They're all and welcome to NorAm Drilling's Q1 2023 results. My name is Marius Furuly. I'm the strategy and investor relations director in the company. With me on this call, I have Mr. Marty L. Jimmerson, the company's CEO and CFO with me from Houston, who will present the company's Q1 results and be available for a question and answer session at the end of this presentation. Feel free to use the chat function or the question function in Microsoft Teams during the presentation, we will answer the questions at the end of the conference. Before we begin, I'd like to point your attention to the disclaimer page on page two regarding 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. 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 different from those set forth in the forward-looking statements. Thank you for that. With that, I'd like to introduce Mr. Marty L. Jimmerson, who will continue this presentation. Please go ahead, Marty. Thank you, Marius. Good afternoon or good morning to you wherever you may be joining us today. I am pleased to report that NorAm Drilling's Q1 2023 financial results represent record performance for the company. Revenue increased 11% sequentially from Q4 2022 as a result of continued strengthening of our clean base day rates. Excluding taking 2 rigs out of service for a total of 11 days during the Q1 for upgrades, we achieved fleet utilization of 99.3%, which was in line with Q4 2022 and continues to exceed our internal forecast. Adjusted EBITDA grew to $15 million as a result of the increases in revenue and a benefit from our final ERTC refund of $1.4 million. Net income after tax was $9.6 million or $0.22 per share on a fully diluted basis. Wrapping up slide 3 in our Q1 2023 highlights, our current backlog as of yesterday was approximately two and a half months of revenue. On page 4, NorAm is debt-free, and we paid $13.1 million or NOK 3.15 per share in monthly dividends to our shareholders in Q1 2023. This brings the total dividends returned to our shareholders from December of 2022 through last week's dividend to a total of $27.2 million or NOK 6.48 per share. That is impressive for the first six months of the company. While we continue to see a tight market for high-end Super-Spec rigs, especially in the Permian Basin, volatility in natural gas prices, which continued to drop from $4.50 per BTU as of December 31, 2022, to a low of $2 per million BTU in late March and early April, has been the primary catalyst for many smaller and private E&P operators recently releasing drilling rigs in gas basins such as the Haynesville and the Eagle Ford Basins. By most reports, the majority of these rigs that have been released have been stacked in the gas basin where they previously worked. However, a relatively small number of rigs have been mobilized to the Permian Basin looking for work. A few of these transitory rigs have secured contracts, displacing lower-end rigs such as SCR, mechanical, or lower-end Super-Spec rigs. The residual transitory rigs arriving in the Permian remain stacked and are currently looking for work. As of yesterday, natural gas has been trending up slightly and was trading above $2.30 per million BTU. While the improvement in natural gas prices provides some encouragement, we believe it will take until later in 2023 or 2024 to see demand for additional rigs in the gas basins. WTI has been volatile as well, albeit less than natural gas, and has tempered E&P's near-term plans to increase drilling activity. Recent consolidation and announcements of the E&Ps is also contributing to some rig reductions or potential future rig reductions. Most E&Ps that we speak with say they will be looking to start picking up rigs later in 2023 as they expect WTI prices to increase. WTI is currently trading in the low $70 per barrel range and is well above published breakeven amounts. I know everyone's looking at WTI. It's even up again this morning, based upon concerns of supply. Given the macro trends and volatility in natural gas and WTI, the U.S. and Permian rig counts have reacted as we would have expected. While the total U.S. land rig count has declined 65 or 8.5% since December 31, 2022, the Permian Basin rig count has only dropped 4 rigs or 1.1%. Next page. We continue to believe that the market fundamentals remain intact and are well-positioned longer term for increased demand for high-end Super-Spec rigs like our fleet. Drilled but Uncompleted wells or DUCs in the Permian, where over 60% of the U.S. oil supply is produced, continue on a downward trend. Many of the remaining DUCs could likely not get completed for economic reasons or are not operationally viable. As current well productivity continues to decline fairly quickly with limited viable inventory of DUCs, the supply of US oil will have challenges meeting current production levels given current rig count levels. With global oil demand expected to increase, U.S. shale will be expected to fill the anticipated shortage of oil supply versus anticipated future oil demand. According to industry reports, NorAm's fleet continues to outperform the number of rigs drilled per month, wells drilled per month and supports the efficient operations and demand for our high-end Super-Spec rigs. With that, Marius, I'd like to turn it back to you. Thank you, Marty. There we go. In Q1, we continued to achieve a full utilization and maintained industry-leading margins after maintenance CapEx, SG&A. Capital expenditures were a bit higher than normal in the Q1. We recorded $2.1 million of capital expenditures, and most of that was relating to equipment upgrades, and a small share was for maintenance CapEx. The Q1 equipment upgrades done in the Q1 is predominantly relating to completion of the remaining requirements that all our rigs meet our ultra Super-Spec specifications. Additionally, we commenced construction of our first transformer to allow our rigs to connect to highline power. We anticipate that this transformer will be placed in service in the Q2 of 2023. We currently estimate that our full year capital expenditures will be in the region of $3.5 million-$4 million with the majority being upgrades or equipment or equipment add-ons that ultimately is compensated for through dayrate from our customers. On page 7, we show our balance sheet and our cash flow statements. As you can see, we have a strong debt-free balance sheet. With minimal expected future capital expenditures, we are in the position to continue to distribute all of our operating cash flows after OpEx and G&A. So far in, since listing, we have distributed almost six and a half NOK per share to our shareholders. That's the strategy we intend to keep on doing, subject to our meeting our minimum liquidity level of $11 million or $1 million per rig. In our balance sheet, I would point you to other current liabilities, which is declared dividends after the end of the financial quarter. Even though we have some liabilities showing up in our balance sheet, that's not debt, that's declared dividends. While we are now debt-free, we have availability under our RCF with the US bank of $4.5 million, but none of those money was drawn at the end of the Q1. By that, I would like to thank you for listening into our presentation, and we will now open up for Q&A session. To ask a question, please use the chat function in Microsoft Teams, and we will start reading your questions to the audience. I will pause there for a minute to let people write questions. Thank you for listening. All right. I see that we have some slight issues with the chat function in Microsoft Teams. I'm sorry for that. Although, I have actually received some questions. If you would like to ask a question, can you please write it to ir@noramdrilling.com. I'm sorry, we have to. We can spend some time on your questions, but you have to send them on email to ir@noramdrilling.com. I'm sorry for the technical difficulties, but we will manage to host this Q&A session regardless. I have the first question that comes from one of our investors is, "What's your strategy for keeping your fleet employed given the recent slowing momentum in the market?" Marty, would you like to answer that? Thank you, Marius. First, owning a pure fleet of high-end Super-Spec rigs provides NorAm an advantage over other drillers who may own mechanical SCR or lower-end Super-Spec rigs that still require capital investment to achieve our rig efficiencies that we think our customers demand. Second, all of our rigs are currently located in the Permian, where 50% of the active rigs are working today. We strive to ensure that we're working for a preferred E&Ps that appreciate our high-end quality fleet, operational reputation, safety record, and we expect that we should earn a higher clean base day rate as a result. Near term, we anticipate that both E&Ps and drilling contractors will execute shorter term contracts, probably in a 3-month or pad-to-pad kind of range, which ultimately will benefit the drilling contractors longer term. With a debt-free balance sheet, NorAm does not have to chase day rates down and subsidize E&Ps where it does not justify operating our rig, incurring the operating expenses, our overhead expenses, capital expenditures, safety risk, and longer-term wear and tear on our premium equipment. Thank you. Thank you, Marty. I also got a question from Fearnley Securities, from Truls Olsen, he asks, "How many rigs do you have that roll in the near term, and how should we think about the potential for recontracting? Also, where should we see day rates bottom? Well, good question, Truls. You may know as much or more than we do, I suspect. No, with the backlog of roughly two and a half months of revenue, we expect to touch contract renewals on roughly half of our fleet, maybe a little bit more over the next three months. We are in conversations on one or two of those rigs. Neither the operators nor us. Even when the market's up and to the right, you normally do not get a sense on the renewal rate until just before the expiration of the current contract. That's not changed today. Based upon all of our conversations, there is the intention to keep the rigs working. We're just navigating through day rates. As you saw in our press release, we have seen some softening on renewal rates. I think that's a case by case situation depending on who you're working for, where you're at, what they're looking for, et cetera. I don't know where the bottom is on day rates. I do know where we are in terms of day rates. As I said, I don't think that we're gonna be compelled to chase day rates to the floor as we did in years past, which did not prove to be a good strategy. Thank you. Thank you, Marty. We have received a lot of questions. That's good. Making the best out of this situation. We have another question here from William. He asks, "Having read that the oil companies are finding fewer large deposits per drilled well in the Permian and yet U.S. oil production would rise steadily over the coming years, do you foresee a squeeze for rigs in 2024 even if gas prices remain at the current relatively low levels? William, a great question. You know, I think that kind of just fits right into our thesis, which is the US shale is gonna have to produce oil regardless of what gas is. You know, we all can have our own opinions on gas. I do think it's gonna go up as we kinda get LNG exports going, but that's a little longer term. The majority of Super-Spec rigs are working today. I think the utilization is, you know, right around 90% roughly today. There's still maybe another kinda 100 rigs that could get upgraded to, you know, maybe our high-end fleet, but it's our quality of rigs that's gonna be required to meet the anticipated increase demand for supply as we move forward. You know, while everything's not the same, what I can say is we continue to see our operators wanting to drill more wells per pad, which bodes well for our type of rigs, that can do multiple wells per pad, and I think that trend will continue. Thank you, Marty. William also another question, which is relating to duration of our backlog, and he asks, "With the current backlog, I estimate that roughly two and a half months of work is secured for the rigs on an aggregate basis. Do you expect to hold a bit back on new contracting if we see further weakness over the summer and play it spot than you already do, or would you just prioritize to secure firm employment going forward?" Basically to summarize, will you hold back to see if we can to hold back on new contracting if we see weakness over the summer, or will you prioritize to secure more firm long-term employment? Yeah, it's another good question, and how I would like to respond is, you know, the two most recent rigs that we renewed, it was our preference, that we remain short term, so call it pad-to-pad, and we'll call it 90 days. We have daily discussions about our ongoing renewal discussions with operators. Let's just say my preference, unless I hear of a dayrate that I think justifies, a longer term commitment such as 6 months, my preference would be to stay short term. I do see the current momentum in the market being more of a speed bump and not a downturn. I wanna be well positioned, when the market does start to improve on day rates, which I do expect to occur later this year. Thanks. The third question from William is about the useful life and the age profile of rigs. Could you talk a little bit about useful life? If you would sell any rigs, work them until scrapping, or do you need to put any money aside in the future for upgrades, et cetera? We have discussed this in previous calls, but it's good to refresh it a bit. Marty, I can start. We built our rigs between 2010 and 2015, and our average rig fleet age is close to 10 years. However, we have done a lot of upgrades on the rigs in the years between 2018 and 2021. We spent about $40 million of CapEx into upgrade work and exchanging certain equipment on board the rigs. These rigs are extremely more powerful than a new build built in 2014 would have been. There's been several developments on drilling in Permian, i.e., going to longer laterals, which has made the previous Super-Spec rig a little bit outdated compared to what we define as our ultra Super-Spec rigs. In terms of how long they could last, Marty, do you have any examples of how long could rigs last in, on the US shale? Thanks, Marius. We depreciate our rigs basically over 15 years. I'm very confident that, based upon our operational protocol, our maintenance program, how we treat our equipment, and the preventative maintenance that we instill, I have no reason to believe that our rigs will not continue to work for another 10 to 15 years without any major or significant amounts of capital reinvestment, you know, which you're probably gonna incur as you come up upon your recertifications. You may have to do some welding on the derrick, some reinforcement. There's nothing that is not, you cannot solve by either overhauling a piece of equipment or changing it out. You just gotta ensure that the structural integrity of the substructure and the derrick is intact so that you don't have a catastrophic situation. It's I guess it's relevant also for the audience that unlike an offshore rig that needs to be classed every 5 years, the classification of shale land rigs is a bit different. It's a biannual survey, and it's a 10-year survey, which is a bit more comprehensive. Marty, we've had some of our rigs through that 10-year survey already, and is there any experience you can share from that 10-year survey? So our on the structure, we've just had our first three rigs go through. We did not incur any material cost for repairs, you know, small amounts. But I think that still speaks to how we operate our rigs, how we inspect our rigs, on rig moves, and taking care. When you see something in year four or five, you deal with it. You don't wait till year 10. That's just not a very safe or prudent financial decision, and that's how we operate. Thank you. Thank you for the color, Marty. Another question from Trygve here. Could you please comment on the recent article in Financial Times about an auction from Kruse Asset Management who are selling two unused top-of-the-line drilling rigs? It's a bit detailed, but they were built in 2019, and their respective starting bids is about $13 million and $2.3 million each. Any comments to that, Marty? I know you know these rigs from before. Trygve, we do know the rigs, how well, and, you know, not as well as our rigs obviously. It does appear that one of the rigs was built by Schlumberger in their efforts to try and get into the rig business and sell rigs into the marketplace. The other rig we know of. But neither one of these rigs would be what I would describe as ideal candidates for the Permian Basin that require efficient rig moves and probably require some additional CapEx, like quite a bit. We have gone and inspected those rigs previously prior to the announcement that was in the Financial Times. Our interest was in certain pieces of equipment that would fit our standardized equipment. I'll just kind of wrap up with two comments, is number one, I think most likely any buyer of those rigs will likely want to take those rigs internationally. Secondly, there are some components on both of those rigs that is not standard to our equipment. While I'm not an operational guru, I will tell you that my team's telling me we're not sure where you get replacement parts or can you even get a new piece of equipment for certain components on those rigs. I think they'll have their challenges. I think they can deal with it. It's gonna take a lot of money, but I don't view those rigs as being a competition in the U.S., nor being representative of what you should think about, rig values in the U.S. because they're just not comparable to our fleet. Thank you. He also asks whether NorAm would be interested in buying rigs at cheap prices. Obviously, for the right opportunity, and I think this will be consistent with what we've said, we wanna ensure that we maintain the profile and integrity of our high-end Super-Spec rigs, for a pure, high-end opportunity that would be an accretive situation to NorAm that fits well with our operational structure, and complements the standardization of our equipment. I think you'd have to naturally look at it. We have in the past, and we will continue to look for opportunities, but we're not gonna do anything crazy. Thank you, Marty. We have one question from Peter. He asks, "What do you see as the value or market price per rig today?" I'll just to confirm, whether you ask about the market price of a rig, or I assume that's the question. In terms of the market price of the rigs, we know that there are rigs out there which as the Financial Times article mentioned, being auctioned or marketed for sale. Although none of them are essentially comparable to the rigs that we have as Marty just explained. It's a bit tough to say what's the market value of a rig today. Of course, we... You can calculate the market value or the implied market value through our shares, which is a reference point. In terms of a standard market price, we don't have any answers for you. I'm sorry. Another question from Hans-Olav Torgersrud. He asks, "With the credit facility, why do you still need use the $11 million on account?" Marty, you want to share? Sure. The simple answer is kind of there's a little bit of ebb and flow in terms of working capital. For example, we just, you know, renewed our insurance, and that was a couple million dollars of cash outflow that you amortize over a one-year period. We do have these CapEx upgrades that we've been incurring. The answer is, we are a little bit above the $11 million. It's trending down. We wanna make sure we can properly handle both any kinda cyclical, if you will, timing of cash collections, cash outflows, and that's over a relatively short few months looking forward, not over a long term. Thank you. Another question from Truls at Fearnley. He asks, "Just in case, how quickly could you reduce cost if a rig runs idle? Hey, Truls. you know, I think this is where NorAm excelled when rigs started stacking during COVID. I think you've gotta make a decision on what your strategy is. During COVID, we elected to warm stack our rigs much similar to how some operators did do it offshore, or drillers do it offshore, where you'll stage 2 or 3 jackups together and you can, you know, have a not a skeleton crew, but effectively, instead of having 3 crews for 3 rigs, you could have 1 crew, and they just rotate and go through and turn over all the engines and do painting and repairs and maintenance. To answer your question in the beginning is, if a rig is released, we would bring it to the yard. We would stage it in such a manner that we, our intention would be to keep it warm and hot, probably even stand it all the way up and have it running every day for at least a period of time. The crews would probably not be full crews. You know, we could probably utilize some of the crews elsewhere. We wanna make sure we would keep the crews in the near term, because we would not expect to be down low or down long. Should we get the sense that a rig would be stacked for a longer period of time, we could eliminate probably 90% of the cost or 80% of the cost and be down to $2,000 or $3,000 a day within, you know, roughly 30 days from the time the rig hit the yard. Thank you, Marty. I think that was all the questions. With that, I would like to thank you all for listening in and sorry about the technical difficulties in the beginning of the Q&A. I think we managed well regardless. Thank you, Marty, for dialing in from Houston and thank you to all NorAm employees, crews, and families out there. Look forward to speak to you over the summer. Thank you.