Participants

Ian Macpherson; Vice President - Investor Relations; Noble Corporation PLC

Robert Eifler; President, Chief Executive Officer, Director; Noble Corporation PLC

Richard Barker; Chief Financial Officer, Senior Vice President; Noble Corporation PLC

Aaron Rosenthal; Analyst; JPMorgan

Eddie Kim; Analyst; Barclays

Fredrik Stene; Analyst; Clarksons Securities

Kurt Hallead; Analyst; Benchmark

Noel Parks; Analyst; Tuohy Brothers

Josh Jayne; Analyst; Daniel Energy Partners

David Smith; Analyst; Pickering Energy Partners

Presentation

Operator

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. (Operator Instructions) Thank you.
I would now like to turn the call over to Ian MacPherson, Vice President of Investor Relations. Please go ahead.

Ian Macpherson

Thank you, Kelvin, and welcome, everyone, to Noble Corporation's fourth-quarter 2024 earnings conference call. You can find a copy of 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.

Robert Eifler

Thanks, Ian. Good day, everyone, and thank you 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 semiannual 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're well on our way to achieving our previously stated synergy of $100 million, approximately half of which have already been realized as of today.
I'm 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 report and confirm that recent day rate fixtures for Tier-1 drillships have held firm in the mid to high 400s 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, et cetera, 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 temporary 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 stacked 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 a highly specific niche situations for 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 stack 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 over 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 the regional demand highlights. The Golden Triangle of the Americas and West Africa continues to shoulder over 75% of global deepwater demand. While the US 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 has 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 and 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 multiyear tenders with contemplated start dates throughout 2026 and into 2027. This is in addition to several multiyear 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 slipped 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. Base load demand from Brazil 35 rigs look stable going forward with positive optionality arising from Brazil and other areas such as Colombia, where there has been recent exploration success as well as Suriname with its first field development commencing in 2026.
The US 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 Black Rhino, 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 9 units contracted currently, in line with the 8 to 10 range over 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 5 UDW units compared to normalized demand of 8 to 10 earlier this cycle. These 5 units do not include an additional 4, 6 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 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 and P&A opportunity set in the North Sea remains a relative bright spot in terms of our fleet positioning.
All together, 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 to 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 drillship have been in the mid- to high 400s 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. These programs commencing in 2025 and 2026.
Next, our 3D Class 6 gen semis similarly have a promising outlook with the developer and Discover now well contracted in the Americas and the recently idle deliverer also well positioned. We believe for work commencing in 2026. Our 2 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 the jackups. In the traditional North Sea and Norway market, current demand is 27 jackups and marketed utilization of 93%. We have also had some recent success in deploying -- more 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 market 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 CJ-70 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.

Richard Barker

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 period comparisons we usually reference have less relevance. So I will forgo 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 [Jerry Susa] 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 slides, our total backlog as of February 17 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 revenues 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 of 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.
We're flowing to Page 10 of the earnings slides. We're providing full year 2025 guidance as follows: total revenue in the 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 in capital expenditures, which excludes customer reimbursements of between $375 million and $425 million. The mid of this revenue range is approximately 90% supported by Q1 to date revenues but 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 jackup 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 cost to achieve the remaining synergies related 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 leaders 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 5-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 dividend to share buybacks.
With that, I'll pass the call back to Robert for closing remarks.

Robert Eifler

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 400s 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 role 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 the demand for our services.
Regardless, we feel extremely excited about what Noble is capable of producing either in a flatter world such as were confronted with it 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 this 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 Qatar Energy 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 to go to questions.

Question and Answer Session

Operator

(Operator Instructions) Aaron Rosenthal, JPMorgan.

Aaron Rosenthal

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 more detail on some of the opportunities for the Black Rhino, Voyager and Valiant?

Robert Eifler

Sure. Yes. Thanks, 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 future 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, for are kind of across the golden triangle that we referenced.
And so 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.

Aaron Rosenthal

Fair enough. And in the release, you highlighted how kind of leading-edge rates for 6 gen rigs kind of is across a fairly wide band, low 300s to low 400s. 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 a bit of an air pocket until you get to longer-term programs in 2026?

Robert Eifler

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

Operator

Eddie Kim, Barclays.

Eddie Kim

I just wanted to ask if you could kind of walk through the thought process for us on the decision to retire that the Meltem specifically, which I think caught many by surprise. But 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-tract 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.

Robert Eifler

Yes. Sure, Eddie. So we watch everything closely, and we continuously run numbers on everything. And I think on the Meltem. A couple of things stand out.
One, I certainly recognize that on paper, it's easy enough to craft a scenario where that rig could be in the money in that, call it, the option value of continuing to pay the stack costs could work. However, as we said in the script, we see the diminished call in the near term on stacked capacity. I mean, you need -- UDW numbers, excuse me, are down around 10 rigs here as we move through this year. And so as we look forward, we think that whatever color 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 never -- had never drilled a well for a customer to have been activated twice and then deactivated before it had actually drilled.
And so we failed to see a likely scenario where that rig 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 be 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.

Eddie Kim

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 reactive 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. So maybe ask it in a different way. And I guess, maybe over the next three years, let's say, what's your estimate on how many 7G drillships -- reactivations we could see over that time period? I would imagine it's not anywhere in the 4 to 5 range -- is it 1 to 2? Or could it possibly even be 0?

Robert Eifler

That's kind of the million-dollar question. It requires, of course, a crystal ball. I think I would say if we use the numbers that we used in our prepared remarks -- were you going to need another year to 1.5 years to kind of get back to where we want it to be, call it, 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 of this, that we have a great -- we have a lot of cost for optimism in that late '26 and '27 and on period.
But we got to work through a lot of active supply before we get to the step rigs. And that's why we chose our words carefully saying that we think the call [on to 3] has been greatly diminished here recently.

Operator

Fredrik Stene, Clarksons Securities.

Fredrik Stene

Robert and team, I hope you are well, and thank you for good color in the prepared remarks, as always. I wanted to touch a bit on 2025 guidance? Any way, I guess it relates still also to fleet optimization. I think Richard, you said around [0.9] of the EBITDA point would be secured by current contracts and options and potentially some expansions if I heard it correctly. But on the backlog slide, you say that for 20%, 25% -- sorry, from 2025, you have 55% of available base 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 contact 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 market going forward?
Can you view those as effectively out of the drilling market forever? Or do you think they can eventually return?

Richard Barker

Sure. A lot of questions in there, Fredrik. Starting on the -- side. So you're right. So basically, approximately actually just over 90% of that top line at the midpoint is in backlog today, right?
So 65%, I think that you're 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 the 10% of top line to go get to a 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 go back to 2024 and 2023, I think in a similar kind of range -- billings, if you will, from a contract coverage perspective. I think both years, we've managed to actually rate intolerance as well.
So I think we feel our guidance, obviously, we up to go again in 2025. There's obviously some meaningful amount of kind of white space assumed, especially in our 7 gen assets in 2025. I think that's maybe why it's lower than where kind of consensus was. And I think the key drivers around the 2025 guidance.

Robert Eifler

And I can speak to the globe chatter. 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 multiyear work that actually could use both of the Globetrotters, so that's in the intervention market. We mentioned in the script that there's a couple little exceptions there, Black Sea, et cetera, where we would consider drilling with those rigs in 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 and then later in the year, we'll make a decision about whether to further reduce costs on one of those units.

Fredrik Stene

This is very helpful. Thank you very much as always, beyond tried to wrap five questions into one. So that's why (inaudible) I will 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.

Operator

Kurt Hallead, Benchmark.

Kurt Hallead

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 got to try to connect the dots, right? So you referenced that one of your competitors also referenced that this morning. So it seems like is definitely -- 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.

Robert Eifler

Yes. That's a great question. So I think most -- 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 tying it 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, 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 flash flat period rather than the linear things of the run.

Kurt Hallead

Okay. Fair enough. And then -- and look, I know you referenced that the jackup business is going to represent somewhere between 10% to 15% of EBITDA as you go 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 semis.
So what are you seeing in Norway as it relates to the prospect to get some tailwinds in demand for your jack-up assets there?

Robert Eifler

Yes. Yes. 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 effectively maintained utilization here in the 90% kind of range. And we're hopeful that, that we're over the hump in terms of the worst regulatory headwinds and that we can perhaps improve that from here.

Operator

Noel Parks, Tuohy Brothers.

Noel Parks

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

Robert Eifler

Yes. Well, look, I think rates have been relatively flat for quite some time now in the high 400s. We had some low 500s. And so maybe they're more mid- to high 400s now. But I don't know that -- 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 for 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 price and I think, remains supportive of certainly the Tier 1 market.

Noel Parks

Great. And I was just wondering from the producer 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 a -- 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 exactly the same time. I just wonder -- 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 any -- or 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 of years now. So is there sort of some embedded macro confidence you see in -- for the longer term as opposed to the near term that you see from operating -- when you talk with them?

Robert Eifler

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, $20 or where it was a year or 18 months ago. And the kind of middle part of the curve is down as well.
On the other hand, most of what had been what has been taken to FID or what is being contemplated to go to FID has been profitable and let us well below any of the middle part of the curve. And so in my mind, there is -- other 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 these 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 uncommitted. 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 continue forward with everything.
And I agree with you to your point that the general availability, especially on the drilling side, not -- some other categories that are a little bit different on the supply. But on the drilling side, there's supply, so there isn't really a catalyst on supply constraint right now. And so we think that for 2025, that the discipline certainly will continue to govern us of the decisions.

Operator

Josh Jane, Daniel Energy Partners.

Josh Jayne

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 put 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're thinking about that over the medium to long term.

Robert Eifler

No. I 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. And really, the vast bulk of that package comes from service companies instead of our size.

Josh Jayne

Okay. And then just to follow up on tariffs. I know in your cost guidance -- 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're thinking about managing that.

Richard Barker

Sure. Sure, Josh. Obviously, it's a excellent fluid situation, and we candidly -- impossible to predict like the real impact -- it's very likely that times would result in the price increases, which was more likely not to be passed on to us as well. And so embedded in our guidance is some level of 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.
We've been in our suppliers around this, but obviously, it's an incentive fluid situation, something that we're managing on a daily basis.

Operator

David Smith, Pickering Energy Partners.

David Smith

Like the US Gulf was one of the bright spots in the deep water market last year, right, we saw increasing lead times and good price momentum with most of the 7 gen capacity booked through the end of '25, by the end of September last year. Contracting really slowed down in Q4. I don't see any contracts for [seven rigs] signed in the Gulf year-to-date. And -- that could be available soon, including, I guess, the Valiant next month.
So I was hoping you could help with some color on what you've seen happen in the US Gulf going from a -- run on forward availability last year to having some near-term availability of [seven-year] rigs now? And how you're thinking about the Valiant and Black Rhino opportunity set and if either has been bid outside the Gulf?

Robert Eifler

Yes, sure. I mean -- so I guess a couple of things. We continue to see the US as 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 Black Rhino. And that's a place where we really expect to continue to work through the year.
And so I think the US -- and look, again, these are more, I would say, more independents that are affecting our fleet in the US. And I would say that the explanation I gave to the previous question around discipline and current spot pricing, all of what's playing into this. I would say is as pervasive among independents in the US as it is anywhere else in the world.
That's a place that can move quickly. There is obvious supply availability. So people can ramp down quickly and ramp up quickly more quickly in the US than anywhere else in the world I would argue. And so I think you're seeing that play out here in '25 for the reasons previously stated.
I think the West Africa, where things can't be ramped down or reach up as quickly, really 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 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 are trying to delay just on account of spot pricing. So we kind of went through a script. I will repeat it, but we see all of that work all potentially coming back as we get into '26, which is one of the reasons we're perhaps more optimistic than you may have expected here in the call.

David Smith

I appreciate it. And 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 go forward? Or was there anything one-off contributing to the low Q4 SG&A figure?

Robert Eifler

Yes. 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 realized about kind of 50% of those on a run rate basis. And so hopefully, as we move -- as well, we see some benefit there as well through 2025, right?
And as we sit here today, by the end of 2025, we would expect to be less than 100% of the synergies on that deal.

Operator

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.

Richard Barker

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.

Operator

Ladies and gentlemen, that concludes your conference call. We thank you for participating and ask that you please disconnect your lines.