We have maintained our return of capital program, returning an additional $80,000,000 to shareholders through our $0.50 per share quarterly dividend in Q4. Yesterday, our board declared a $0.50 per share dividend for the current quarter. Turning to the commercial highlights, we have continued to see strong booking levels across our fleet, with backlog increasing to $7,500,000,000. First, the Noble Great White has been awarded a three-year contract with Aker BP in Norway valued at $473,000,000 including mobilization, but excluding additional fees, integrated services, and bonus potential. This marks the Great White’s first campaign in Norway and represents a significant step in expanding our presence on the Norwegian Continental Shelf and deepening our important relationship with Aker BP.
We expect CapEx of approximately $160,000,000 for the rig’s reactivation, Norwegian certification, and contract preparation. This is a highly strategic investment with a compelling return profile, as we anticipate total EBITDA potential of approximately $240,000,000 over the three-year contract period. Essentially targeting a recovery of the capital in the first two years of the program and positioning the Great White very well for the future as one of the most technically capable units in the Norway floater market. And, of course, the access to the Norway market should result in a structural enhancement to the long-term earnings profile and NAV of the rig. Next, the Noble Johnny D’Souza was awarded a two-year contract in Nigeria.
This contract, valued at $292,000,000, is scheduled to start around the middle of this year, and is followed by three one-year options. We are looking forward to redeploying the D’Souza in Nigeria following the rig’s previous campaign there from 2023 to 2025. In the U.S. Gulf, the Noble Black Rhino has recently been awarded one well plus one option well with Beacon. The firm well is an estimated 50-day workover set to start in March, and the option well is for an estimated 100 days of drilling work.
Next, the Noble Developer received a three-well contract with BP in Trinidad that is scheduled to commence in early 2027 at a dayrate of $375,000, with estimated duration of 240 days plus three option wells with similar duration. As a side note, the Developer has been made available for this contract as the previously announced long-term contract with Total in Suriname, scheduled to start later this year, has been reassigned to the Noble Discoverer. Perhaps somewhat counterintuitively, our sixth-generation D-class semis actually began to realize an earlier demand recovery than some of the higher-spec seventh-gen rigs, with both the Developer and Discoverer now booked out for a combined total of nearly five rig years.
Additionally, the Deliverer looks well positioned for a good amount of work that is expected to start next year. Hopefully, we will have some positive news to report on the Deliverer before too long. Staying in South America, the 11-well contract with an undisclosed operator is expected to commence late this year with estimated duration of 18 months at a rate of $300,000 per day, plus mobilization and demobilization fees and potential for performance bonus. And finally, in Southeast Asia, we have firmed up contracts for an additional five to six months of work this year, through the expansion of existing work scopes plus one additional option well.
So we now expect the Viking to be solid through July, with additional opportunities under discussion that would carry term for the rig through this year and beyond. Now onto the market outlook. Despite the ongoing abundance of macro uncertainties and Brent prices hovering around five-year lows in recent months between $60 and $70 per barrel, floater contracting activity has been resilient, underscoring our customers’ multiyear planning horizon for their highly strategic deepwater assets. Including our recent contract awards, the contracted UDW rig count has now bounced back up to 105, up from a recent low of 97 early last year, and is closing in on the 2024 high watermark of 107 contracted UDW rigs.
On this basis, the contracted utilization rate of the marketed fleet is 95%. That said, these figures all reflect the gross number of contracted rigs, including those which are currently idle but have contracts starting in the future. Alternatively, the number of UDW rigs currently working under contract today is 90, which represents marketed utilization of 82% on a present basis and, of course, gives rise to the soft dayrates we have seen recently. These divergent utilization statistics tell us a couple of things. First, the industry fleet has added backlog depth but has not yet fully worked through the prompt white space overhang.
And second, the foundation has been set for a steadily improving activity level as we progress through this year and into 2027. Of note, six of the 14 rigs that sit idle today with future contracts in hand are Noble rigs: Noble Black Rhino, Voyager, Valiant, Great White, Johnny D’Souza, and Endeavor. We believe this is a strong indicator of improving utilization for the industry fleet and especially the Noble fleet. More on this later. Focusing on the near term, there are still about 25 UDW floaters with contracts expiring during the course of this year. For context, this is essentially the same as the fleet’s rollover profile in 2025 and does not cause concern.
While this churn will still probably continue to result in some idle gaps this year, overall, the white space across the industry looks to be on the retreat. And if the overall contracting cadence remains on trend, then we would expect to see some convergence between the present and future utilization metrics. Against this firming, but not yet decisively tight backdrop, dayrates for tier-one drillships have settled at around $400,000 per day, with lower-spec units recently capturing low to high $300,000 per day. Geographically, the recent deepwater demand trend has been characterized by steady strength in South America, a slight decrease in the U.S.
Gulf, and an uptick throughout other regions, including West Africa, the Med and Black Sea, and Asia Pacific. Starting first in South America, where contracted UDW demand stands at 44 total units, including 34 rigs in Brazil. Although Petrobras budget pressure has emerged as a near-term headwind, resulting in slower contract executions and ongoing blend-and-extend negotiations with contractors, including ourselves, thus far, this has been offset by increased demand from other operators, both within Brazil and elsewhere throughout the region. Later this year, the Noble Discoverer will wrap up its program in Colombia. It is planned to commence its three-year campaign with Total in Suriname.
We remain in constructive dialogue with Petrobras regarding contract extensions for either or both of our two Brazil rigs, the Noble Faye Kozak and Noble Courage. Overall, with Petrobras paring back activity by a few rigs over the short term, while other operators throughout the region are net adding, we would expect South America to remain roughly flat over the year relative to today’s record-high contracted UDW rig count of 44. U.S. Gulf has softened recently, with the Noble Black Rhino’s recent contract award bringing the contracted UDW rig count back up to 21, which is one to two rigs below last year’s average level. We had predicted this slight pullback in the U.S.
Gulf and it appears now that this has more or less fully played out. Next, on West Africa, where contracted UDW demand has recently rebounded to 15 rigs with the Noble Johnny D’Souza back under contract. This is an uptick from last year’s trough demand level of 12, although there is still some variability to demand in this region, with a few rigs contracted into other regions later this year. The pipeline of open demand throughout Africa remains highly promising, including at least five active or pending long-term tenders throughout Angola, Nigeria, Côte d’Ivoire, Ghana, and Namibia, plus the potential for multiple rig lines in Mozambique over the next couple of years.
So overall, the West Africa plus Mozambique region appears poised to grow into a mid- to high-teens UDW rig count as these various programs come online. The Mediterranean and Black Sea has been a growth pocket, partly due to the continued expansion of Turkish Petroleum’s offshore ambitions. The region is now up to 11 rigs, up from an average of seven to nine last year, and this could expand to 12 rigs by the second half of this year with the commencement of two programs in the Med offsetting the conclusion of the Noble Globetrotter I’s contract in the Black Sea.
Visibility beyond this year is not quite clear yet with a number of rigs rolling off contract by year end, but the long-term trend has been one of secular UDW demand growth. So from where we stand today, an estimated range of 10 to 12 rigs going forward looks sustainable. Continuing with Eastern Hemisphere strength, the Asia Pacific plus India region is witnessing a significant recovery with contracted UDW activity rebounding over the next year from a trough level of four rigs to eight currently. Additionally, the pipeline of open demand in the region remains robust, with over 30 rig years of active tenders and pretenders outstanding, including a variety of requirements throughout Southeast Asia, India, and Australia.
All of this indicates a likely upward bias of at least a couple more UDW units through 2027. Rounding out the global picture, the harsh environment North Sea and Norway market currently represents 22 units of total floater demand, seven of which are satisfied by UDW semis, which is up by one to two units compared to a year ago. We are very excited to kick off preparations for the Noble Great White three-year program with Aker BP starting next year, and the redeployment of both the Great White and the Endeavor points to a tightening market for harsh semis.
So the pathway back to 105 total contracted UDW rigs that we described on our earnings call last summer has, in fact, materialized, if anything, faster than we had hoped. This is good momentum. There is still some work to be done to arrest the recontracting churn. The average Brent crude price of $68 per barrel in 2025 was down by 15% compared to 2024, which I believe makes Noble’s 30% year-over-year backlog growth stand out incredibly well by comparison. However, I believe that a broader industry uptrend will necessarily require at least a modicum of positive upstream cash flow momentum.
With both spot and long-term Brent futures hovering in the high sixties per barrel, our end markets are, for the most part, highly economic, whereas our customers’ budgets remain relatively inert, which creates friction for significant expansion in drilling activity and dayrates. The great news for Noble is that our backlog progress has already formed a strong foundation for rising utilization, EBITDA, and free cash flow, without necessarily a great deal of wind at our backs from a macro perspective. This sets us up well toward our goal of maintaining our robust shareholder returns through a transitional year in 2026 and supports visibility for a meaningful step-up in free cash flow next year even in a flat world.
Before I turn the call over to Richard, I would like to provide a brief update on our fleet strategy. Last month, we completed the sale of five jackups to Borr Drilling for $360,000,000. Additionally, the $64,000,000 sale of a fixed jackup, Noble Resolve, is expected to close in Q3 upon completion of its current contract. As we continue to sharpen Noble’s strategic focus around the high-end deepwater and CJ70 jackup market, we have in the process unlocked capital available both for fleet reinvestment, in particular the highly strategic reactivation and upgrade of the Great White, as well as for preserving a highly flexible balance sheet and industry-leading shareholder capital returns program.
On the jackup side, we remain fully committed to the CJ70 market in Norway and the North Sea, and we are encouraged to see early indications of the strongest utilization outlook for this fleet in many years. This aligns very nicely with our entry into the NCS floater market with the Great White next year. With that, I will now turn the call over to Richard B. Barker for the financial results.
Richard B. Barker: Thank you, Robert, and good morning or good afternoon all. In my prepared remarks today, I will briefly review highlights of our fourth quarter and full year 2025 results and then discuss our outlook for 2026. Parting with our quarterly results, contract drilling services revenue for the fourth quarter totaled $705,000,000, adjusted EBITDA $232,000,000, and adjusted EBITDA margin was 30%. Q4 cash flow from operations was $187,000,000, capital expenditures were $152,000,000, and free cash flow was $35,000,000. Last quarter, we terminated the BOP service agreement on the four black ships, which increased fourth quarter CapEx by $18,000,000. For the full year 2025, we generated $3,300,000,000 in revenue and $1,100,000,000 in adjusted EBITDA.
CapEx, net of proceeds from insurance claims, of $497,000,000 included approximately $25,000,000 of variable CapEx and the aforementioned CapEx for the termination of the BOP service agreement. This all resulted in $454,000,000 in free cash flow for the year. As summarized on page five of the earnings presentation slides, our total backlog as of February 11 stands at $7,500,000,000. As a reminder, our backlog excludes reimbursable revenue as well as revenue from ancillary services. Our current backlog includes approximately $2,300,000,000 that is scheduled for revenue conversion during the remainder of 2026, as well as a slightly greater amount that is already booked for 2027.
This is the first instance in many years in which our year-two backlog has exceeded prompt year backlog at this point in the calendar, which highlights the embedded utilization and earnings ramp that we anticipate for 2027. I will circle back to this point in just a moment. Referring to page nine of the earnings presentation, we are providing full year 2026 guidance for total revenue between $2,800,000,000 and $3,000,000,000, which includes approximately $150,000,000 in reimbursable and other revenue, and adjusted EBITDA between $940,000,000 to $1,020,000,000. The low end of our adjusted EBITDA range is fully covered by our existing firm backlog plus a measure of relatively high-confidence options.
We currently expect Q1 adjusted EBITDA to be roughly flat versus last quarter. We also anticipate a slightly higher weighting of adjusted EBITDA in the second half of the year compared to the first half, although not dramatic. Total capital expenditures in 2026 are expected to be between $590,000,000 and $640,000,000. This range includes approximately half of the $160,000,000 Great White project CapEx, with the remaining half included in the 2027 CapEx, approximately $25,000,000 of customer reimbursable CapEx, and approximately $50,000,000 of additional project-related CapEx associated with the $1,300,000,000 of contract awards we announced in late January.
While our CapEx for this year is amplified by previously announced upgrade projects, including the Noble Voyager and the Noble Venturer, as well as capital associated with more recent contracts including the Great White, Endeavor, and Johnny D’Souza, these expenditures represent life-of-asset upgrades that support a fundamental enhancement to the NAV of our fleet, and all with very robust project IRRs. This capital is an important enabler to a structurally high level of potential EBITDA and free cash flow for our fleet. And as discussed earlier, this is all supported by 2027 backlog currently higher than 2026 backlog.
Looking ahead to 2027 and beyond, we would expect CapEx net of customer reimbursements to taper meaningfully towards a range in the high $300,000,000s to $400,000,000, excluding the remaining Great White project capital, which is essentially how we would think about the go-forward run rate for the fleet, barring any meaningful additional contract-supported project capital. A few other elements for 2026 to consider are as follows. Firstly, we expect cash taxes to be approximately 11% to 12% of adjusted EBITDA. Secondly, during 2026, we anticipate a maximum potential outlay of up to $85,000,000 associated with the possible buyout of the BOP leases on the four black ships. This possible buyout is not included in our capital expenditure guidance.
Next, we expect a favorable working capital reduction of around $100,000,000, this partly driven by CapEx reimbursables. Additionally, when modeling cash balances, recall that the sale of five jackups to Borr Drilling brought in $210,000,000 in cash proceeds last month, plus a $150,000,000 seller note. We also expect to close the additional $64,000,000 cash sale of Noble Resolve to Ocean Oilfield in the third quarter. As it relates to the Noble Resolve, we received approximately one-third of the sale proceeds as a deposit in Q4 2025. Lastly, our guidance reflects inflation rates in the low single-digit area on average across various cost components.
With the significant recent advancements with our contract backlog underpinning forward revenue visibility, coupled with the anticipated normalization of net CapEx to a lower sustaining range after this year, we have increasing tangible visibility to a healthy inflection in both EBITDA and free cash flow next year. By way of illustration, assuming 13 of our 15 tier-one drillships working at current market rates, contribution from all three D rigs, and the remainder of our fleet essentially contracted at current status quo, we can envision an annualized run rate of around $1,300,000,000 in EBITDA with corresponding free cash flow of approximately $600,000,000 in 2027. With that, I will pass the call back to Robert for closing remarks.
Robert W. Eifler: Thanks, Richard. To sum up, I am incredibly excited about this moment for Noble. All of the strategy and effort that our organization has invested over the past five years is truly paying off, as evidenced by our backlog build and widespread relationships with the world’s most active deepwater producers. On backlog, our outperformance is a direct result of our strategy and has differentiated Noble over the past year, fundamentally recasting our contract coverage profile and substantially underwriting the material earnings and free cash flow inflection that Richard just mentioned. In connection with several of our major contract awards, we are making significant strategic investments to support our first-choice offshore strategy.
With these investments, our fleet of 15 high-spec drillships will all have owned and integrated MPD or CM/L systems. Two-thirds will be equipped with NOV’s leading-edge automation technology, including advanced robotics on several rigs, and two will feature 2,800,000-pound derricks. Additionally, the Great White’s modifications will place it as a tier-one floater in Norway, alongside our leading fleet of ultra-harsh CJ70 jackups. With all of this, we strongly believe that Noble has the most advanced automated fleet in deepwater and NCS.
As Richard mentioned, the significant increase in our backlog, with over 90% of our 24 floaters now contracted, combined with the unique characteristic of having greater year-two backlog in the book than current-year backlog, serves to provide a direct line of sight to run-rating approximately $1,300,000,000 of annualized EBITDA by 2027, even without any improvement in dayrates. And with 10 of our 15 drillships already secured by long-term programs, this implies only a small handful of highly marketable rigs to be contracted in order to derisk that trajectory towards the highest free cash flow level this company has seen in over a decade.
And I would further add that nothing about our near-term rollovers gives rise to significant concern, as the demand pipeline appears quite robust, resource holders continuing to look offshore for future oil and gas developments of scale with advantaged economics. This is evidenced by a 33% increase versus last year in open tenders and pretenders for floaters, which is now back to around 100 rig years of open demand in the public domain, i.e., not counting direct award opportunities. Several high-profile and long-anticipated FIDs in places like Namibia, Suriname, and Mozambique, for example, stand out as key contributors to this next leg of the offshore cycle. But as we have discussed earlier, there is considerable global breadth to the story.
Previously, on our second quarter earnings call last summer, we communicated a milestone objective of $400,000,000 to $500,000,000 of run-rate free cash flow by 2026. Since that time, we have taken strategic investment decisions that have pushed the time horizon of this inflection back to 2027. However, we can now visualize around $600,000,000 of run-rate free cash flow by the second half of next year at current market rates, with significant leverage to dayrate upside beyond this. And based on the emerging utilization improvement across the global fleet, as well as the encouraging leading indicators on forward demand, we would expect to see an upward bias to dayrates from here.
As we have seen before, rates can move from the low 400s to the high 400s in the blink of an eye. So it will be interesting to see where this next part of the cycle takes us. But in the meantime, we will remain laser-focused on execution and continuing to deliver value for our customers and shareholders. With that, I will turn it back over to the operator for questions.
Operator: Thank you. At this time, I would like to remind everyone if you would like to ask a question, please press star then the number one on your telephone keypad. We do request for today’s session that you please limit yourself to one question and one follow-up. Your first question will come from Arun Jayaram with JPMorgan Securities LLC.
Arun Jayaram: Yeah. Good morning, Robert and team. Robert, I was wondering if you could give us your thoughts on industry consolidation. Obviously, you have seen a large merger announced earlier this week, and just your overall thoughts on the implications to Noble and your overall strategy. Yeah. I mean, look, consolidation has been the path for this industry post-COVID. Obviously, we participated in that, and then this week, there has been a really significant announcement. You know, I think with the outlook for our industry, I think consolidation is the obvious path throughout the energy complex, throughout the entire chain. It has obviously been no different for the drillers.
And, you know, I would say we certainly have benefited from it through the past years. We are a better company today than when we started this journey, and I am hopeful that broadly consolidation makes the entire industry better and more capable and more efficient, because that is the path forward for the drillers. Got it. I have my follow-up, Robert. Obviously, you have been a participant, as you mentioned, in industry consolidation, including the Diamond Offshore transaction. Maersk obviously have a very capable offshore rig fleet either compete at the very high-end, high-spec end of the market. Do you feel you have sufficient scale now if the other deal does get through regulatory approval?
And thoughts, do you see a window of opportunity perhaps to maybe further expand your opportunity set perhaps in the floater market? You know, obviously, you have been divesting some of your shallow water jackups. Yeah. Look, I think the answer, strangely enough, is the same today as it would have been before Monday’s announcement, that we feel we have scale. We, as I repeat myself, but we are a better company today than we were before because of the scale we have built. And there are going to be opportunities out there.
We will continue to look at everything, and we will continue to be as picky as we ever have been on ensuring that any opportunity we look at sits in the right place for us as a company in terms of the type of asset and the quality of the asset. Great. Thanks a lot. Thank you.
Operator: Your next question will come from Scott Gruber with Citigroup.
Scott Gruber: Yes. Good morning. I want to inquire about the recent strength in the sixth-generation market. I think your recent contracts surprised the market. You know, I guess first, what is driving that? Is that just a collection of projects moving forward? Is it a bit of value buying by customers? And you mentioned prospects on the Deliverer. Just curious whether you think you can get some good term on that rig as well. Yeah. It is a good question, and, you know, not necessarily something we would have predicted a couple of years ago for sure.
What I would say, I think, is our D-class semis are most of our sixth-gen rigs, and those are the most capable non-Norway semis out there. They have both moored capability and DP, and they are set up particularly well for certain types of operations. And so what I would say is for that class of three rigs, it is a project-specific right place, right time kind of phenomenon. I think it is sustainable. I do not mean to suggest that this is a window in time, but I think the fact that they have kind of contracted prior to the seventh gens is the phenomenon of being at the right place in the right time for the right projects.
It is not a value decision by our customers, as you mentioned, which is a good thought, but I do not believe that is what is driving it at all. Got it. And then we have kind of long sought it. You know, the sixth gens, we need to see better utilization just to get another round of upward momentum in rates across the collective seventh- and sixth-gen marketplace. It seems like, you know, the direction of travel there is positive. And you mentioned line of sight to especially getting back to 105 UDW’s. You know, what does it take to get some upward momentum in rates?
You know, just do you think you have to kind of eclipse that level as crude prices do you say subdued? Or, you know, just kind of getting back there, do you think you would inject enough tightness back into the market? Or do we need to see crude prices improve to kind of, you know, see some additional spending capacity by customers? Just some thoughts on the conditions that could drive some dayrate improvement here. Yeah. It is really a question I wish I had the answer to. I think it is a mixture of both.
I think what we are seeing, this phenomenon where we are seeing higher backlog kind of in year two than year one right now, I think is somewhat crude agnostic, and I think is perhaps driven more by the realization that volume of barrels is going to have to be produced from deepwater, and those are all obviously long cycle, etc. And so I think that is more driven by this return to deepwater that we have seen play out over the last couple of years. However, you know, the incremental rigs that probably the tightness in supply and demand, you know, crude price does matter for near-term projects.
And that is why we kind of outlined in our script the problem, not the answer. I personally am quite optimistic for 2027 for the reasons I mentioned in prepared remarks. But we need another, say, five rig contracts that we do not see anywhere out there today to come through to really get to an extremely tight market, call it. I am pretty confident that everything is set up to supply that. I do not think there is any reason that could not happen by 2027. Let me put it that way. But we are a little cautious to say we kind of have to see how 2026 plays out here right now.
I will say I think there are a lot of contracts that are going to get announced here, not just now. Well, just across the board over the next few months. And I think that obviously should all be well received. We are including all of that in our analysis, and we are pretty hopeful that here going into 2027, we have the various pieces for a tightening market. I appreciate the color. Thank you.
Operator: Next question will come from Eddie Kim with Barclays.
Eddie Kim: Hi. Good morning. I will ask the pricing question in a little bit of a different way, and I appreciate all the detailed commentary on the outlook. You said recent dayrate fixtures for tier-one drillships have been in the kind of plus or minus $400,000 a day range. You pointed to a tightening market as we progress through this year. Do you think we could start seeing fixtures sometime next year in 2027 back up into the mid-$400,000 range, or does that maybe look like more of a 2028 event just based on the conversations you are having and the opportunities you are seeing out there today? Yes. I think the possibility is there.
I think I would stop a little bit short of making that the base case today. But maybe it is a maybe it is a 50/50. I do not know. It is so hard to predict. But, look, I think all of the pieces are laid out, and we need just a little bit more contribution worldwide to really tighten up the market going into mid next year. You know, I would say a couple things about us specifically. One, you know, the things Richard laid out in his script are all completely without dayrate improvement.
So we feel, with our unique backlog curve where we have done a lot of the 2027 work already, we feel that we are extremely well positioned for an inflection here without dayrate improvement. And then two, I would say, also, I really like the way the fleet contracting is staggered right now. So we have got a nice mix of short-term availability, long-term contracting, and then, of course, our CEAs. We price up and down. And so I think I am pretty pleased right now with the way the Noble fleet sits looking forward at everything. Got it. Thanks for that color. My follow-up is just on negotiations with Petrobras.
We have not really heard any news about the London from you or anyone else. I would have thought that we might have seen something on the Faye Kozak in your fleet update several weeks ago. It mentioned negotiations are still ongoing. When do you expect these will conclude? And separately, I mean, Petrobras has a tender out for Buzios and Tupi and Mero I. Is it fair to say they are unlikely to award these contracts until those blend-and-extend negotiations have concluded? Just any thoughts there would be great. Yeah. It is a good question. Something we are tracking closely along with everyone else.
You know, we are hopeful that the next couple of months bring a fair amount of news. If you look at it through Petrobras’ lens, they have an incredibly complicated set of dynamics. They have got more debarred rigs than anyone else out there. They are managing the tenders you mentioned as well as the blend-and-extends all at the exact same time, and that is a heavy lift and so could easily see how that could get pushed out a little bit past the next couple of months. You know, I would add color, kind of referring back to our remarks, that we do think maybe Petrobras rig numbers probably come down a couple of rigs.
But we think non-Petrobras players in Brazil are going to basically make up that supply change in 2027. And then from there, who knows? You know, plans change, and so we are generally positive, optimistic about Brazil being, you know, kind of worst flat, which is, you know, in a really good place right now, and hopefully up by a couple of rigs over the next couple of years. Got it. Thanks for that color. I will turn it back. Thanks, Ed.
Operator: Your next question will come from Fredrik Stene with Clarksons Securities.
Fredrik Stene: Hey, team. Hope you are all well, and thank you for the prepared and detailed remarks on the grid market in particular. I wanted to ask a bit more about the Norwegian market because a couple moves here that you have done recently. One, obviously, signing the Great White with Aker BP and focusing your jackup fleet solely on the high heavy-duty, harsh environment market. If you take that kind of combined with your prepared remarks where you said that the outlook, I think, for these particular markets were better than you had seen in many years.
Are we able to elaborate a bit on that and maybe specifically on the jackup side since the Great White’s floater role has been contracted for three years? Why what makes you optimistic, and how should we think about the jackup fleet in 2027–2028 where there is some space that definitely needs to be filled? Thanks. Yeah. It is a good question. I do not want to imply more than too much optimism. And, look, we have got contracts for the CJ70s. A number of those are in the UK sector, which is great. I am not sure that we see a renaissance in shallow-water Norway right now, so I do not want to overstate that or have that misunderstood.
But we do have contracts for everything. We do have multiple customers that are looking at and considering potential jobs in Norway, so the market has expanded well past just Equinor. And, obviously, I include Equinor in the multiple customers, but, you know, I think with the rigs kind of in a steady state utilization right now and some ongoing conversations, it just feels like it is more likely to get better than worse for sure. Okay. Maybe Norway-specific stays more flat than up. But it definitely feels flat or up right now.
And, you know, we think we have the most capable rigs in the world ready to go if we do get an incremental unit or two of demand in Norway. Alright. No. That is very helpful. One quick one more. Turning to the floater fleet. You have the Globetrotter I, you know, which is a little old contract. You have the Apex and that is idle. Deliverer, we seem very optimistic about, potentially having a good chunk of work from ’27 and beyond. Would you have any commentary on how you view the Ocean Apex and the Globetrotter in your fleet as we look forward? Thanks. Yeah.
So on the Globetrotter, we have said before that we are effectively bidding those into intervention or niche drilling applications. So, obviously, Black Sea qualifies for that, since those rigs can go into the region pretty quickly and efficiently. You know, I think the intervention market remains out there, and we are, you know, I would say we are kind of chasing a mixture of intervention and potentially some niche programs for the Globetrotter. Apex is, you know, probably we will see what happens with that rig. So there is, I guess, less on the horizon for that rig. We are going to keep looking hard at that one. Alright. Thank you so much for your answers.
Have a good day. Thank you.
Operator: Next question will come from Ben Summers with BTIG.
Ben Summers: Hey. Good morning, guys, and thanks for taking my question. So first on the Black Rhino, kind of just the U.S. Gulf market in general. Just kind of curious, it was a to see that rig get some work. And I know we have the 100-day drilling option, but just curious, kind of longer term there, what you think the potential is for maybe more spot work in the U.S. Gulf or potentially moving that rig elsewhere? Any color there would be helpful. Thank you. Yes. It is a good question. That is where we are spending our, myself and our marketing group, spending a lot of time on that rig. We have multiple opportunities.
So I would say, you know, for 2026, we are hopeful that there is some spot work out there, but there is probably not a huge amount of upside on the rig. Hopefully, some. I think the more exciting programs for that rig really are in 2027. Those exist both in the U.S. and outside of the U.S., and we have got a couple of different opportunities with some of our closest customers globally, and we are hopeful that we can land something there. That rig is an excellent rig. It is outfitted very well for big development campaigns and obviously can perform with the best of them for shorter-term and exploration jobs as well.
So we are hopeful to land something here before too long. Awesome. Thanks for the color. And kind of just more broadly, I know you guys spoke on the 2027 kind of expected demand pickup. I guess, is there any kind of concern there that projects could continue to shift to the right, I guess particularly in a market like West Africa? Are we pretty confident here that is kind of in the past now and that demand should really begin to substantially pick up in 2027? Just kind of curious on anything here and there. Not a day that I do not wake up concerned about things getting pushed to the right.
So it is obviously always a risk in our business. When you have got Brent in the sixties, it is always going to be a risk in the business. Partly why I, you know, we are not exactly calling for predicting with certainty what happens in 2027. But I will say, with all of the backlog that has been announced by Noble and our competitors, and I think an amount of backlog that will be announced here in the coming months, the number of pieces that need to fall in place for a tight 2027 are substantially lower than what we have seen in quite some time.
We threw out the statistic about the kind of open demand that is out there. There are obviously direct negotiations that are in excess of those numbers. And we look at where we sit today in the year, in the rollovers, it is kind of there is no negative story about 2026 rollovers. It looks like upstream CapEx is either flat or up. And if you try to decode what that means for deepwater and commentary around it, it feels like that is a reasonable story for 2026. And for us, you add all of those together, and it gives us a fair amount of optimism for a pretty tight market in 2027. Awesome.
Thank you guys for taking my questions. Thank you.
Operator: Your final question will come from Keith Beckman with Pickering Energy Partners.
Keith Beckman: Thanks for taking my question, guys. I had a question kind of relating around the CapEx on the nine contracts outside of the Great White. So I think it is about $50,000,000 of CapEx, and I believe you guys said it was related to the Endeavor and the D’Souza. Can you sort of bucket between those two rigs roughly what that is for me? Yeah. So I think you are talking about the incremental $50,000,000 of contract capital that we announced in conjunction with the $1,300,000,000 of backlog here about two weeks or so ago. Think about that incremental capital as kind of split between the Endeavor and D’Souza. Okay. Perfect. Awesome.
And then my other question was, just relating around, and I think this was hit on maybe a little bit earlier, but just relating around the remaining five jackups. Does it potentially make sense if somebody comes in with the right price now to kind of make yourself the largest pure-play floater fleet? Just any color around that. Yeah. Like, it is a good question. No. We are committed to the CJ70s. When we announced the merger with Maersk, we chose to put our secondary headquarters as Stavanger. We have an established, extremely capable operation there, and with the addition of the Ocean Great White, some added scale. So we are pretty happy with where we sit there right now.
Perfect. Really appreciate the color. Thanks for taking my questions. Thank you.
Operator: And that concludes the Q&A portion of today’s call. I would now like to turn the call back over to Ian MacPherson for any closing remarks.
Ian MacPherson: Thank you for joining us today, everyone. We appreciate your interest and we will look forward to speaking with you again next quarter. Have a great day.
Operator: Thank you for your participation. This does conclude today’s conference. You may now disconnect.
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Noble (NE) Q4 2025 Earnings Call Transcript was originally published by The Motley Fool