Alright, hi everyone, and welcome to NorAm Drilling's Second Quarter 2025 Results Presentation. My name is Marius Furuly, and I'm the company's Director of Strategy and Investor Relations here at NorAm. With me today, I have the company's CEO and CFO, Marty Jimmerson, in 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 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, 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 undue 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 NorAm continued to deliver operational excellence during the quarter despite Permian rig counts declining 10% during the second quarter. Permian rig counts finished the quarter at 270 rigs, down 30 from the end of the first quarter. WTI began the quarter at approximately $72 and finished the quarter at $67. I believe today we're trading around $64. Revenue was $24.9 million, down $900,000 from the previous quarter as a result of slightly lower utilization. NorAm's fleet utilization decreased to 86.0% from 89.7% in the prior quarter, and I'll comment on that shortly. Adjusted EBITDA, defined as earnings before interest, tax, depreciation, and amortization plus non-cash stock option expense, was $5.3 million, down $1.4 million from the previous quarter.
Adjusted EBITDA was impacted during the quarter by lower utilization, slightly higher repair expenses, and slightly higher insurance cost. Profit after tax was $3.7 million during the second quarter versus $5.2 million during the first quarter. Nine out of our 11 rigs were under contract and working at the end of the second quarter. Our backlog is $12.2 million as of today, with nine of our 11 rigs under contract and working. We expect three rigs to be renewed over the next few days and an additional three rigs to be renewed before the end of September. If you'll flip to the next page, Marius, and we'll cover recent events. During the second quarter, we paid dividends of $5.3 million or NOK 1.24 per share.
Subsequent to the second quarter end, we have announced two additional monthly dividends, and our latest distribution represents our 33rd consecutive monthly distribution since our public listing. As mentioned on the previous slide, our current backlog is $12.2 million. Seven of our rigs are currently operating under contracts of at least six-month contract terms. Two of our rigs are on a pad-to-pad contract and have continued to work, much like term contracts. We did have a second rig stacked during the quarter as a result of E&P consolidation, and we have active discussions ongoing for near-term work. As of last Friday, the Permian rig counts have declined an additional 15 units during the third quarter, or 6% to 255 rigs, as a result of WTI prices, continued economic and geopolitical uncertainties, OPEC's announcement of production increases, and E&P's consistent operating and fiscal discipline that they continue to demonstrate.
While near-term WTI prices suggest flat to slightly down activity levels in the Permian, we do believe U.S. shale production has likely peaked at current rig count levels, and it creates longer-term optimism for super- spec rigs, in our opinion. Flipping to page five, rig counts, as you can see, continue to decline, which indicates lower production ahead. Permian rig counts are now down 50 rigs year-to - date and a total of 100 since 2023. Well completions continue to decline, and this started in early 2024. Also, oil production growth has continued to slow and has been flat over the last several weeks. We are firm believers that we need to see increased rig counts to accommodate material production growth in the Permian going forward.
E&Ps in the Permian continue to high-grade underperforming rigs, and our discussions with customers indicate that 2026 CapEx and drilling plans could result in modest but not significant increases in rig counts at current WTI prices. In closing my opening remarks, I would like to thank all of our employees for their hard work and dedication. We continue to be a top contract driller with our talented employees and ultra super spec rigs. Now let me turn it back over to you, Marius, for a review of our key operational figures for the quarter.
Thank you, Marty. In the second quarter, we achieved a rig utilization of 86%, which was down from 89.7% in the first quarter. We had one rig stacked at the beginning of the quarter and another one ending its contract during the quarter. Both rigs are stacked now in our yard, and we are actively marketing them for new opportunities, including outside of our core market in the Permian. On the revenues, they came in at $24.9 million, which was slightly down from $25.8 million in the first quarter. Our adjusted EBITDA was accordingly down approximately $1.4 million from Q1 due to lower revenue. On the cost side, our repair and maintenance expenses increased from Q1 due to some 10-year certification costs, which resulted in our overall cost base coming in a little bit higher during the quarter.
Our all-in break-even cost per rig per day was $18,600 per day for the working rigs, and the idle rigs are stacked at approximately 30% lower cost than those that are working. On the income statement for the quarter, we had an operating profit of about $3.8 million compared to an operating profit of about $5.2 million in Q1. We had financial income of $51,000 as a result of interest income and as we keep a debt-free balance sheet. The second quarter net profit after tax was $3.7 million versus a net profit of $5.2 million in the first quarter. Turning to our balance sheets and cash flow statements, NorAm continues to have a debt-free balance sheet and minimal investment requirements. We ended the quarter with a cash balance of $7.5 million as a result of working capital reductions and Norwegian tax payments during the second quarter.
We also have available an RCF of up to $4.5 million, where we had no amounts drawn during the second quarter. On the distribution side, the company paid out $5.3 million or NOK 1.24 per share in monthly dividends in the second quarter, and we've declared two monthly dividends so far in the third quarter. We will continue to pay dividends subject to continued positive net cash flow from operations. To conclude this presentation before we start the Q&A session, NorAm Drilling 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 drilled per rig per day. We retain a top-quality customer portfolio of five E&Ps ranging from super majors to smaller private companies.
The company has an industry-level cash break-even and minimal investment requirements in the rigs to keep them at the very top of the market. We have a clear distribution policy of returning all excess cash to our shareholders, and since our listing, we have returned $82.2 million to our shareholders, equal to more than NOK 20 per share. Our last monthly cash distribution implies an annual yield of approximately 13.5% as of the closing price yesterday. Thank you for listening to the presentation, and we would now like to open up for questions from the audience. Please use the Q&A or, if available, the raise hand function to ask a question, and your speaker will be unmuted. I'm sorry, but we have a little bit of technical issues with Microsoft Teams. If it's possible, could you please use the Q&A or the chat function to ask a question? Thank you.
All right. The first question we have is from Trul Olsen of Fearnley Securities. How is their rate looking right now, and how do you feel they will develop going forward?
Hey Truls, how are you? Look forward to seeing you in a couple of weeks. I think overall we've been somewhat pleased that day rates continue to be flat to maybe only slightly down upon renewals. It does feel like there's kind of a floor setting in now that we're seeing fewer rigs being released. I think for day rates to increase, we'll need to see a pickup in rig counts. By everything we're hearing and talking to our customers, we feel like we're going to be very stable with our current day rate environment.
All right. We have another one on the call here who asks, can you say anything about the current backlog? I guess the question relates to the figure of $12.2 million.
Yeah, so our backlog, even though it's at $12 million, which is low compared to what we've been reflecting over the last several months and quarters, is more of just a timing issue. We do have three rigs that we expect to renew this week. They're all working for Oxy, and they've been caught up in the Crown Quest integration into Oxy. We have tentatively agreed on day rate and terms, and I'm very pleased that the terms are of six months, maybe even longer. More to come on that. We're expecting a significant increase in our backlog before the end of this week. We also have three rigs that are scheduled for renewal. We've commenced initial discussions, and we're encouraged that those rigs will be renewed. I think stay tuned over the next 30 days.
We'd expect our backlog to increase before the next dividend call in early September, and then furthermore before the end of September.
Thank you. Thank you, Marty. We also have a question from Marcus Monsen of Pareto Securities, and he asks, as you commented on costs, were slightly higher this quarter than the previous one. Should we assume this level going forward, or can we expect it somewhat lower again going forward?
Yeah, great question. If you take a look back at our run rate of operating cost, we did benefit a little bit in the first quarter with slightly lower R&M. Our second quarter R&M was more consistent with the last three quarters of 2024. We did incur some costs associated with 10-year recertifications of our NOV rigs. We only have one more NOV rig to complete, as well as we did have some slight increases in insurance. While I'm optimistic that our costs will be flat to maybe slightly down, it may take us a little bit of time, but I would expect our R&M to also decline somewhat as a result of having the two rigs stacked, although we're actively keeping those rigs ready to go. Your R&M will be slightly down while they are in the yard.
All right. He also asks, do you have a view on run rate CapEx for 2026, and are there any major costs you see coming over the next 6 to 12 months?
Yeah, yeah, you know, and I think that's kind of one thing that is the secret sauce for NorAm , is whether it's CapEx or operating expenses. We probably are a little bit conservative on what we expense versus what we capitalize. What we do spend on CapEx is typically either for drill pipe, new drill pipe purchases, or spare equipment or vehicles. We don't flood the balance sheet and amortize recertifications over a five-year period. We just take it as a period cost. We've historically said that our guidance is kind of $3 million- $4 million a year of CapEx. We've only spent $1 million through the second quarter. You know, as we like to say, we like to underpromise and overperform. I'm very proud of our team for our operational perspective, which contributes to minimizing our need to spend cash on new equipment.
To answer your question, we are not aware of any major upgrades that are required, and most of our near-term CapEx expense should be associated with either spare equipment or purchases of new equipment, which should result in incremental revenues. I think kind of if I were to look at it, I think we're going to be in the $2 million- $3 million range, worst case, for 2025 for total CapEx, and maybe $3 million- $3.5 million next year, which I would like to think will be conservative. If it is that high, I would expect some incremental revenues for those additional purchases.
What type of purchases could that be, Marty?
Yeah, it primarily would be drill pipe. It is kind of the real needle mover. You know, a string of high-torque pipe could be a couple million dollars. We've been very successful in getting our customers to either rent the pipe or buy the pipe. They kind of like having control of their pipe, and it's more just customer dependent. One thing that I would like to highlight is, over the last two years, I'm very pleased with the high grading of the quality of our customers that we currently work for. We currently have four rigs working for Oxy, one for Conoco, and one for Permian Resources. We're playing with the big boys, if you will, and we have a great relationship with them, and we work together very closely.
All right. Another one that came in here, the rigs that are coming off so far this year, where are these rigs going?
Yeah, I still fully expect that all of our rigs will continue to work in the Permian. You know, that's where they're best suited. We can and have worked in other basins, Oklahoma and Louisiana. I wouldn't mind moving, let's say, one or two rigs to either Oklahoma or Louisiana. Given what Nat Gas currently is doing on the spot market, that doesn't kind of seem like opportunities that the train's leaving the station to pick up rigs. It looks like it's going to be kind of flat. We're going to stay concentrated in the Permian. What I'd like to express is it's not like our phone is not ringing for opportunities, but it's not ringing looking to pick up 10 rigs. We are bidding and looking at opportunities, one rig here, one rig there.
I would like to think that we will be successful in getting the most recent rig that's stacked in the second quarter, getting that back under contract before the end of the year, and then we can focus on our other rig that's been stacked. We thought we were really close to getting the second rig that's been stacked for almost two years now. We thought we were going to put it to work earlier in the quarter. That didn't come to fruition, but all hope is not lost on that rig.
Yeah, that was also from Marcus Monsen again, a little bit related to the previous question, but the wording pursuing opportunities for the two island rigs, including outside of Permian. We mentioned a little bit around it, but could we also comment a little bit further on potential interests that have come from outside of our core market in the Permian?
Yeah, we're not excluding any opportunities. We need to make sure that it makes sense to us. For example, if we were to move one rig to Oklahoma, you know, we're going to have to stand up some semblance of a warehouse and the ability to stage spare equipment. You clearly get more scale doing that. Right now, the market's not such that the customers are going to pay for the mob and demob from the Permian to a new basin and back should they release the rig. Mobilization costs are probably somewhere between $500,000 and $1 million each way. We are also continuing to explore some opportunities outside of the U.S. I don't want to lead anybody along thinking that that's a material number, that we may move three or four rigs internationally, but we are exploring opportunities outside of the U.S. as well.
All right. Looks like there are no further questions in the audience. I think we'll just round off here. I would like to thank everyone to listen to this call, and we hope to see you again next quarter. Thank you to the NorAm family of workers for the great efforts made during the second quarter. Goodbye, and we'll see you again in three months.