarter-end, we had another one ending its pad-to-pad contract with a public E&P. We continue to look for employment opportunities for both stacked rigs, including outside our main market in the Permian. Revenues came in at $25.8 million, slightly down from $26.6 million in Q4. However, we had an adjusted EBITDA of $6.7 million, marginally up from $6.6 million in Q4, thanks to lower operating expenses. Our operating expenses decreased as our repair and maintenance expenses decreased from Q4. However, we would like to caution that we do not expect the level of R&M expenses in Q1 to be representative for the run rate going forward. Our all-in break-even was around $17,500 per day for the working rigs, but we expect this metric to be at a slightly higher level going forward as Q1 was extraordinary on the low side. The idle rigs are stacked at about 30% lower cost than the working fleet. On the income statement, we had an operating profit of about $5.2 million compared to an operating profit of $1.6 million in Q4. The increase in operating profit can be mainly attributed to lower operational expenses and a change in our accounting policy regarding our rigs' useful life assumptions. Accordingly, we expect the quarterly depreciation going forward to be around those of the level in Q1, which will lead to all else equal, a higher net result for the company. In Q1, we had a financial income of $150,000 as a result of interest income and FX gains, and we continue to have a debt-free balance sheet, and we had no borrowings under our RCF at the end of the quarter. First quarter net profit was $5.2 million versus a net profit of around $19,000 in Q4. Turning over to the balance sheet and cash flow statement, we ended the quarter with a cash balance of $12.1 million, sorry, as a result of working capital reversals during the quarter. During Q1, we paid out $5.2 million, or NOK 1.33 per share in monthly dividends, and we have declared two quarterly dividends subsequent to quarter- end. We will, subject to profitability, continue to pay out dividends as we operate with high utilization and favorable drilling rates. To conclude this presentation, NorAm has a fleet of 11 Ultra Super Spec rigs fully upgraded with state-of-the-art walking systems and racking capacity, with a track record of drilling the longest wells in the Permian Basin. We are strategically positioned in the Permian, the largest U.S. shale basin, where our rigs are among the very top performers in terms of drilling efficiency, measured by feet per rig per day. We retain a top-quality customer portfolio of five E&Ps, ranging from super majors to smaller companies. The company has an industry-low cash break-even and minimal investment requirements in the rigs to keep them at the top of the market. We have a clear dividend policy and will continue to return all excess cash flow to our shareholders. Since our listing, we have returned now $77.6 million, or NOK 19 per share, to our shareholders, and our latest monthly cash distribution implies an annual yield of approximately 22% as of the closing price on Wednesday. With that, I will conclude this presentation, and we will open up for a questions and answers session. You can either use the raise hand function, or you can write in the Q&A chat. I think we have a little bit of problems with the raise hand function right now, so I appreciate if we could use the Q&A section in Teams. Our first questions come from Harald Lund. He asks, "Looking forward into 2026, do you think rig count will continue to go down, and is it possible that NorAm will have more rigs out from the market?" Marty, would you like to start? Yeah, so it's a little premature to start looking into 2026. I think kind of everyone's really focused on 2025 right now, meaning that the EMPs are actively monitoring their CapEx plans. In order to start getting a vision into 2026, I don't anticipate that we'll get much clarity on that until probably the earliest third quarter, more likely the fourth quarter, but it's going to all be driven by the price of WTI. At current levels, what it feels like is that at the current WTI prices, I think there'll be some continued pressure on the number of rigs short-term. Now, whether that carries on to 2026 or not, that remains to be seen. What I can tell you is that we believe that at the current rig activity levels, oil production in the U.S. has peaked, and in order to maintain the production at some level going forward, we're going to need to increase the rig count. Whether that happens in 2026 or not, I think it's a little premature. I still believe that NorAm will perform well, given that all of our rigs are Ultra Super Spec rigs. We continue to operate very well, and as mentioned earlier, we're transitioning a rig next week from an existing customer to a major operator, which I think in this marketplace, I think speaks volumes for the quality of NorAm. I hope that answers your question, and sorry I don't have a very good crystal ball into 2026 right now. Part two of his question is related to our distribution of dividends. Is NorAm Drilling able to pay dividends with more rigs out of the market? Marius, you want to handle that, or would you like me to? I mean, we can say, as said during the presentation, we will, of course, subject to profitability, continue to pay out dividends. NorAm has a long operational history, and since 2016, we have with this current fleet, we have not run into an operational loss before financials, i.e., unlevered. We've been profitable every year since 2016. We are taking measures to reduce our costs in the event of a prolonged downturn, and we will try to protect our shareholders from activity declines. However, it remains to be seen what level of rigs we can retain working. We are, of course, hopeful that we can stand firm with the rigs we have under contracts as of now. Many of our rigs have worked for the same clients for numerous years, and we see the value in being a top performer, as illustrated by the fact that we were just able to transition one rig going off a pad-to-pad contract directly onto an existing customer. As Marty said, this speaks for itself in terms of our standing in the market. Would you like to add anything to that, Marty? Well said, Marius. Nothing else to add. Yeah. Another question on the side here. Are you seeing competitors moving idle rigs away from the Permian, or are they warm stacking them for now? Thanks. Yeah, so the only rigs that we see leaving the Permian are rigs that really came to the Permian a little over a year ago when natural gas prices declined. Those are a modest number. The rigs that are leaving, they could have been either, more than likely they were idle rigs going back to the Haynesville to work. Again, as of today, it's only been a handful of rigs, so not much color on the number and types of rigs yet. If natural gas continues to stay above three bucks, I think we could see more rigs leaving the Permian for the Haynesville. Another question there. Will all rigs stay warm without work if more of them will be out of work? Yeah, no, I do not think so. It is just not economically viable to maintain the crews if you really do not have good vision as to how long your rig is going to be stacked. What I think will more than likely happen is, let us just take an example. If NorAm were to have three or four rigs stacked, we would not have crews for all four rigs sitting in the yard at one time. We may have a complement of maybe two crews that rotate between the four rigs. When the market returns and we return one or two rigs to work, we would bring in additional crews so those rigs would be ready. I would call it a hybrid full-cost model. Thus, as Marius mentioned, if our full break-even cost is $17,500 a day, a warm cost or a warm stacked rig probably incurs $7,000-$10,000 a day. While I would not call it cold stacked, I would call it a stacked rig with no crews. That probably runs about $3,000 a day. All right. We have another question here from Truls of Fernis. Regarding M&A, what's your view on this, and is it more likely or not in the current oil price environment? Hey, Truls, thanks for the question. It's very interesting that I don't know is the bottom line. To me, it comes back to, are the investors of drilling rigs, are they willing to give up control for a transaction? I think everyone sees the merit of consolidation, but it's just tough to give up the cockpit seat and turn it over to someone else. Not all rigs are the same. We operate a pure fleet of 11 super spec rigs. For us to be interested to do something with somebody else, we would want to make sure that we weren't diluting the quality of our asset base and having to navigate with that. Now, having said that, we still remain firmly interested should there be an opportunity to pick up one or two or three rigs that fit our portfolio well. To see a kind of larger transaction happen, I don't think that occurs without someone being in financial duress. Also, we could also have a comment regarding M&A between the EMPs, as this has been a major theme the last 2-3 years in the market. We are, after Diamondback acquired Double Eagle, which was probably one of the bigger transactions in our space the last 6- 12 months, I would expect the appetite for more EMPs' M&A to be somewhat lower in the current oil price environment, as right now economics gets a little bit more challenging on both sides of the transaction. We could also say that the market in Permian has been quite consolidated now in terms of acreage, and there are fewer and fewer opportunities for big public EMPs to acquire smaller private companies, which is typically or historically clients that NorAm has worked for. We have another question from the chat. I understand that NorAm rigs can handle both oil and natural gas. How easy is it for other drillers to change from oil to natural gas, I assume, drillers? Secondly, how are the natural gas drilling market right now? Yeah, so I'm going to really reference NorAm. We cut our teeth in the drilling business working in the natural gas basins, primarily Oklahoma. In order for us to go back and work in the Haynesville or Oklahoma, I'm actually surprised at how little additional effort and expense it would take. Only some minor equipment that we pulled off of the rigs when we came out of Oklahoma to the Permian would be required to reinstall on a rig. For the quality of our rigs, it would take very little effort other than kind of roughly 30 days to put the rig on trucks and get it into the natural gas basin. It is interesting that natural gas is above $3, has remained above $3 here in the current quarter, but you really have not seen a significant move in the rig count in those basins just yet. How quickly that happens is to be seen, but we continue to actively look for opportunities in the Haynesville and would not hesitate to move a rig over there or a couple of rigs. Our preference would be to move a couple to get some economies of scale versus a single rig. We are very capable and have a history of experience in operating in natural gas basins. Another question there with regards to other areas or basins. Can you provide a little more color? I mean, now we just talked about gas basins, but are there any other opportunities out there? Yeah, so I really think our rigs are well-suited for either the Haynesville, Oklahoma, the Eagle Ford, but specifically the Permian. One thing that's kind of entertaining us a little bit is maybe looking at the international markets. While that's clearly not the backbone of NorAm, our rigs could be well-suited in some of the international markets. I don't want anybody hanging their hat on that, it is something else that might be an opportunity for NorAm down the road. I'm sorry, Marius, let me add, the Permian accounts for 50% of the rig count levels. If you add in the Eagle Ford and the Haynesville and Oklahoma, you've got a super majority of the U.S. land count with all of those basins. We're in the sweet spot. It's really those basins or international market that provides an opportunity. Sorry. Yeah, and then another question there. How are day rate and contract terms trending in the current market? Yeah, that's a great question. How I would respond to that is while our backlog is down compared to the prior releases, that's more of a function of the timing of renewals as seven of our rigs are operating on contracts of six-month terms. What I can say is, as of today, we have not seen a significant change in our customer bases' expectations of contract terms and day rates. If WTI remains at kind of the levels they're at today or continues to decline, I think it would only be kind of anticipated that there'll be some pressure on day rates and contract terms. As of today, we've not seen much pressure there. Thank you for that, Marty. Another question here on the line from Peter Lade. Are you in active discussions regarding your two stacked rigs? In a best-case scenario, how quickly could they be back on contract? Yeah, so we always are having active conversations. Given kind of where WTI is right now, any opportunities that are out there, it's a very competitive field. The fact that we were able to place this rig that's coming off of contract next week with an alternative major operator, I think kind of speaks to kind of where the world's at right now for our business. I do believe that at the current levels, I would be optimistic if I thought that we could put the third rig back to work during the third quarter, maybe a little bit earlier. The rig that's been stacked for 18 months, that's going to take a longer period of time, primarily because, as mentioned earlier, the Permian rig count has come down 21 rigs since the end of the first quarter. The majority of those rigs are hot stacked or warm stacked, if you will, maybe not having a full crew, but could crew up pretty quickly. We've missed some opportunities, or excuse me, I think the right term is we've lost some opportunities to put our last rig that's been idle for over 18 months now because operators are going to take a rig that is warm or hot over a rig that's been stacked for 18 months. Unfortunately, I think it's going to take a little longer for that last rig to get back to work. Our rig that just stacked last week, it's a great operating rig. Hopefully, I'm being conservative, but that we can get it back to work by the third quarter. It could happen earlier. Yeah. Both are very good rigs and with similar specs. A little bit different designs. Yeah, the difference is that one of them has not been working for some time, and the other one just went off contract, which makes the latter more attractive to the oil companies looking for hot rigs. Yeah. The next question is regarding the depreciation change in Q1. What factors went into this decision? Yeah, as always, you continue to evaluate the useful life estimates regarding your accounting policies. Our rigs average 10-11 years in age from the original construction date. We originally estimated the useful life of our rigs to be 10-15 years. Given our super spec upgrades completed over the last several years, which were being depreciated over 5-10 years, once we've kind of operated the rigs, completed those upgrades, and more importantly, we've now been through the 10-year, which is kind of the crucial recertification of your rigs, where you check the derrick and the subs to see if you've got cracks essentially in the foundation or the bones of the rig. What we've concluded is that given our maintenance program and the very minimal repairs required on these 10-year recertifications, what we've concluded is that given that there's no technical obsolescence risk, the quality of our maintenance program, the upgrades that we performed on our rigs, we determined that the original 10-15 year useful life estimates were conservative. The fact that we had a little over $50 million of carrying value on our rigs, we would have had basically zero net book value over the next three to four years on our balance sheet. There is no reason to believe that our rigs will not operate for another 10-15 years given our current maintenance program. That was the basis for revising the remaining estimated life of our rig assets. Thank you. Thank you, Marty. There are no further questions in the chat. I think we will conclude there. I would like to thank all of you for listening into our call today. We hope to see you again next quarter. Thank you to the family of NorAm employees for the great efforts made during the first quarter. Thank you all. Hope to see you in three months. Goodbye.