NorAm Drilling AS ($NORAM)

Hi, everyone, and welcome to NorAm Drilling's First Quarter 2026 Results Presentation. My name is Sander Borgli. I'm the new Director of Strategy and Investor Relations here at NorAm Drilling, stepping into the role from Marius Furuly as he will be pursuing new professional endeavors. Marius, we wish you the very best with your new opportunity. Also with me today, I have the company's CEO and CFO, Martin Jimmerson in Houston. We will first go through the presentation of the quarterly results and recent market development before we open up for questions-and-answer session at the end of the presentation. Before we begin the presentation, I would like to note that 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. 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. So with that, Marty, please begin.

Thank you, Sander, and hello to everyone joining us today. Before I begin my presentation, I want to thank Marius for his contributions and collaboration over the last 5-plus years of working together. It has been a pleasure teaming up with you, and we all wish you the very best in your new opportunity and know you will be very successful. Sander, you have stepped in hitting the ground running full speed and look forward to working together with you going forward. I am pleased to report that we contracted and reactivated 2 rigs during the first quarter, which resulted in 100% fleet utilization by quarter end. This 100% achievement was remarkable considering this was accomplished while Permian rig counts declined 6 during the quarter. We now have 7 of our 11 rigs contracted with major E&Ps with contracts ranging from pad-to-pad intervals up to 12-month contract terms. Permian rig counts finished the quarter at 241, down 6 from the end of the fourth quarter. WTI began the quarter at approximately $58 per barrel and rose steadily to $67 per barrel through February 28, when the Iran war commenced. Since the Iran war started, WTI has been volatile, trading as high as $113 and finishing the quarter at $111. WTI is currently trading at $90. Our first quarter revenue was essentially flat with improved utilization and lower reimbursables. Adjusted EBITDA, defined as earnings before interest, tax, depreciation and amortization plus noncash stock option expense improved $700,000 to $4.5 million. Our backlog as of yesterday was $23.3 million. Now turning to Page 4. We'll cover recent events and outlook. During the first quarter, we paid dividends of $3.9 million or NOK 0.88 per share. We have announced 2 additional dividends, which constitutes our 42nd consecutive monthly dividend payout. As mentioned on the previous slide, our current backlog is $23.3 million. 7 of our rigs are contracted with major E&Ps, 1 rig is contracted with a top-tier pure-play E&P and 3 are contracted with 2 of the largest and most significant private equity-backed E&Ps. As stated earlier, Permian rig counts declined 6 during the first quarter. However, as of last Friday, Permian rig counts have increased 9 rigs to 250 subsequent to March 31. Based upon current commodity prices and uncertainty regarding the Iran war, we continue to believe that most major E&Ps are maintaining their original 2026 budgets while some private operators are increasing their budgets, resulting in the recent uptick in Permian rig counts. For what it's worth, the inquiries we have been receiving for any available rigs have come from private E&Ps with short-term committed work, but also insinuating that they have more behind it. We continue to believe U.S. shale production has likely peaked at current rig count levels and creates longer-term optimism for Super Spec rigs. Now turning to Page 5. Let's go through DUCs. So as one would expect, E&Ps have one possible option to access more production by tapping any viable DUCs without increasing their operating budgets significantly. While Permian production continues to flatten, the likely decline long term at current rig activity levels, Permian DUCs have declined in half over the last 2 years. Many experts believe there are increasing concerns regarding the economic viability of many of the remaining DUCs. Bottom line is DUCs are becoming an increasingly less short-term solution to address expected production declines. We believe any increase in incremental demand for rigs in both the U.S. and the Permian should benefit our super spec pure-play fleet in terms of both pricing and contract terms. In closing, I would like to thank all of our employees for their hard work and dedication. Our entire team deserves the credit for our exceptional operational performance, which has contributed to the improvement in concentration of major and significant E&Ps operating in the Permian Basin. And now let me turn it back over to Sander for the key operational figures for the quarter. Sander?

Thank you. In the first quarter, we achieved a rig utilization of 90.3%, up from 82.6% in the fourth quarter. Revenues came in at $26.2 million, down from $26.5 million in Q4. Our adjusted EBITDA was $4.5 million, up from $3.8 million in Q4 as a result of reactivation of 2 rigs. All-in fully burdened breakeven, including direct costs, overhead and maintenance CapEx was around $17,900 per day for the working rigs. On the income statement for the first quarter, we had an operating profit of about $3 million compared to $2 million in Q4. In Q1, we had a financial income of $96,000 as a result of interest income and a debt-free balance sheet. First quarter net profit after tax was $2.6 million versus $2 million in Q4 2025. Turning to our balance sheet and cash flow statement. NorAm has a debt-free balance sheet and minimal investment requirements. We ended the quarter with a cash balance of $7.3 million, impacted by working capital increases during the first quarter. We also have available an RCF of up to $4.5 million, where we had no amounts drawn during the quarter. The company paid out $3.9 million or NOK 0.88 per share in monthly dividends in the first quarter and have declared 2 quarterly dividends so far in the second quarter of 2026. We will continue to pay dividends subject to continued positive net cash flow from operations. And now I will hand it back to Marty for closing comments.

Thank you, Sander. In concluding our prepared comments in this presentation, NorAm has a fleet of 11 super-spec rigs fully upgraded with a track record of drilling the longest wells in the Permian and are among the very top performers in terms of drilling efficiency measured by feet per day. We retain a top quality customer portfolio of 5 E&Ps ranging from super majors to smaller private companies in the Permian. The company has an industry-low cash breakeven and minimal investment requirements in the rigs to keep them at the top of the market. We have a clear dividend policy of returning all free cash flow excess cash to our shareholders. Since our listing, we have returned $95 million to our shareholders, equal to about NOK 23 per share, and our latest monthly cash distribution implies an annual yield of approximately 9% as of the closing price yesterday. Thank you for listening to the presentation. We'd now like to open it up for questions from the audience. [Operator Instructions]

We have a question from Marcus Monsen. I'll just unmute you. Please unmute to ask your question.

Congrats with another good quarter and good performance. I was wondering if you could tell a bit more about what kind of contract lengths do you see in the market now? E&Ps looking for shorter contracts, longer contracts? What kind of contracts will you be targeting for the NorAm rigs going forward? What kind of contract lengths?

Yes thanks for the question. So what I would say is this current -- I think somebody else described it as an inflection point in terms of what the operators want in terms of term and what drillers want in terms of day rate. It certainly feels like we're there, although I think it's a little too early to conclude, if it resembles 2022 when the pendulum shifted in the driller's favor, it kind of moved pretty quickly. But it starts with what we've already started to see, which is operators being more interested in longer-term contracts. I don't want to create the perception that anything beyond 12 months is a reality because that's 12-month contract in the U.S. land drilling business is an eternity. But we are seeing many -- all of our customers being much more interested in term contracts, 6 months, 9 months, up to a year. And so we're just going to need to factor that into our analysis. And if we think the market is going up, we're going to expect a day rate increase commensurate with tying the rig up for that period. Otherwise, I think we may be comfortable sitting right where we're at and getting an opportunity to touch the day rate every time there's a renewal if we truly are moving in a positive direction. Hopefully, that answers your question.

Yes, absolutely. Also one more. I was just -- when you look at the figures, obviously, it looks like you still have low cost levels and cash breakeven for the working rigs was actually solid down quarter-over-quarter. Do you see any material changes to costs or CapEx going forward? Or should we expect the current run rate levels?

Yes. Yes. No, that's a great question. And so clearly, we're going to have a much more normalized OpEx run rate, allocating our overhead over 11 rigs rather than, call it, 9.2 or whatever it was. And so how I'd answer the question is, let me start with CapEx. We -- most of the CapEx that we spent in the first quarter was for customer requirements on the 2 rigs that we reactivated. I think we're probably going to be around $1 million of CapEx in the second quarter, which will be a combination of spares and some vehicles for our team. And so as I look into the remainder of the year, I would say, excluding any high torque drill pipe that we may be requested to purchase, which we would expect reimbursement and day rate from our customers or we won't do it. I'm going to still kind of give you an indication that we think we've come in between $3 million and $4 million of CapEx for the year. I don't have any specific knowledge of where the other $2 million will come from in the third and fourth quarter if we, in fact, do it, we may actually come in at $3 million. With respect to OpEx, heretofore, wages have been steady. But as of recent, we have been hearing of increases in wages for other contract drillers -- and so we're looking at that right now. Any increase that we may give, we'd fully expect to be reimbursed through incremental day rate from our customers. And as always, with all the global inflation that's going on, we continue to see items inching up in terms of inflation costs. But where the real pricing impacts you is if you need a -- I'm going to call it a more -- a larger piece of equipment, let's say, a mud pump or an engine. The availability of that type of equipment is becoming less and less. And so that's kind of one of the reasons we bought some spare equipment in the second quarter so far is if there's not much inventory, you can appreciate that the vendors have pricing power to push upon you. And so we work hard at keeping our inventory at levels and not be put in a position to be impacted by significant price increases. So hopefully, that addresses your question.

We also have a question from Truls Olsen. Please unmute your microphone to answer and/or to place that in a question.

Thank you, Sander. I think you can hear me. A couple of quick questions from me. One sort of [ focus ] on what previous speaker talked about. In terms of equipment, but I'm thinking about the larger stuff, I mean -- and you touched upon this in your report, the availability of, let's call it, readily available rigs, and we see that, call it, in other places as well like Argentina. How do you describe that? And how do you think that's going to impact, call it, the ability of the oil companies to react if they want to react?

Yes. And it's -- I think the answer is at least our calculus suggests they're somewhere between 50 to 70 super spec rigs that are primarily controlled by the larger contract drillers, the [ H&Ps ], the Precisions, the Pattersons and the neighbors that are "available." -- how many of those rigs are -- do not require any capital to upgrade, have fully staffed crews and hot and ready to go. I think it's less than about 3 fingers on one hand. There just is not any hot available rigs in the market. So we think best case is it's a couple of million, $1 million to $2 million or $3 million to reactivate a rig, maybe an upgrade or you have to replace an engine that's been sitting in a while. But the much more significant issue and before I go there, so minimum $2 million to $3 million, you probably could spend $5 million to $10 million if you've got to go find 3 engines or 3 mud pumps for whatever reason. So it could be a very costly endeavor. But the largest hurdle, I think, and we experienced in reactivating our 2 rigs is the availability of crews, and there's just not the experience available, ready to come back to work and get after it. And so I think that's going to be a -- not a moat around the castle, but it's going to be a significant governor on how quickly rigs can be redeployed in the market. And as you mentioned, there's a need for -- I think it's YPF in Argentina, they're saying they're increasing their rigs. We're hearing some stuff possibly out of the Middle East. I'm not so sure that all of the international needs for rigs would require a super spec rig. I do think Argentina may be one of those places. And so they may draw a little bit. So that's why I kind of -- even though we've stated in our release that we think as of now, everything is stable in terms of rig count with some modest increases, the second half is really going to drive and determine what happens to day rates and terms on contract. But there's a couple of catalysts out there that if there's any movement, it could be -- it could bode well for NorAm Drilling.

Interesting. And to follow up on another note, how would you characterize the conversations with your clients at the moment? I mean, is it a sense of haste or urgency? Are they sort of playing it a bit coy? Or how would you sort of label those dialogues?

Yes. And it's a fun question. And so first of all, all of our customers, we have very good relationships with. I'm never going to say all customer vendor relationships are a partnership, but it's closer to acting like that than an adversarial role. I think the dynamics right now, both given what's going on in Iran is that there's the fun exchange to get -- to break the ice, if you will, to where a customer will say, 'Hey, we're thinking about giving you a 3-year contract. And we're going, 'Hey, we'd love a 3-year contract and the customer says, well, we'd expect a discount. And we say, well, we'd love to have a big increase in day rates to tie a rig up that long. And they're going, well, you want certainty of backlog. So it's all fun back and forth. But what I think is the real body language that's being signaled is it's not only the current Iran war, it's the -- there's more concern today over the global impact on oil supply and how long it's going to take to recover. And we went from in the first 30 days of the Iran war thinking that, just quit chunk of bombs at Iran and back in Israel, everything will be fine. I think everyone is now concluding it's going to take months, if not years, to recover. And so the conversations with the customers now are picking up in terms of intensity of kind of wanting to make sure they don't lose rigs, which kind of means you may need some term and you may need to do day rate. But not all customers are like that. But it certainly feels like the majority of our conversations are customers are having to operate in their budget. They're wanting to save money. Every oilfield service company is hitting them up for a price increase. And so it's kind of like -- as I like to say, if I walk in my house, all my wife says is I need more money. And so that's where they're at today.

[Operator Instructions] Good. There are -- since there are no further questions in the audience, I would like to thank you for listening to the call. We hope to see you again next quarter, and thank you to NorAm family of employees for the great efforts made during the first quarter. Goodbye.