NE - NYSE

Good morning, ladies and gentlemen, and thank you for standing by. My name is Kelvin and I will be your conference operator today. At this time I would like to welcome everyone to the Noble Corporation's Fourth Quarter 2024 Earnings Call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks there will be a question-and-answer session. [Operator Instructions] Thank you. I would now like to turn the call over to Ian MacPherson, Vice President of Investor Relations. Please go ahead.

Thank you, Kelvin, and welcome everyone to Noble Corporation's Fourth Quarter 2024 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. Today's call will feature prepared remarks from our President and CEO Robert Eifler as well as our CFO, Richard Barker. Also joining on the call is 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 those 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.

Thanks, Ian. Good day, everyone, and thank you for joining us. Today we have three main topics that we will address in our prepared remarks before we wrap up and go to Q&A. First, a summary of our Q4 results, capital return program, and integration progress. Second, our industry market outlook, including our semi-annual review of global deepwater demand, as well as important fleet status highlights for Noble. Third, Richard will discuss our results and 2025 guidance. Following all of this, I'll wrap up with a few concluding remarks. 2024 was another pivotal year for Noble. We completed the highly strategic acquisition of Diamond Offshore, bolstering our strong position in deepwater, and advancing our value proposition for customers and shareholders. We just passed the 150-day integration mark, and we are well on our way to achieving our previously stated synergies of $100 million, approximately half of which have already been realized as of today. I am immensely proud of our global offshore and shore-based teams, who have ensured that the initial and most critical phase of this integration has gone tremendously well. Thank you to all our employees. Your commitment has been crucial as we prioritize our customers' needs throughout this integration and continue to deliver safe and efficient operational outcomes. The fourth quarter was our first full quarter with Diamond, and we had a solid result with Q4 adjusted EBITDA of $319 million. We continue to make major progress with our Return of Capital program. During the quarter, we paid $80 million in dividends and repurchased $50 million of shares, bringing our full year 2024 Return of Capital to over $575 million. Yesterday, our board declared a $0.50 dividend for the first quarter of 2025, consistent with past practices, and I'm pleased to highlight that we have now surpassed $900 million in combined dividends and buybacks since Q4, 2022, including this quarter's announced dividend. We've also had a nice string of contract wins recently, comprising over $500 million in firm commitments, excluding options, which have augmented our 2025 and 2026 contract coverage. These are detailed in our earnings release and fleet status reports, and confirm that recent day rate fixtures for tier-1 drillships have held firm in the mid-to-high 400’s per day. Now turning to the broader industry outlook, including our semi-annual global review of deepwater demand. Overall, we remain encouraged by a variety of positive indicators for deepwater activity over the coming years, both from a macro perspective in terms of the expected rising call on deepwater production, FIDs, and subsea order books, etcetera, and also from the specific dialogue with our customers and the visibility into their future drilling plans. That said, we have seen, of course, the emergence of a mid-cycle lull beginning in the second half of last year, which is carrying through into 2025, in step with the global trend of upstream capital discipline in a comfortably supplied oil market. Consequently, contracted deepwater demand has dipped from about 105 rigs and 94% marketed utilization as of last summer, to 100 rigs and 89% marketed utilization currently. With this downward revision versus how the market was previously trending, we are continuously evaluating the range of scenarios against which to manage and plan our business. We expect UDW contracted demand to bottom slightly lower this year and then to ultimately eclipse recent highs, perhaps 105 to 110 or more rigs by late ‘26 or ‘27. However, recent experience with demand generally slipping to the right also compels us to consider more tempered scenarios as well, with commodity prices and macroeconomic drivers obviously playing a key role in these potential outcomes. Regardless of whether demand lands at 95, 100, or 110 UDW rigs over the near term, we see a diminished call on reactivations of idle capacity for at least the next two to three years. Hence, our recent decision to permanently retire the cold stack to drillships Meltem and Scirocco. In total, we have now effectively removed six rigs from the lower end of our floater fleet, including the Ocean Onyx and Ocean Valiant, which have been scrapped, as well as the Globetrotter I and II, which we are no longer bidding into the drilling market, except for in highly specific niche situations where their unique design features have advantages, for example the Black Sea. Given the oversupply of rigs in today's market, we strongly believe that the rational course is to scrap stacked rigs or sell them into alternative use, rather than selling them as drilling units to secondary competitors. Nonetheless, these retirements will be cash flow accretive, regardless of disposal proceeds, as we expect to shed upwards of $20 million in annualized stacking costs. Throughout our growth journey of the past few years, sideline capacity has never been Noble's brand. We're focused on operating a leading high spec and highly utilized fleet, which we believe is ultimately how we can truly deliver value for our customers and shareholders. And again, based on the recent recalibration of the market, the option value of sideline capacity in this industry has eroded. Now, on to the regional demand highlights. The golden triangle of the Americas and West Africa continues to shoulder over 75% of global deepwater demand. While the U.S. Gulf and South America have remained strong, West Africa has been the primary locus of weaker than expected activity recently. That said, the tangible pipeline of additional rig requirements in the region, which have been delayed by around a year on average, still provides good visibility for a rebound over the next two to three years. Current demand in West Africa is 13 UDW rigs, down from a range of 17 to 20 that prevailed throughout 2023 in the first half of 2024. The keystone markets here are Angola with six units currently and Namibia with four. Open demand in the region includes among numerous other smaller programs, five multi-year tenders with contemplated start dates throughout 2026 and into 2027. This is in addition to several multi-year tenders with similar timing in Mozambique that appear to be approaching imminent FID. Namibia remains a crucial exploration and development play, although we have recently seen the expected FID for the Venus project probably slip from 2025 out to 2026. So overall, while West Africa has been a surprising laggard region over the past year, this looks very much like a transient air pocket ahead of what should be a meaningful and durable uptrend in the years ahead. South America continues to be very strong, and a very important region for Noble, with eight of our deepwater rigs presently contracted throughout Guyana, Brazil, Colombia, and Suriname. Total UDW demand in the region is now up to 42 rigs, which is a current cycle high and up significantly from 35 rigs a year ago. A slow demand from Brazil's 35 rigs looks stable going forward, with positive optionality arising from Brazil and other areas such as Colombia, where there's been recent exploration success, as well as Suriname, with its first field development commencing in 2026. The U.S. has, as expected, remained stable, with 23 contracted UDW rigs today in line with the normal 22 to 24 rig range over the past couple of years. It's also another highly scaled market for Noble, with seven of our deepwater units contracted domestically, including the BlackRhino, which has recently returned from West Africa. Although there is likely to be some additional gap time between contracts in 2025, we expect demand levels to ultimately stabilize around current levels. Now turning outside the Golden Triangle, the Mediterranean and Black Sea have been another stable deepwater market, with nine units contracted currently, in line with the eight to 10 range of the past couple of years. Activity in the region is led primarily by Turkey and Egypt, with a fair amount of current and future planned activity also stemming from Cyprus, Israel, Spain, Libya, and the Black Sea. The Asia-Pacific region after West Africa, has been the other notably softer market over the past six months, and is currently down to five UDW units compared to normalized demand of eight to 10 earlier this cycle. These five units do not include an additional four 6th gen semis in Australia that are not technically UDW rated. The outlook in this region is somewhat mixed. On the favorable side, there is open demand for at least one to two incremental units in India from late ‘25 and into ‘26, in addition to an expected incremental drillship program in Malaysia. On the other hand, most of the bigger programs in Australia are further out into the 2027 to 2028 time frame, according to current plans. Finally, the harsh environment in the North Sea and Norway market currently represents seven units of UDW demand and 20 units of total floater demand, including mid-water, both of which are a few units lower presently compared to 2023 to 2024 levels. There's a fairly high degree of political influence that governs capital deployment in this region, which always complicates forecasting a bit. However, separate from the fiscal and regulatory factors, there are underlying realities surrounding European energy resilience and competitiveness that could eventually support a more predictable upstream investment landscape compared to the current status quo. However, in the meantime, I would also add that the intervention in P&A opportunity set in the North Sea remains a relative bright spot in terms of our fleet positioning. Altogether, incorporating all these regional dynamics, we believe the global deepwater market could potentially see a net demand improvement of up to 10 or more units versus the current 100 contracted rigs by late ‘26 or ‘27. But again, there's always timing variability to consider. So how does this translate for our deepwater fleet status and outlook? Starting with our 14 tier-1 drillships, which are the core earnings engine of Noble, comprising approximately 75% of expected total company EBITDA this year, we currently have one unit available, the Noble Voyager, and another three units that have contract rollovers throughout this year. Our recent pictures for tier-1 drillships have been in the mid to high 400’s per day, and we have a clear line of sight to potentially securing full future contract coverage across these 14 rigs by later this year, with programs commencing in 2025 and 2026. Next, our three D-class 6th Gen semis similarly have a promising outlook, with the Developer and Discoverer now well-contracted in the Americas, and the recently-idled deliverer also well-positioned, we believe, for work commencing in 2026. Our two Globetrotter drillships are being bid toward a number of opportunities in the intervention market. Depending on the outcome of these bids, we'll evaluate whether to remove one of these units from the marketed fleet. And then, as you look at the remaining semis from the legacy Diamond fleet, we've obviously picked up some additional backlog on a few of those units recently, and we will continue to evaluate their longer-term marketability on a case-by-case basis, particularly as SPS and recontracting thresholds dictate. Now, on to jackups. In the traditional North Sea and Norway market, current demand is 27 jackups, and marketed utilization is 93%. We have also had some recent success in deploying our harsh jackups in less traditional markets such as Argentina, Poland, and Spain. When expanding the harsh jackup realm to include these niche markets, the total demand picture is 31 rigs, with marketed utilization of 94%. So, the overall fundamentals are in good shape, despite the disappointing fact that the Norway jackup market remains relatively subdued, which is holding back the potential earnings of our CJ70 rigs. And we do have active and encouraging conversations behind all of our jackups with near-term rollovers, including the Intrepid, Resilient, and Regina Allen. So, I'm going to pause there and turn it over to Richard now to discuss the financials and 2025 guidance.

Good morning or good afternoon all. In my prepared remarks today, I will briefly review the highlights of our fourth quarter and full year 2024 results, provide an update on our synergy progress, and then touch on our outlook for 2025. Starting with our quarterly results, the fourth quarter was our first full quarter as a combined company with Diamond. As such, the type of prior period comparisons we usually reference have less relevance, so I will forego the prior period comps for the purposes of this review. Contract drilling services revenue for the fourth quarter totaled $882 million. Adjusted EBITDA was $319 million, and adjusted EBITDA margin was 34%. Adjusted EBITDA was positively impacted by approximately $40 million related to the early termination of the Noble Deliverer, but was also adversely impacted by approximately six weeks of idle time on the Jerry de Souza at the end of the year between contract scopes. Q4 cash flow from operations was $136 million, net capital expenditures were $134 million, and free cash flow was $2 million, which was burdened with transaction costs related to Diamond, as well as a temporary increase in net working capital, which we expect to reverse in early 2025. For the full year 2024, we generated $3.1 billion in revenue and $1.1 billion in adjusted EBITDA. As summarized on Page 5 of the earnings presentation slide, our total backlog as of February 17th stands at $5.8 billion. Current backlog includes approximately $2.4 billion that is scheduled for revenue conversion during the remainder of 2025. As a reminder, our backlog excludes reimbursable revenue, as well as revenue from ancillary services. Before walking through our 2025 guidance, I would like to provide a brief update on our integration activities related to the Diamond acquisition. We are pleased with how the integration is progressing and the level of buy-in we are seeing across all levels of the organization. And as Robert mentioned, we are making significant strides in realizing our previously announced synergies of $100 million, with just over half on a run rate basis realized to-date. We have a high degree of confidence that the remainder of the synergies will be realized by the end of the year, and we'll have updates on our progress over the next couple of quarters. Referring to Page 10 of the earnings slide, we're providing full year 2025 guidance as follows: Total revenue within a range of $3.25 billion to $3.45 billion, which includes approximately $150 million in other or reimbursable revenue. Adjusted EBITDA between $1.05 billion to $1.15 billion, and capital expenditures, which excludes customer reimbursement of between $375 million and $425 million. The midpoint of this revenue range is approximately 90% supported by Q1 to-date revenues, with firm backlog and options for the remainder of the year. Based on current visibility and contract sequencing, we anticipate Q1 adjusted EBITDA tracking marginally down by around approximately 5% quarter-on-quarter when excluding the Q4 impact of the contract termination. For full year 2025, we anticipate our jackups to contribute approximately 10% to 15% of our adjusted EBITDA. Some other elements for 2025 to consider are as follows: We expect cash taxes to be approximately 12% of adjusted EBITDA, and we expect costs to achieve the remaining synergies relating to the diamond transaction to be approximately $40 million for the full year 2025. Also, we will incur $26 million in BOP lease payments in 2025, although I would like to note that we are currently evaluating terminating these leases when they expire in 2026. Our guidance reflects inflation rates in the range on average of 3% to 4% across various cost components. As it relates to potential tariffs, it's clearly a very fluid situation. Our supply chain team is proactively working with our vendors to mitigate the impacts of any potential tariffs, and some small level of price increases is assumed in our 2025 inflation outlook that underpins our guidance. Despite a more muted near-term outlook, we still expect 2025 to represent a nice step up in free cash flow compared to last year, facilitated in part by lower CapEx following the peak of the five-year SPS cycle in 2023 and 2024 for both the legacy diamond and Noble fleet. And consistent with our past practice, we will look to deploy excess free cash flow after the dividends to share buybacks. With that, I'll pass the call back to Robert for closing remarks.

Thank you, Richard. In conclusion, we remain laser-focused on safe and efficient drilling for our customers, while navigating what we expect to be transitory demand softness over the near-term. Despite some pockets of utilization gaps, we see high-end UDW day rates holding firm in the mid to high 400’s, with a realistic path to higher levels based on plausible demand scenarios over the next couple of years. Fundamental drivers for our business are durable in nature, and therefore this recent contracting law that has pushed things out to the right by a year or two is very likely to be self-correcting before long. And just to state it, nothing has changed in our medium and long-term view about that demand for our services. Regardless, we feel extremely excited about what Noble is capable of producing, either in a flatter world such as we're confronted with today or in a more galvanized up cycle like we hope to see in ‘26 and ‘27 and beyond. Now, I'd just like to wrap up with a word of thanks to our employees. It's always a proud moment to see those closest to the wellhead earn recognition directly from our customers. So hats off to the crews of the Mick O'Brien who recently earned Rig of the Quarter for their outstanding performance for QatarEnergy LNG, and also to the crews of the Noble Valiant, who brought home Deepwater Rig of the Year from Total Energies. These awards are a testament to the strong commitment to safety and performance demonstrated by the men and women on not just these, but all of our rigs, each and every day. So thank you to all. Be proud of what you do. The future is bright at Noble. We're ready to now go to questions.

Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. As we enter the Q&A session, we ask that you please limit your input to one question and one follow-up. [Operator Instructions] Your first question comes from the line of Arun Jayaram of JPMorgan. Please go ahead.

Yeah. Good morning, gentlemen. My first question is on the tier-1 drillship market. You highlighted Robert, that you have some good prospects to get all of your tier-1 drillships contracted maybe later this year, early ‘26. Can you maybe provide a little bit more detail on some of the opportunities for the BlackRhino, the Voyager, and Valiant?

Sure, yeah. Thanks for the question. I guess we won't go into specifics as far as customers or tenders, of course, but I would say that we have a few different programs. I would say there are more with ‘26 starts than ‘25 starts, but with ‘25, with some opportunities in ’25, and those opportunities really I would say cover, or are kind of across the golden triangle that we referenced. Some of those are tenders included in some of the tender stats we've given in the past. Others are direct negotiations. But there is, I would say, an abundance of work out there that's being discussed.

Fair enough. And in the release you highlighted how kind of leading-edge rates for 6th Gen rigs is across a fairly wide band, low 300’s to low 400’s. Help us think about what kind of governs the lower versus the upper end of that band, and how do you expect the market to play out maybe later this year where we're all dealing with this, a bit of an air pocket until you get to longer-term programs in 2026?

Yeah, sure. So I think part of it depends on specific opportunities and the technical needs for specific opportunities. So giving an example, our D-class semi-submersibles, which we classify as 6th Generation rigs, when competing against a drillship are going to need to bid at, I'd say, a higher discount to 7th Generation than when they are needed more specifically, which they are in several instances, actually, that we're discussing right now, where that discount shrinks. So 6th gen, I would say – of course, there's so many definitions now, but 6th Gen I would say probably, also encompasses a slightly wider band of capabilities in terms of the assets in that class, which is part of the reason for that range. And there are always where 7th Gen is preferred, you're going to have higher discounts. And to the second part of your question, we see softness the rest of this year, and generally speaking, like we've seen in times past, I'd say that the asset quality is a big differentiator here when customers have options among a couple different classes of rigs.

Great, thanks a lot.

Thank you.

Your next question comes from the line of Eddie Kim of Barclays. Please go ahead.

Hi, good morning. I just wanted to ask if you could kind of walk through the thought process for us on the decision to retire the Meltem specifically, which I think caught many by surprise. But you know, by all accounts, this was a very high-spec 7G drillship. And while I understand it's not free to stack the rig, at the same time, we have seen some multi-year contracts announced over the past several years, which does seem to pay for that reactivation expense and maybe some of the stacking costs within that initial term of the contract. So just curious, if you could just expand a bit more for us on the thought process related to that decision.

Yeah, sure Eddie. I’d be happy to. So, we watch everything closely and we continuously run numbers on everything, and I think on the Meltem, a couple things stand out. One, I certainly recognize that on paper, it's easy enough to craft a scenario whether that rig could be in the money and that called the option value of continuing to pay the stack costs could work. However, as we said in the script, we see a diminished call in the near term on stack capacity. I mean, UDW numbers are down around 10 rigs here as we move through this year. And so as we look forward, we think that whatever caller there would be on the Meltem has been pushed out several years, at least two or three years. And admittedly that rig as well has actually had never drilled well for a customer that had been activated twice and then deactivated before it had actually drilled. And so we failed to see a likely scenario where that rig – where it would make sense for us to bid that rig, especially considering that the contract durations that we see today and that we think we'll continue to see for a little bit now, given the softness are short enough, where in effectively any situation where we would bid that rig, we would begin bidding it against available active fleet within our own fleet. And so we took the decision, which we think is the right decision to go ahead and move on.

Understood. Understood. That's very helpful. Just my follow-up is maybe just another one on rig retirements. You've taken kind of a market leadership role here in retiring the Meltem. Do you think others might start to see the market in a similar way – others with 7G cold-stacked drillship capacity and might start to retire their own drillships? I’ll maybe ask it in a different way. I guess maybe over the next three years, let's say, what's your estimate of how many 7G drillships or reactivation we could see over that time period? I would imagine it's not anywhere in the four to five range. Is it one to two or could it possibly even be zero?

Yeah, that's kind of a million-dollar question and it requires, of course, a crystal ball. I think I would say, if we use the numbers that we used in our prepared remarks, we're going to need another year to year and a half, to kind of get back to where we wanted to be a year ago. And then from there, of course, there are a lot of macro factors that will determine where we go. I mentioned in my script and I would repeat it, that when we look at all this, that we have a great – a lot of cause for optimism in that late ‘26 and ‘27 and on period. But we've got to work through a lot of active supply before we get to these stacked rigs. And that's why we chose our words carefully, saying that, we think that the call on those rigs has been greatly diminished here recently.

Got it. Understood. Thanks for that color. I'll turn it back.

Your next question comes from the line of Fredrik Stene of Clarksons Securities. Please go ahead.

Hey, Robert and team. Hope you are well. Thank you for good color in the prepared remarks as always. I wanted to touch a bit on 2025 guidance. And in a way, I guess it relates still also to fleet optimization. I think, Richard, you said around 90% of the EBITDA midpoint would be secured by current contracts and options and potentially some extensions, if I heard it correctly. But on the backlog slide, you say that for 2025 you have 55% of available days contracted. So obviously, there's not going to be full utilization of all units as we move through 2025. So you have taken out some of the callback assets now. What are your thinking on taking out or stacking some of your warm assets? And as a side question to that, I would be interested to hear around the Globetrotters I and II. You are saying that they are not being bid into the drilling markets going forward. Can we view those as effectively out of the drilling markets forever? Or do you think they can eventually return? Thank you.

Sure. Thank you. A lot of questions in there, Fredrik. Starting on the optimization side, so you are right. So basically, approximately just over 90% of our top line at the midpoint is in backlog today, right? And so the 65% I think that you are referencing, I think that includes – that does include kind of our cold stacked assets as well. And so as we look forward to 2025, we're basically saying that we've got just under 10% of top line to go get to hit midpoint. There's obviously a cost element to that as well to the extent that we don't find that work. I'll note that if you can go back to 2024 and 2023, I think we're in similar kind of ranges, if you will, from a contract coverage perspective. And I think both years we've managed to actually bid or raise our guidance as well. So I think we feel good about our guidance. Obviously, we've got work to go get in 2025. There's obviously some meaningful amount of kind of white space assumed, especially on our 7th Gen assets in 2025. I think that's maybe why it's lower than where kind of consensus was, but I think those are the key drivers around the 2025 guidance.

And I can speak to the Globetrotters. So we've been saying for a while that we've been chasing the intervention market and we continue to believe those rigs are well suited for that market and we also believe that that market will be a strong and growing market going forward. So in the near term, we've got several open, I'd say, conversations for multi-year work that actually could use both of the Globetrotters that's in the intervention market. We mentioned in the script that there's a couple of little exceptions there, Black Sea, etcetera, where we would consider kind of drilling with those rigs. And I think the standard there is that it wouldn't be cannibalizing our other drilling rigs. But we do not see ourselves outside of those exceptions, chasing the drilling market with the Globetrotters. And we'll look to see how the results of this work that we're chasing. And if for some reason we're having trouble contracting into that market, then later in the year we'll make a decision about whether to further reduce costs on one of those units.

Well, this is very helpful. Thank you very much. And as always, we analysts try to wrap five questions into one, so that's why a lot of words at the start there. We're only allowed one question. So I appreciate you answering my one question, of course. So thank you and have a good day.

Your next question comes from the line of Kurt Hallead of Benchmark. Please go ahead.

Hey, good morning everybody.

Good morning, Kurt.

So, thanks as always, for the color. So Robert, you mentioned that, you think there's going to be a rebound in demand coming off this low in 2025, which is good to hear. I'm kind of curious, then, if you're going to try to connect the dots, right? So you referenced that – you know one of your competitors also referenced that this morning. So it seems like the discussions are definitely happening. With the incremental net demand coming, do you expect there – what kind of pricing improvement would you expect off of 2025 levels on contracts that you are looking to sign in, say, 2026?

Yeah, that's a great question. So I think, my guess is that most people see what we see in terms of this demand. And I'm sure that everyone sees what we see around things getting slightly, just a tiny bit worse before they get better. But I think that the underlying, call it mid to long-term drivers still remain quite strong. And so we gave, I guess, some a couple of facts around where we've seen recent fixtures in the mid to high 400s. So I think that defines the market right now. And I don't know where we go from here, but I do think that the reality is that there is a fair amount of work out there that is pretty evident starting mainly in 2026. So we see, we kind of think about ‘25 as maybe being, just kind of maybe stepping back to 2023 or some sort of analogy like that, where the optimism remains just after a slight dip/flat period rather than the linear up into the run.

Okay. Fair enough. And look, I know you referenced that the jackup business is going to represent somewhere between 10% to 15% of EBITDA as you are going into 2025. Some recent things that I've seen coming out of Norway would suggest a desire to increase drilling-related activity. I know it's kind of a two rate type market, right, jackup and harsh environment semi. So what are you seeing in Norway as it relates to the prospect to get some tailwinds and demand for your jackup assets there?

Yeah. Yeah. So obviously we saw that as well. And we do think that the potential for an additional unit or two of demand on the jackup side in Norway is better now than it's been in several years. So I guess I would say we're hopeful. I would say that that market for us has remained, I would say, almost surprisingly stable considering the political headwinds that everybody faces in a couple of different countries over there, Norway and the UK, and really others as well. So we've actively maintained utilization here in the 90% kind of range. And we're hopeful that we're over the hump in terms of the worst regulatory headwinds, and that we can perhaps improve that from here.

That's great. I really appreciate it. Thank you.

Thanks, Kurt.

Your next question comes from the line of Noel Parks of Tuohy Brothers. Please go ahead.

Hi, good morning. So I was wondering, as this era of strength and pricing, call it post-COVID has continued on. Is sort of the relatively lower visibility that results from saying a year or two ago, having new contracts in place that were going to give you a big bump up in day rate, say from the 200’s into the 400’s or something, as there are fewer of those highly visible increases in the hopper. Because is that sort of influential in you getting just a bit more conservative on your program moving forward?

Yeah, well look, I think rates have been relatively flat for quite some time now in the high 400’s. We had some low 500’s, and so maybe there are more mid to high 400’s now. But I don't know that that's necessarily changed our outlook dramatically. I continue to reference work that's being discussed being contracted that's under negotiation, a lot of direct negotiations out there and still a fair number of public tenders. So I think if there were a program, short-term program that came up for 2025 work, I think, it's pretty obvious that people might be aggressive for something like that, given that assuming people see what we see. But I think what I said previously holds true, that there is a fair amount of work out there that's on the horizon and I think remains supportive of certainly the tier-1 market.

Great, thanks. And I was just wondering, from the producer's standpoint, it sort of seems that by sort of taking the risk, that when they decide to move forward with wells, that they will be able to get the equipment they want without price inflation that's too dramatic. In other words, there seems to be confidence that not everyone is going to be rushing through the door at exactly the same time. I just wondered, it seems to me that also means that they are comfortable sort of assuming that the macro situation in pricing is going to be strong enough, that they don't feel much urgency to sort of bring value forward by being active now, maybe at better rates than they could get a couple years from now. So is there, sort of some embedded macro confidence you see for the longer term as opposed to the near term, that you see from operators when you talk with them?

Well, there is. I mean, I guess there's kind of competing realities a little bit. One reality is that spot pricing today is down $15 or $20 from where it was a year, 18 months ago. And in the kind of middle part of the curve it's down as well. On the other hand, most of what has been taken to FID or what is being contemplated to go to FID has been profitable at levels well below any of the middle part of the curve. And so in my mind there is, and one of the reasons we have so much optimism, in my mind there's plenty of work that is profitable at where the curve currently sits. And I think we're seeing that play through with all this tendering activity that we're talking about, negotiating activity that we're talking about. However, I think we've said in past calls, there is no rush really to make that final commitment, just given, like we mentioned in the script, a pretty comfortably supplied market right now. And so, it's this balance of the work being there, and we believe being profitable, balanced with a catalyst to actually go ahead and commit the dollars and move forward with everything. And I agree with you, to your point, that the general availability, especially on the drilling side. Now that just says, there's some other categories that are a little bit different on supply, but on the drilling side there's supply. So, there isn't really a catalyst on supply constraints [Audio Gap] we'll continue to govern most of the decisions.

Got it. Thanks a lot.

Your next question comes from the line of Josh Jane of Daniel Energy Partners. Please go ahead.

Thanks. Good morning. I wanted to go back to the Globetrotter rigs a bit. You talked about potentially removing one from the marketed fleet, and it sounds like over the next six to nine months, we'll sort of have an answer on that, and based on the number of opportunities you're going to bid those into. My question is, are there any modifications that you potentially may need to make to one of those assets, to make them more competitive in the intervention space? And if so, could you speak to that, just if you are thinking about that over the medium to long term?

No, I don't think anything. Really, the GT2 has NPD, which is really more of a drilling tool. Other than that, most of the intervention equipment is transferable. So, and really, the vast bulk of that package comes from service companies instead of our side.

Okay. Thank you. And then just to follow-up on tariffs, I know in your cost guidance you talked about some level of inflation was assumed. It's obviously a very quickly moving target across a number of geographies, but could you give any more details about maybe upside or downside scenarios for what they could ultimately look like and just how you are thinking about managing that?

Sure, sure, Josh. Obviously, it's a very fluid situation, and then candidly promising that it's impossible to predict like the real impact. It's very likely that tariffs would result in price increases, which are obviously more likely not to be passed onto us as well. And so embedded in our guidance is some level of that inflation, really across the entire cost base in the kind of 3% to 4% type area. We're obviously working as closely as we can with our suppliers around this, but obviously it's an incredibly fluid situation, something that we're managing on a daily basis.

Okay. Thank you. I'll turn it back.

Your next question comes from the line of David Smith of Pickering Energy Partners. Please go ahead.

Hey, good morning. Thank you for taking my question. Yeah, I feel like the U.S. Gulf was one of the bright spots in the deepwater market last year. We saw increasing lead times and good price momentum, but most of the 7th Gen capacity broke through at the end of ‘25, right, by the end of September last year. Contracting really slowed down in Q4. I don't see any contracts for 7th Gen rigs signed in the Gulf year-to-date, and we have some rigs that could be available soon, including, I guess, the Valiant right next month. So, I was hoping you could help what's in color on what you've seen happen in the U.S. Gulf going from a run-on forward availability last year to having some near-term availability of 7th Gen rigs now. And how you are thinking about the Valiant and BlackRhino opportunity sets, and if either has been bid outside the Gulf.

Yeah, sure. I mean, so I guess a couple of things. We continue to see the U.S. as a kind of flat to current in the midterm. We think it's obviously going to dip down a little bit, just look at our own fleet, and so we were disappointed around some of the decisions, drilling decisions, that affected our own fleet. I think probably the difference between our guidance and consensus is explained largely by the BlackRhino, and that's a place where we're really expecting to continue to work through the year. So, I think the U.S. – and look, again these are more, I would say, more independents that are affecting our fleet in the U.S., and I would say that the explanation I gave to the previous question around discipline, current spot pricing, all of what's playing into this, I would say is as pervasive among independents in the U.S. as it is anywhere else in the world. That's a place that can move quickly. There's obvious supply availability, so people can ramp down quickly and ramp up quickly, more quickly in the U.S. than anywhere else in the world, I would argue. So, I think you are seeing that play out here in 2025 for the reasons previously stated. I think West Africa, where things can't be ramped down or ramped up as quickly, really it provides most of the explanation for where we are today versus where we had hoped to be, call it, a year ago. And the good news is that we see a lot of that coming through. We mentioned in the prepared remarks, we do see a lot of that coming through, and we do see, I think, some of the drivers there being, call it regulatory, but perhaps legitimate delays rather than question marks or trying to delay just on account of spot pricing. So, we kind of went through it in the script, so I won't repeat it, but we see all of that work, all potentially coming back as we get into 2026, which is one of the reasons we're perhaps more optimistic than you may have expected here, from this role.

I appreciate it. If I could ask a quick follow-up, I thought Q4 SG&A was surprisingly low given the first full quarter of including the Diamond fleet. Is this a good base level to think of going forward, or was there anything one-off contributing to the low Q4 SG&A figure?

Yeah, I think Dave, I think that's a decent estimate going forward. Obviously, the majority of the synergies in the Diamond transaction are G&A related. As we sit here today, we've realized about 50% of those on a run rate basis, and so hopefully, as we move forward as well, we see some benefit there as well through 2025. And as we sit here today, by the end of 2025, we would expect to realize 100% of the synergies on that deal.

Great. I appreciate it. Thank you.

There are no further questions at this time. With that, I will now turn the call back over to Ian MacPherson for final closing remarks. Please go ahead.

Thanks, everyone, for joining us today. We appreciate your interest in Noble, and we'll look forward to speaking with you again next quarter. Have a great day!