Noble Corporation Plc (NYSE:NE) Q2 2025 Earnings Call Transcript

Noble Corporation Plc (NYSE:NE) Q2 2025 Earnings Call Transcript August 6, 2025

Operator: Thank you for standing by. My name is Rebecca, and I will be your conference operator today. At this time, I would like to welcome everyone to the Noble Corporation Second Quarter 2025 Earnings Call. [Operator Instructions] I would now like to turn the call over to Ian MacPherson, Vice President of Investor Relations. Please go ahead.

Ian MacPherson: Thank you, operator, and welcome, everyone, to Noble Corporation’s Second Quarter 2025 Earnings Conference Call. You can find a copy of our earnings report, along with the supporting statements and schedules on our website at noblecorp.com. We will reference an earnings presentation that’s posted on the Investor Relations page of our website as well. Today’s call will feature prepared remarks from our President and CEO, Robert Eifler; as well as our CFO, Richard Barker. We will also have with us Blake Denton, Senior Vice President of Marketing and Contracts; and Joey Kawaja, Senior Vice President of Operations. During the course of this call, we may make certain forward-looking statements regarding various matters related to our business and companies that are not historical facts.

Such statements are based upon current expectations and assumptions of management and are therefore subject to certain risks and uncertainties. Many factors could cause actual results to differ materially from these forward- looking statements, and Noble does not assume any obligation to update these statements. Also note, we are referencing non-GAAP financial measures on the call today. You can find the required supplemental disclosure for these measures, including the most directly comparable GAAP measure and an associated reconciliation in our earnings report issued yesterday and filed with the SEC. Now I’ll turn the call over to Robert Eifler, President and CEO of Noble.

Robert W. Eifler: Thanks, Ian. Welcome, everyone, and thank you for joining us as we present our results for the second quarter. Today, I’ll walk through our financial and operational highlights, recent commercial wins, our perspective on the market, including our semiannual outlook on regional deepwater demand and wrap up with our fleet strategy. Then I’ll hand it over to Richard to cover the financials before I return with some closing remarks and open the line for Q&A. Starting with Q2, we delivered strong financial results with adjusted EBITDA of $282 million and free cash flow of $107 million. Over the past 2 years, our capital return program has been a key element of our strategy. We affirmed that commitment this quarter, returning an additional $80 million to shareholders through our $0.50 per share quarterly dividend.

Yesterday, our Board declared a $0.50 per share dividend for the third quarter, now eclipsing $1.1 billion in capital return since Q4 2022 through dividends and share repurchases. On the integration front, we’re approaching the 1-year anniversary of the Diamond acquisition, and I’m pleased to report that we’ve achieved our $100 million synergy target ahead of schedule. I want to thank the teams across the organization who have made our integration efforts so successful. At this point, the heavy lifting is behind us, and our focus now is squarely on optimization. And I’m proud to say that we have already reached a point where we are truly better than the sum of our parts. Turning to commercial activity. Our contracting momentum continued this quarter.

Building on the transformative awards that we announced in April, we have subsequently secured six new contracts since the last earnings call as detailed in our fleet status report published yesterday. First, on the deepwater front, the Noble Stanley Lafosse was extended by its current customer in the U.S. Gulf for 5 additional wells, spanning approximately 14 months and keeping the rig contracted through August 2027. There is an option for an additional 5 wells at mutually agreed rates. Next, the Noble Viking received a 1-well contract with Total in Papua New Guinea scheduled to commence in Q4 in direct continuation of its Brunei campaign. This estimated 47-day program is valued at $34 million, including mobilization, demobilization and MPD usage, but excluding a modest performance bonus.

This will be the first drillship to operate in Papua New Guinea in over 30 years and the first ever ultra-deepwater rig to do so. We’re honored that Total has entrusted us with this high-impact exploration well, which includes options for 3 additional wells in the region. And finally, on the deepwater side, the Noble Globetrotter I, having recently completed its campaign in the U.S. Gulf, secured a 2- well contract with OMV in the Black Sea. This contract is planned to begin in Q4 with estimated duration of approximately 4 months and a total contract value of approximately $82 million, including a day rate of $450,000 plus mobilization and demobilization fees. The rig’s unique design provides a distinct advantage for transit into and out of the Black Sea.

As a reminder, this Black Sea program is a specific niche market opportunity, but we have otherwise removed the Globetrotters from competitive bidding into drilling programs globally. In addition to these deepwater awards, we also secured several recent contracts in our jackup fleet that highlight the versatility of our harsh environment rigs and our ability to support both traditional and energy transition projects. First, the Noble Innovator was awarded a 6-well contract with BP for the Northern Endurance Partnership carbon capture and storage project in the U.K. North Sea. The program is expected to commence in Q3 2026 in direct continuation of our current contracts with BP at a day rate of $150,000 with a minimum firm term of 387 days plus 2 optional wells.

Subsequently, Noble Intrepid was awarded a 2-well program with BP for additional Northern Endurance Partnership CCS wells, also at $150,000 per day. Intrepid’s contract is scheduled to commence in April 2026 for an estimated duration of 160 days plus options. We’re very proud to support BP with this critical infrastructure project that underpins the U.K.’s carbon storage ambitions. Lastly, the Noble Resilient secured a 92-day accommodation services contract at the Inch Cape Offshore wind farm in the U.K. North Sea. This contract is scheduled to commence within the next few weeks and is valued at approximately $6.5 million for the firm — 92- day firm with options to extend. Year-to-date, we have now secured new contracts with total contract value of $2.8 billion and our total backlog as of August 5, stands at $6.9 billion.

As a reminder, our backlog position assumes 40% of available performance revenue realized on a combined basis under our recent long-term contracts with Shell and Total. We continue to pursue a number of promising opportunities to build on this recent momentum and look forward to sharing further updates as they materialize. Before we move to the market outlook, I’d like to highlight two key contract startups in Southeast Asia and the Americas that required significant planning and coordination to execute safely and on time. I want to thank the teams involved for their hard work in bringing these projects online. First, in the Philippines, the Noble Viking commenced a critical 3-well program for Prime Energy in June to extend the life of a key gas field, an important part of the country’s broader push for energy security and independence.

Following the recent award with Total, the Viking could remain active through most of the first quarter next year if options are exercised with a robust pipeline of future opportunities in the region thereafter. Next, in Suriname, the Noble Developer recently kicked off an important 3-well development campaign for Petronas in July, returning to a region with a growing pipeline of development activity for this class of rig. Now on to the market outlook, including our semiannual review of key deepwater geographic markets. Amidst significant macro uncertainty and upheaval this year between tariffs, Middle East conflict and Brent crude prices that have ranged between the low 60s and the low 80s per barrel, the demand characteristics for offshore drilling have stayed comparatively on trend.

While we have seen intensifying pressure on 2025 upstream CapEx, resulting in incrementally more near-term gaps for rigs, we’ve also seen a crystallization of firming conditions by H2 2026 and into 2027. On the UDW demand side, the global contracted rig count currently stands at 97 rigs, which is roughly flat compared to recent quarters, but down from the recent peak of 105 to 106 during 2023, 2024. We will still probably see a few more idle units over the next few quarters as scheduled rollovers are likely to outstrip visible contract starts and extensions. And this near-term slack in the market continues to pressure day rates, which are now generally in the low to mid 400s per day for Tier 1 drillships. Geographically, the recent deepwater demand trend has been shaped by continuing strength in South America, contrasted with softness in West Africa.

However, visibility for a potential rebound in West Africa is promising and hopefully drawing near. Starting first in South America, where contracted UDW demand stands at 43 total units, including 35 rigs in Brazil, 5 in Guyana, 2 in Suriname and 1 in Colombia. This is a highly important region for Noble as we had 2 rigs working in Brazil and 7 out of the 8 rigs contracted across Guyana, Suriname and Colombia. Visibility throughout the region remains highly encouraging. Starting with Petrobras in Brazil, a strong outlook is supported by recent tenders covering existing development drilling throughout Buzios, Mero and Tupi as well as potential for new frontier exploration activity in the recently licensed Foz do Amazonas Basin further to the north.

These combined with Shell’s recent FID at Gato do Mato, Equinor’s recent drillship tender, very significant recent exploration success from BP announced just this week, plus miscellaneous demand from one or more smaller operators, collectively all frame a very exciting outlook for Brazil for years ahead. Elsewhere throughout South America, we are tracking potential floater programs throughout Suriname Trinidad, Colombia, Uruguay and the Falklands with varying probability and timing factors. So overall, the deepwater market in South America continues to show extraordinary depth and breadth of demand, which should keep the region in growth mode. The U.S. Gulf has softened recently with 21 contracted UDW rigs today, down from 22 to 24 rigs last year.

Depending on how the spot market plays out, we may see activity drop slightly further in the back of this year. Although current indications from customers suggest that the rig count could normalize back towards around 20 UDW rigs next year. That said, demand on the U.S. Gulf tends to be a bit more dictated by spot market drivers and is sensitive in that regard to commodity prices as well. Our primary marketing priority in the Gulf is the Noble BlackRhino, which will finish its current contract in the next month or so. We are constructive on the rig’s long-term outlook in 2026 based on direct conversations we are having with clients. But we would not be surprised to see the rig encounter some near-term white space in the meantime. Next, on to West Africa, where current UDW demand is 12 rigs, similar to recent quarters, but materially below the 17 to 20 range that prevailed throughout 2023 and the first half of 2024.

Angola remained steady at 6 rigs while Namibia and Nigeria had declined to just 1 and 0 rigs, respectively, representing a combined decrease of 6 rigs compared to last year. The good news is that visibility for resumed growth in the region is increasingly tangible. While West Africa and Mozambique comprise only 12% of total deepwater rig count today, the region’s corresponding share of open demand is 2x that level at over 25%. Several prominent IOC tenders appear to be progressing towards contract awards with ’26 and ’27 start dates. These anticipated fixtures should be supportive of a UDW rig count back toward the mid- to high teens or conceivably higher if and when Namibia eventually regains momentum. Namibia for now does not factor us prominently in the near-term open demand picture as other areas like Nigeria, Ghana, Cote d’Ivoire and Mozambique, but it should ultimately progress back towards a more consistent multi-rig basin in the fullness of time.

Additionally, we are seeing potential incremental exploration activity in adjacent South African blocks, which could materialize as early as 2026. The Mediterranean and Black Sea have remained steady with 8 to 9 UDW rigs. However, the big positive surprise in this region recently has been Turkish Petroleum’s acquisition of 2 more drillships from sideline capacity, which will increase their captive fleet from 4 to 6 drillships and add 2 more units of long-term captive demand in the region. Open demand throughout the Med appears otherwise supportive of stable activity levels, excluding the oscillations in the Black Sea and the structurally upsized demand from Turkey. Asia Pacific plus India has remained muted and is now down to 4 UDW units compared to 5 earlier this year and 7 to 8 rigs last year.

Despite the recent decline, open demand for multiple rigs across India, Southeast Asia and Australia suggests a modest upward bias in activity over the next 1 to 2 years, although some of the incremental rig needs are likely to be satisfied by lower-spec equipment. Lastly, the harsh environment North Sea and Norway market currently represents 6 units of UDW demand and 19 units of total floater demand, including mid-water, both of which are down by 1 rig compared to earlier this year. Two of our North Sea semis, the GreatWhite and the Endeavor have rolled off contract recently with no visible work opportunities for the balance of this year. Upstream customer consolidation, policy and fiscal headwinds continue to suppress spending and there has also been some incremental deferral of P&A and intervention programs since earlier this year.

That said, most of the North Sea and Norway floater fleet is copiously contracted into 2027 and beyond. Moreover, there is potential for 1 harsh semi requirement in Canada, which is currently an inactive market. So tying all this together, although the next several quarters continue to be characterized by a variety of pluses and minuses on the demand side, which appear to shake out to a roughly flat market, we continue to believe that the bottoms-up view supports promising upside by late 2026 or 2027, including a very credible path back toward a contracted UDW rig count of around 105, assuming reasonably stable macro conditions. As we have seen over the past 12 to 18 months, timing risk really continues to be the key wild card as many FIDs and rig awards have been drifting to the right.

Hence, our focus on judiciously managing our costs and active fleet posture based on current market realities. Now I’ll comment briefly on our contract position and objectives. We’ve made very good headway toward contracting our 15 high-end drillships. We are now principally focused on the BlackRhino, Viking and Gerry de Souza as key remaining priorities, all 3 of which have very robust opportunities under discussion with customers for programs commencing in 2026. Moving down the fleet, with the decision to dispose of the Globetrotter II, the Globetrotter I still remains in consideration for several multiyear well intervention scopes, which could potentially follow the rig’s Black Sea drilling program. If none of these intervention opportunities come to fruition, then we will likely move to dispose the Globetrotter I as well.

Four of our eight semi-submersibles are well contracted next year. While the Deliverer, GreatWhite, Endeavor are currently idle and Apex rolling next month. We’re pursuing active leads for all 4 of these units around the world with expected starts bearing throughout 2026 and 2027. And each is subject to individual stacking plans over the interim term. We’ll continue to carefully evaluate stacking cost vis-a-vis the opportunity set, especially with the older rigs. Now on to jackups. In our harsh environment Northern Europe market, current demand is 28 jackups. This demand level has fallen off by about 3 rigs compared to last year and forward visibility for 2026 continues to be clouded by fiscal and regulatory headwinds. We are happy with several of our recent contract wins, including additional CCS and wind farm construction support activity in the U.K., in addition to expanding our customer book in Norway with the Intrepid’s DNO contract.

Overall, however, we expect muted market conditions throughout the region to linger until policy-driven impediments are removed, particularly in the U.K. That said, our jackup earnings contribution is disproportionately weighted to our well-contracted units, and we do not anticipate material earnings erosion from the overall jackup fleet segment compared to current levels. Wrapping up. On the supply side, we have recently closed the disposals of the cold-stacked drillships, Pacific Scirocco and Meltem, permanently removing those units from the drilling market. We are now moving forward with the disposal of the Noble Globetrotter II. In addition to the jackup Noble Highlander, for which we have entered into a definitive agreement to sell for $65 million and the jackup Noble Reacher, which is also now held for sale.

For additional context, the Reacher is the lowest capability jackup in our fleet, having worked exclusively in accommodation mode for the past few years and the rig would require meaningful capital to be drilling-ready again. These actions reflect our continued focus on maintaining a high-spec competitive fleet and managing our costs and active capacity as judiciously as possible in order to maximize cash flow for our shareholders. To underscore this point, while we don’t know with exact precision, our best estimate is that the current combined run rate costs for idle/stacking time across the largest drilling contractors is likely approaching $800 million to $1 billion on an annualized basis. By these estimates, idle costs for floaters alone represent a surcharge of around $30,000 to $35,000 per day on average across every one of the working floater rigs in the global fleet.

With our focus on cash flow maximization and returning capital to shareholders, we are taking aggressive actions to reduce Noble’s exposure to this surplus cost burden. In other words, our recent and pending capacity rationalizations are instantly accretive as these units have not contributed positive economics in recent years. And as we look ahead to a near-term flat market with promising upside optionality in the years ahead, we are optimally positioning the fleet for either a flat market or growth market with effectively no relevant earnings attrition. With that, I’ll pause here and turn it over to Richard now to discuss the financials.

Richard B. Barker: Good morning or good afternoon, all. In my prepared remarks today, I will review our second quarter results, provide a brief update on our integration progress and then discuss our outlook for the remainder of the year as well as some high-level perspectives around 2026. Starting with our quarterly results. Contract drilling services revenue for the second quarter totaled $812 million. Adjusted EBITDA of $282 million, and adjusted EBITDA margin was 33%. As expected, Q2 revenue and adjusted EBITDA was sequentially lower, primarily due to planned out-of-service time for the Noble Sam Croft FPS and rigs rolling off contract during the quarter into a softer spot market. Q2 cash flow from operations was $215 million.

Net capital expenditures were $110 million and free cash flow was $107 million. Included in the Q2 free cash flow is approximately $16 million from the closing of the Scirocco sale. The Meltem sale closed in early Q3 for the cash proceeds of approximately $25 million. As summarized on Page 5 of the earnings presentation slides, our total backlog as of August 5 stands at $6.9 billion, which includes $1.1 billion that is scheduled for a revenue conversion for the remainder of the year with $2.3 billion and $1.6 billion scheduled for conversion in 2026 and 2027, respectively. As a reminder, these figures exclude reimbursable revenue and revenue from ancillary services. We’re very pleased with the progress of the Diamond integration and have now achieved our stated synergy cost target of $100 million.

I’d like to echo Robert’s earlier comments and thank our employees for the great work in achieving this milestone ahead of schedule. On fleet management, the moves outlined by Robert around the Globetrotter II, the Highlander and the Reacher, highlights our commitment to managing the business to maximize cash flow. While these decisions are not taken lightly, we can no longer justify keeping these rigs in our fleet when weighing the ongoing stacking costs and reactivation capital against the opportunity set. Referring to Page 10 of the earnings slides, we are updating our full year 2025 guidance as follows: First, total revenue is lowered to a range of $3.2 billion to $3.3 billion. This update aligns with our commentary on the prior call around trending to the lower end of the initial range as we see white space persist in the second half of the year.

Specifically, on rigs we previously thought would see option exercises that did not materialize. Second, the guidance range for adjusted EBITDA is narrowed to the upper end of the previous range, now standing at $1.075 billion to $1.15 billion. This is driven by decent first half results and strong cost management across the business. The lower half of this revised range is effectively fully contracted based on year-to-date results and remaining 2025 backlog. Third, we are increasing capital expenditures, excluding customer reimbursements to a range of $400 million to $450 million. The increase reflects capital tied to the recent long-term awards. The available CapEx for 2025 is expected to total approximately $25 million, with $10 million incurred in the first half.

Looking towards 2026, we currently would expect 2026 capital expenditures to be in the ballpark of around $450 million, which includes the capital required for the recent long-term awards. As we look ahead, we anticipate adjusted EBITDA to decline sequentially in Q3, primarily due to contract rollovers and planned downtime for the Noble Venturer. These impacts will be partially offset by the Noble Developer contract startup in Suriname and the Noble Sam Croft working following her Q2 FPS. If we zoom out and bring 2026 into view, we remain constructive on the long-term market despite white space that is expected to persist well into 2026. Given this, we expect quarterly EBITDA to trend lower over the next 4 quarters relative to the first half of 2025, but expect a material rebound starting in the second half of 2026, supported by the start-up of new long-term contracts in parallel with rising deepwater demand levels.

In the meantime, we are taking a disciplined approach to managing our business that is calibrated to the realities of a nearer-term flatter demand environment. With that, I’ll hand it back to Robert for closing remarks.

Robert W. Eifler: Thank you, Richard. To reiterate, we’re seeing signs that the deepwater market could firm up nicely by the second half of 2026 or 2027, but in the meantime, we are managing the business from a cost and cash flow discipline perspective for the flatter market presently at hand. We remain committed to and confident in a stable dividend. Thus, shareholders in Noble have the unique benefit of being paid to wait for the next leg up in the cycle. While late 2026 is still a ways out and with perennial macro uncertainties and volatility continuing to shape upstream spending, our current backlog, coupled with the active dialogue we’re having with customers on a global basis gives us confidence in soon substantially derisking an annualized free cash flow run rate of $400 million to $500 million by the second half of next year, even in a scenario where current trough levels of demand linger past 2026.

Today, we are keenly focused on securing the very small handful of key remaining contracts that would be necessary to complete that picture, while continuing to deliver the service integrity and value every single day that our customers expect and require from Noble. With that, operator, we’re now ready to go to questions.

Q&A Session

Operator: [Operator Instructions] Your first question comes from the line of Arun Jayaram with JPMorgan.

Arun Jayaram: I was wondering if we could unpack a little bit about around the guidance update, you’re lowering your top line guidance by about 3%, but tweaking higher your EBITDA guide by about 1%. So maybe you could just help us unpack kind of the moving pieces there.

Richard B. Barker: So I think on the last conference call, I think we softly guided to the low end of the revenue range. And you know, I think unfortunately, we had a couple of options or specific options that [ should be decided ] that it’s happening through this year. And so I think that [ talks widely ] because the top line is down. I think also from an EBITDA perspective, I think just strong customer management across the board. [indiscernible] if you will, which is why the top line seems down a little bit at the midpoint of the EBITDA slightly.

Arun Jayaram: Got it. Got it. So cost management, the driver of that. Got it. Got it. Okay. Great. And then maybe for Robert, you highlighted the organization’s focus from a marketing perspective on the BlackRhino, Viking and Gerry De Souza. Obviously, the outlook, which is kind of consistent with your peers is for a broader set of opportunities kind of emerging later in ’26 and ’27. So talk to us about kind of your strategy around those 3 rigs because that can be a decent swing factor as we think about your earnings power next year?

Robert W. Eifler: Yes, sure. And that’s right. We’re highly focused on those 3. I mentioned at the end of my prepared remarks where we think we can get run rate in having probably 2 of those 3 contracted [ as it is ] a key part of that. What I would say is we have a very strong line of conversation behind all 3 of those rigs. And I think that, that fits in — while we’ve had perhaps a slightly more muted tone on the outlook — on the market outlook, we do see the big projects going through definitively and we are extremely encouraged by the level of conversations we’re having around bigger projects and in search of the higher quality rigs. So I think what we’ve seen — and [ this was ] the question, but I think what we’ve seen here, especially in the last 3 months, is a little bit of a disappointing level of demand at the lower end spectrum of rigs globally, but with very little change on demand for the higher-end rigs.

Operator: Your next question comes from the line of Fredrik Stene with Clarkson Securities.

Fredrik Stene: So I wanted to touch a bit first, a bit more specifically on Brazil. Clearly, you have, as you said in your prepared remarks, quite a decent exposure to South America in general. But right now, there are several tenders, etc, going on down in Brazil, Buzios, [indiscernible], Tupi, etc. You have I think, 1 rig rolling off in late ’26, 1 in early 2027. How do you think about the recontracting opportunities for those units in particular? And are you planning to keeping them down in Brazil?

Robert W. Eifler: Yes. So I think we think about Brazil is at worse, flat and more likely, probably up a rig or 2 on rig demand. Obviously, with 30 of the 35 rigs in country, Petrobras will be the one who determines that .Then there, I think the narrative from them is positive. You’ve got the Buzios tender right now, and there are a lot of moving parts. They firmed off a handful of rigs already. But the way they kind of shape that tender and then move forward from there is very important, and it’s just a little bit too early, I think, to have of kind of, I guess, a factual opinion on where they go. But we’re planning for Petrobras to effectively be flat on rig count through time and then with some upside, as we mentioned, outside of Petrobras in Brazil. So we’re pretty — and then obviously, further north, there’s a an immense amount of activity. It’s a core region for us. And so we think South America right now is certainly a bright spot on the demand side.

Fredrik Stene: Okay. That’s very helpful. And then turning to supply. You have 3 rigs announced today that your holding for sale, one being in the definitive agreement already. The 2 others, I — maybe you said it in the prepared remarks, but are those targeted to be retired from the drilling fleet? Or are you potentially selling to, call it, competitors or niche markets where you don’t have any presence? And as an add-on to that, you also talked about rigs in your fleet now having, call it, individual stacking plants, etc, if there is prolonged downtime. But if you don’t find opportunities for some of those rigs, can you identify potential further retirement candidates also beyond the Globetrotter I, as you mentioned.

Robert W. Eifler: Yes. So the Highlander will go to a drilling project, and we don’t have a conclusion on the Reacher or the GT II, but we would not anticipate those are sold for drilling purposes. So we would not anticipate that the Reacher or Globetrotter that we would be competing against those later. The Highlander well go to drilling. I would reiterate on the second part of your question, what we’ve done already with the Meltem and the Scirocco, and we mentioned that the Globetrotters, those are effectively competing for intervention work with the sole exception of 1 or 2 places in the world that really need the Globetrotter capabilities for drilling the likes of Black Sea. And then I think being rational on the jackup side as well, we’re just big believers that the option value of hoping for a better market at present is more expensive than it has been in times past.

And we’ve said for years that we’re running this company to generate cash and our fleet rationalization policy has been really in keeping with that. So what else could be out there? We mentioned the GT I but I think from there, if we’ve done what we think we need to do. Obviously, we can be — we’ll continue to be rational and we’ll continue to look forward at what we see and specific opportunity set for a given rig and make decisions, and continue to be rational as we move forward.

Operator: Your next question comes from the line of Eddie Kim with Barclays.

Eddie Kim: So you provided a very constructive medium-term outlook in your walk through the regions but indicated some near-term kind of softness here. We’ve seen leading edge day rates on recent [ Mota ] contracts in the low 400s. Just curious on your expectation on where that pricing could go for upcoming contracts later this year. Do you think rates kind of hold firm here in the low 400s? Or could they even see a downtick lower, just given the near-term softness we’re seeing right now? Just curious on your thoughts there.

Robert W. Eifler: Yes. I mean, I think — thanks, Eddie. I think rates are in low mid 400s like you said. There hasn’t — to my knowledge, there hasn’t been a single example of a 2 BOP Tier 1 rig below that range. Our outlook is that there should be some incremental rigs demand by late ’26 hopefully, and I can’t imagine someone dropping rates with that outlook, but who knows? I do you think you have — because of the — you’ve got a little bit of a funny dynamic where there’s a number of big projects coming on in late ’26 and ’27, with probably a drop in demand in the interim. So people like to talk about gap filler work, that kind of stuff, who knows. I think you could have some lower rates. But I think — I don’t think that’s representative of a broader market view if you pull in late ’26 and ’27 earnings potential.

Eddie Kim: Got it. That’s very helpful color. My follow-up is somewhat related. I think you said in the prepared remarks that there’s a very credible path back to UDW rig count back up to 105, I think towards the back half of next year, assuming stable macro conditions. Fair to say that there is also a very credible path back to leading-edge day rates sort of in that mid- to high 400s level on contract announcements we might see in the back half of next year?

Robert W. Eifler: It’s a great question. I wish I knew the answer. I think the way we view it is that we’re in a little bit of a lull that’s been created by a lot of macro noise right now. So if you want to — I would make the claim that if we’re now just below 100 working rigs on the floater side, on the UDW side that perhaps — we just take the Brent curve that perhaps kind of the normalized demand level with current Brent curve, which should be 100 to 105, that kind of range. And we’ve counted up projects and I think see a path to the higher end of that range. So yes, I think that is at a minimum stabilization, and there is absolutely a path where rates tick back up from here. We’re going to have to wait and see what happens in the interim.

You can map out of a relatively large slice of the demand through big projects. But there is always just enough other out there that makes these things pretty hard to predict. And I kind of mentioned it earlier around the lower spec — the demand requiring lower spec assets. But in my opinion, it’s the other that’s created a softer market here recently than I think anyone was anticipating. So it’s a little early for these prediction, but we’re certainly hopeful here that we get back to a much more normalized level by the end of next year. And then I guess I would add on the thoughts that we kind of made in the prepared remarks, but we just feel very strongly that with our fleet, our current contract set and then a pretty limited need for additional contracts that we can set ourselves up here for some pretty meaningful cash flow.

We mentioned $400 million to $500 million in the prepared remarks with effectively a flat market from here, even maybe day rates down a small tick. But effectively, if what we see now is the new reality, we still think that we can generate meaningful cash flow for our investors and we’ve given a lot of data out for cause for optimism that we would actually be up from that.

Operator: Your next question comes from the line of Greg Lewis with BTIG.

Gregory Robert Lewis: Yes. I feel like I asked this like once a year, but could you kind of remind us the timing of the Exxon rig resets and then maybe how we should be thinking about that? I believe it’s in October, how we should be thinking about that versus, say, where it was, when it was reset, I guess, a few months ago?

Robert W. Eifler: Yes. It’s March 1 and September 1 are the dates that the new rates go into effect. And so those rates are respectively set 3 to 5 months prior to when they go into effect. I would say that, that mechanism has worked extremely well and it has tracked the market since we came up with the CEA. And so you’re talking about a September rate that will go into effect that was set 2 or 3 months ago, and so we don’t give the rates out, but I think there’s obviously [ hopeful ] ties. And I think that, that mechanism has really tracked the market very closely.

Gregory Robert Lewis: And then — and I felt like, Robert, you mentioned kind of dual BOP, which is what those are. So it’s safe to assume that excludes kind of like a — it definitely sounds like it excludes sixth-gen rigs, but maybe even lower end seven-gen rigs?

Robert W. Eifler: That’s correct. That’s absolutely…

Gregory Robert Lewis: Okay. Great. And then I did have a broader question. Obviously, there were some big news yesterday with some consolidation in the jackup market. Clearly, the acquirer has not historically operated in the North Sea. Does this — M&A is sometimes good for a sector sometimes bad. Any kind of view on how this impacts the jackup market and realizing you’ve been scaling down your jackup fleet over the last couple of years, but any kind of view how — does this do anything to change how you’re thinking about your jackup fleet post that M&A deal?

Robert W. Eifler: No, not really, honestly. I mean, we have the 3 rigs outside of the North Sea that we’re marketing aggressively. And then yes, there’s obviously some overlap with the North Sea in this M&A deal. But we’re — it doesn’t change our demand — I mean, sorry, [indiscernible], but honestly, no, it doesn’t do a whole lot to change our views on anything. I’m happy for the companies, and I think it was probably a great deal and win-win, but it doesn’t really — I don’t think it spurs action from our side necessarily.

Operator: Your next question comes from the line of Doug Becker with Capital One Securities.

Douglas Lee Becker: Robert, you’ve laid out that Q1 drillships are still in the low 400 to mid-400 range. Have you seen any material changes to some of the other factors that can affect economics like mob or demob fees or capital reimbursements. Just trying to look a little deeper in terms of the economics in the current environment.

Robert W. Eifler: Yes. I mean, look, contract terms are effectively correlating with day rates. However, I would say that if you’re talking about a wider spectrum of potential day rates, so the awful years that had 2 handles on them all the way over to kind of some world with 5 handles where there is the true shortage of rigs. I don’t think the change between high 400s and low 400s is particularly meaningful on the broader contract term scale. So yes, there will be a bit of economic leakage probably today versus when we were knocking on the 500 door. But I don’t think that’s a meaningful change so far.

Douglas Lee Becker: Fair enough. And you’ve touched on this a little bit, but just on some of the options that are outstanding, just any general commentary in terms of option exercise as we think about those rigs going forward.

Robert W. Eifler: Yes. I think we made the assumption for 2 or 3 years that all options would be exercised. And I think today, we will make the assumption that I’m just — I have no idea, I’m just going to throw, out 50% to 75% are exercised and hopefully towards the higher end of that. But maybe another way to put that is that there’s definitely going to be — if you look across the full industry spectrum of options. There’s going to be a non-negligible number that probably are not exercised. We suffered from that a little bit on our 2025 numbers, where mid- to late last year, we were quite certain that a couple of them would be optioned — would be exercised that ultimately were not.

Operator: Your next question comes from the line of David Smith with Pickering Energy Partners.

David Christopher Smith:

Pickering Energy Partners Insights: So a lot of mine have been answered. I’m going to step back with just a little bigger picture question. In past cycles, we typically saw floater contract lead times move in tandem with utilization and backlog. In the past few months, we’ve seen operators locking in multiyear contracts with 12- to 24-month lead times even as near-term demand looks softer and the rig count trends lower. It’s creating multi-quarter gaps between contracts for some rigs, a dynamic that seems fairly uncommon compared to prior cycles. I was curious if this strike you as unusual. And if you have any thoughts on what is driving that out-year contracting behavior?

Robert W. Eifler: Yes, that’s a great observation, Dave. And we agree with you. I mentioned earlier a little bit that it is kind of a unique — because we’re asked about day rates, and it is a little bit of a unique situation where I think whether you’re talking to a drilling contractor or a service company, everybody sees some demand on the horizon here in late ’26 and ’27. And there’s been a disconnect between some long lead provider and the national service providers for some time. And so it is creating a kind of a different situation than we’re accustomed to. I think that part of this is — look, our understanding is that for these — all the projects that are being sanctioned and moving forward, obviously, the math works here in the kind of 60s range for Brent.

So I think you’re seeing that dynamic play out as major projects move forward. And I think you’re seeing that on the back end of so much noise, macro noise and also a persisting commitment to capital discipline for our customers that it’s creating slightly different dynamics than what we’re used to. And the core — you’re right, the correlation on lead time has kind of fallen apart here. But we take all that as a good sign. We went through the global view, and we’re optimistic that we can get back to what I would call a more normal level for — a more normal level of activity, kind of 100 to 105 working UDW rigs.

David Christopher Smith:

Pickering Energy Partners Insights: I appreciate it. And a follow-up if I may. Just kind of relates to Eddie’s question earlier. But for the rigs that are facing multi-quarter gaps between firm term contracts. Do you see a risk that bidding strategies become more aggressive to fill in those gaps? And if so, do you think that more competitive pricing for short-term and near-term work might influence broader pricing expectations or do you think it’s just going to result in a greater bifurcation for short-term, near-term versus longer-term work?

Robert W. Eifler: Yes. I mean, for sure, I think you’re going to see gas sort of work where people are willing to take almost any price or take a discount, maybe a better way to say it, but I just don’t think that affects the broader pricing strategies for the companies. I don’t think it will affect ours. And I think back to this funny dynamic we have right now, everybody sees it, and we’re one of the last to go on this earnings season and whether you’re talking about drilling, tractor or a service company, everyone is talking about the same dynamics. And so I think that’s really meaningful and important. And I think people are going to price as they see the market and people generally see a bit of an uptick here in starting late ’26. So I think of the gap filler stuff as more noise than I do of something that’s going to drive rates.

David Christopher Smith:

Pickering Energy Partners Insights: Really appreciate the color. Congrats on the quarter and the better cost outlook.

Operator: Your next question comes from the line of Noel Parks with Tuohy Brothers.

Noel Augustus Parks: I was wondering just given some of your comments about the marketplace so far, do you see — or have you considered any revisiting of the maintenance and upgrade schedule as you look at what’s still some near-term uncertainty about white space being taken up balanced against, as you pointed out, the pretty consistent industry optimism in ’26 and ’27.

Robert W. Eifler: Yes. I think what I would say is we’ve — we talked earlier, of course, about rationalization of the fleet and our view on that and the carrying cost of some of this “option” value. You’re asking more specifically about the working rigs. And so I would say that we had — we haven’t brought revenue down, EBITDA. And so we’ve managed costs very closely. And we — in the previous call, we mentioned that we kind of take — if you want to divide things up between 6-month readiness and 1-year readiness, that kind of view. We’ve kind of taken a 6-month readiness on a couple of units, which we think is a good balance between present costs and marketability. And we feel we’ve been highly focused on managing costs, and we’re happy with the decisions we’ve made around the — really more on the flow side on the couple of units that we seek work for, but maybe with a bit of a gap before that work starts.

Noel Augustus Parks: Great. And I’m just wondering if with BP’s announcement of their big discovery at Boomerang offshore Brazil. Do you have any sense of whether that might help sort of affirm or accelerate what we’ve seen as a little bit of a positive drift towards exploratory dollars and drilling in the industry.

Robert W. Eifler: Yes. I mean all discoveries are good for our business. And my longer-term view is very firm around the need for oil and gas produced from offshore wells. There is a gap that we will eventually get to, have to assume an oil demand, obviously. But if history is any guide, I think I’m very confident that there’s a gap between discovered barrels and needed barrels coming from offshore and we thought that dynamic might start playing out this year. It’s been pushed off to the right. There’s a lot of macro noise, but I remain extremely confident that the need for our services to increase offshore production is imminent and will come in the next few years. So you’re starting to hear more about reserves, reserve life, reserve replacement from our customers.

And I think this is one of our biggest customers and them highlighting that this is the best exploration year in 10 years, I think is another data point that there is a meaningful shift back to offshore globally that’s happening right now.

Operator: At this time, there are no further questions. I will now turn the call back over to Ian MacPherson for closing remarks.

Ian MacPherson: Thank you, everyone, for joining us today. We appreciate your interest, and we look forward to speaking with you again next quarter. Have a good day.

Operator: Ladies and gentlemen, that concludes today’s call. Thank you all for joining. You may now disconnect.