Noble Corporation plc Stock

Hello, and thank you for standing by. My name is Lacy, and I will be your conference operator today. At this time, I would like to welcome everyone to the Noble Corporation Third Quarter 2026 Earnings Call and Webcast. [Operator Instructions]

I would now like to turn the call over to Ian MacPherson. Please go ahead.

Thank you, operator, and welcome, everyone, to Noble Corporation's Third Quarter 2026 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 as well 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. We also have with us Blake Denton, Senior Vice President of Marketing and Contracts; and Joey Kawaja, Senior Vice President of Operations.

During 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. Several factors could cause actual results to differ materially from these forward-looking statements, including those described in our earnings release and in our most recent annual report on Form 10-K and quarterly reports on Form 10-Q filed with the SEC. 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 associated reconciliation in our earnings report issued yesterday, furnished to the SEC and posted to our website.

Now I'll turn the call over to Robert Eifler, President and CEO of Noble.

Thanks, Ian. Welcome, everyone, and thank you for joining us. I'll open today's call with a brief summary of our third quarter highlights and recent contract awards, followed by an update on the market. Richard will then cover the financials before I wrap up with closing remarks and move to Q&A.

During the third quarter, we earned adjusted EBITDA of $201 million with free cash flow of negative $48 million. We again distributed our $0.50 quarterly dividend. And yesterday, our Board declared a $0.50 per share dividend for the fourth quarter, maintaining our consistent return of capital program. The 5% sequential decrease in adjusted EBITDA resulted from a number of rigs transitioning between contracts, including the BlackRhino Discoverer Venturer and Globetrotter I, each of which had fewer days on contract in Q3 compared to Q2. These were partially offset by the resumed operation of our 2 rigs in Brazil in July as well as the Gerry de Souza's contract startup in August.

Additionally, the Voyager commenced its 4-year contract with Shell in the U.S. Gulf in late September. Final commissioning and weather delays resulted in a few weeks later start than planned for this contract, but we are excited to now be underway with the Voyager. Next, in our major project start-up queue, we are looking forward to the Valiant and Discoverer scheduled commencements right around the end of this year on their long-term development campaign for Total and Suriname. Over the past 3 months, we have secured new contract awards totaling approximately $560 million. First, the Noble BlackRhino has been awarded a 4-well contract with TotalEnergies in Nigeria, expected to commence within the next few weeks. This program has an estimated duration of 150 days and includes options for up to 6 additional wells.

Next, I'm pleased to announce that the Noble Faye Kozack was awarded a 5-well contract with Tullow in Ghana scheduled to commence in mid-2027 with an estimated duration of approximately 250 days. Also, the sixth-generation drillship Noble Globetrotter I has been awarded a contract with TotalEnergies for light well intervention services under a 3-year capacity reservation agreement with the first scope of work scheduled to commence in Angola in Q3 or Q4 next year. However, prior to this, the rig is scheduled for a recently awarded 2-well exploration campaign with Occidental in Peru, commencing in Q2 2027, which leverages the Globetrotter's unique capability to transit through the Panama Canal in order to access this remote drilling location.

Continuing with Frontier exploration in South America, the Noble BlackHawk has been awarded a 1-well contract with Apache in Uruguay that's expected to commence in Q4 2027 with an estimated duration of 50 days and a contract value of approximately $25 million, plus additional fees for mobilization and demobilization. This contract value does not include MPD or any other additional services. As the BlackHawk is winding down its current work in the U.S. Gulf, we are continuing to pursue promising leads for additional work for the rig next year prior to the Uruguay move.

Switching over to Norway. The Noble Interceptor has been awarded a 1-well contract with DNO that's expected to commence in mid-2027 with an estimated duration of 50 to 90 days. Upon completion of this campaign, the rig is scheduled to commence its P&A program of ConocoPhillips at the Ekofisk field in the third quarter of 2027 with an estimated duration of 670 days. And finally, the Noble Intrepid was awarded a 1-well contract with ORLEN that is expected to commence in Q3 2027 with estimated duration of 40 to 60 days. With these awards, our current backlog stands at $6.7 billion.

Now zooming out for a moment to the broader market, recent trends across both the deepwater and harsh environment sectors are continuing to gain nice momentum. Deepwater contracting activity, which started out the year gangbusters, but then hit a quiet patch between May and July has recently reaccelerated over the past few months with a spate of recent pictures confirming day rate recovery for high-end drillships in the mid-400s up to $500,000 per day as current utilization, but to a greater extent, anticipated 2027 utilization continues to firm up. Today, 109 out of 110 marketed UDW rigs are contracted currently or in the future, putting contracted utilization at 99%. This eclipses the 2024 high watermark of 105 contracted rigs.

Meanwhile, current working utilization of 88 rigs is still 10 units shy of the 2024 peak. However, we've reached a point now where the number of pending contract start-ups for currently idle rigs modestly exceeds the number of contract rollovers over the next 6 months or so. This creates a fulcrum for the active rig count to potentially expand over the next few quarters as additional contracts are executed. So the deepwater market is firming up, consistent with what we've been anticipating for a while now. And this is despite the fact that we really haven't seen any real demand response so far this year resulting from higher commodity prices.

On the contrary, the U.S. Gulf, which has historically been one of the more demand elastic markets through commodity cycles, has been a noted soft spot amidst an otherwise robust global market throughout this year. Having now retreated from a low 20s rig count in recent years to a mid-teens market presently, we do expect to see some improvement in the Gulf next year based on current customer dialogue. However, the departure of a few drillships to other regions could likely create upward day rate pressure in order to drive capacity back into the Gulf, perhaps similar to recent dynamics in the harsh semi market, which in recent years have seen Norway rig count dip from the high teens down to the mid-teens and now back up to the high teens, with strengthening Norway day rates accompanying the migration of capacity back into that region.

And speaking of Norway, I would further add that the Norwegian jack-up market is also developing into a bright spot for Noble. With our recent contract awards, we now have 4 of our 5 CJ-70 jack-ups contracted in Norway for the first time, which is very promising improvement with leading-edge day rates ranging between $230,000 to $300,000, depending on work mode and contract duration. Currently, the Noble Innovator, the older unit among our 5 CJ-70s, remains uncontracted, but we're optimistic about contracting that rig fairly soon in the Southern North Sea where day rates are structurally lower. But nonetheless, this gives us a clear shot at approaching effectively full utilization for our jack-ups in 2027.

Now I'll pass the call over to Richard for the financial review.

Thank you, Robert, and good morning or good afternoon all. In my prepared remarks today, I will briefly review the highlights of our third quarter and then discuss the outlook for the fourth quarter of 2026. Starting with our quarterly results. Total revenue for the third quarter totaled $684 million. Adjusted EBITDA was $201 million and adjusted EBITDA margin was 28%. Q3 cash flow from operations was $144 million. Capital expenditures were $192 million and free cash flow was negative $48 million. On October 9, the sale of the Noble Resolve was finalized with the company receiving the remaining $45 million of proceeds. Further, the sale of the Noble Globetrotter II is expected to close in the fourth quarter of 2026 for a purchase price of $38 million.

As summarized on Page 5 of the earnings presentation slides, our total backlog as of October 26 stands at $6.7 billion. As a reminder, our backlog excludes reimbursable revenue as well as revenue from ancillary services. Our current backlog includes approximately $2.6 billion that is scheduled for revenue conversion in 2027. Referring to Page 9 of the earnings presentation, we have narrowed our full year 2026 guidance for total revenue to between $2.85 billion and $2.9 billion compared with $2.8 billion and $2.9 billion previously and adjusted EBITDA to between $850 million and $900 million compared with $850 million and $925 million previously, as we expect Q4 to be slightly lower compared to Q3. Revenue was narrowed around the high end of the previous range, driven by higher reimbursable revenue than previously expected, while adjusted EBITDA was narrowed around the lower end, driven primarily by slightly later starts for the Voyager and the Valiant.

Additionally, capital expenditures guidance for this year has been increased to $680 million to $705 million compared with $615 million to $665 million previously, with the increase primarily attributable to higher customer reimbursable capital expenditures, which is now expected to total roughly $65 million for this year as compared to $25 million previously. If you exclude this $14 million increase in reimbursables, our capital expenditures guidance would have otherwise remained within the prior range.

Looking ahead, while we plan to provide formal guidance for 2027 on next quarter's earnings call, I would like to share the following directional indicators. In the first quarter of 2027, adjusted EBITDA is expected to be broadly similar to Q4 2026. We then expect adjusted EBITDA to build meaningfully higher each quarter as we progress through the year, supported by the buildup in our contract coverage with already approximately 20% more capacity under contract in the second half of the year compared to the first half. This is a noteworthy contrast with recent years in terms of the general slope of our contract coverage for the following year. And as Robert referenced, there were several opportunities we are actively chasing that start around the middle of the year that would build on top of this already existing contracted step-up.

With that, I'll now pass it back to Robert for concluding remarks.

Thanks, Richard. To wrap up, we're excited about both the direction of the market as well as Noble's positioning as we ramp into some pretty meaningful contract start-ups over the coming quarters. The gathering drumbeat of exploration and reserve replacement imperatives facing resource holders, combined with a forward oil price curve that has been melting higher through the end of the decade, have the potential to drive meaningfully tighter market conditions ahead. And specifically, based on the robust portfolio of contract opportunities in front of us today, it's not hard to draw a straight line to a fully sold-out market for high-end deepwater rigs within the next year or so.

Even under a more moderate demand scenario, however, we believe Noble is exceptionally well positioned to execute our playbook, generate durable free cash flow and deliver substantial returns of capital to shareholders through cycle. The backlog that we've secured since last year provides a clear line of sight to a significant cash flow inflection as we move through 2027 with, as Richard just highlighted, approximately 20% more contracted fleet capacity already secured in the second half of 2027 versus the first half of the year. And of course, we will have some opportunity to build on this.

This dynamic, in particular, is clearly supportive of an improving outlook, especially when contrasted against comparable measurements in recent years when the deepwater outlook has been burdened by significant white space problems. For example, 12 months ago, our H2 2026 days under contract were 5% shy of H1 2026 contracted days. And 24 months ago, when we were in the relatively early days of the emerging downdraft in the market, our contract coverage in the second half of 2025 was at that time actually 33% below H1 2025. So today's situation does indeed represent a very pronounced upturn in the shape of our backlog heading into 2027. And with that as a launch point, we're increasingly excited about the opportunity set in front of us.

Operator, we're ready to go to questions.

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

Hey, Robert and team, I was wondering if you could comment a little bit on kind of changes you've seen in the overall market since last quarter and you gave your semiannual review of rig demand. We have noted that the contracted rig count has moved up by about 5 rigs. I think last quarter was about 104 and now you're at 109. So maybe just comment on what you're seeing that's evolved over the last, call it, 90 days and maybe add a little bit of regional color as well. Appreciate that.

Sure, Arun. Thanks for the question. Yes, we noted in the prepared remarks that we were in a bit of a doldrum over the summer months on fixtures. And you've referenced those that are known where we're up a handful of rigs on total demand rig count. What I would say is beyond that, we see now, I think, 2 to 3 opportunities in the U.S. Gulf that are somewhat closer to firm than we saw 90 days ago, which is obviously extremely helpful. And we see everything moving forward as planned through Kercom in West Africa. And then I would also note probably the other most notable change is we're feeling very good about demand emerging in India. So if you recall, there was some excitement there and then some tenders were postponed. And since that time, it appears obvious to us that, that I don't know, anywhere from 2, but probably something closer to 4 good drillships are going to be needed in India starting in late '27 and '28. I think those are probably the most bullish changes that we've seen in the last 90 days are U.S. and India.

Great. And my follow-up, Robert, we're still in the early innings of kind of the OFS earnings season. But one of the themes that SLB highlighted on their call is just this renewed interest in exploration. And we did note in your updated fleet status report some opportunities in Peru and Uruguay. So I was wondering if you could just comment on general trends you're seeing in exploration over the next, call it, 12 to 18 months? And maybe part and parcel with that, are you seeing opportunities for chunkier development opportunities, which could have a little bit of a longer-term duration to those versus some of the exploration opportunities that tend to be a couple of wells here or there?

Yes. So I think if you just walk back through just a tiny history of exploration, I think it was around 3 years ago where we started seeing our customers start to talk a little bit more about reserve replacement. And then in the last 18 months or so, we started to see some real movement among our customers and increased narrative, specifically in exploration. There have been some, I guess, public commitments by our customers and statements around a return to exploration in various different regions. 2027 has been cited as a year where we would perhaps see an uptick in some of the, call it, wildcat exploration, which I think is where you really want to be looking right now. And so I would agree completely with what SLB said. What -- the only thing I would say is in terms of what has hit our business, you've seen the couple you referenced on our fleet status. It's not a needle mover, I don't think, for our business from where we sit today. We're very hopeful that as our customers exit budget season with really good cash flow during 2026 that we might actually see some more evidence of wildcat exploration in 2027.

And then you asked about development. This cycle has been -- I don't know if it's been reversed, but most of what's driven the demand heretofore has been development projects. So it's like a lot of things that have been delayed in years past are now starting up. That's what's driving, I think, the global uptick that we see in late and have referenced in late '27. And so -- and included in a lot of that, I think the exploration we've seen over the last couple of years has all been infield exploration. And so we watch that closely. That -- the percentage of our wells that's infield exploration has stayed relatively flat over the last few years. And so we're like you, really watching some more wildcat type exploration closely, and we're hopeful that, that starts to define the next phase in this uptick that we've been calling for here. But I think '27 is when we might get a little bit more clarity there.

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

I would argue that you provided a relatively strong contracting update today with rates being supportive on most of these contracts, particularly happy to read and hear your commentary about the jack-ups, which have been lagging a bit with the leading-edge rates now being stronger. But I wanted to -- with rates being in a good place, I wanted to touch a bit on utilizations maybe in the near to medium term for certain specific rigs. You have some open capacity next year on the Stanley Lafosse, you have the Viking that has availability and obviously, the BlackHawk, which you've now in for a short-term contract towards the latter part of 2027. If we -- feel free to give specifics, but if you were to take like a portfolio view of maybe the drillships in particular that have open capacity, what kind of utilization should we expect on those in those areas which are now at least for now uncovered?

Yes, Fredrik, thanks. So all 3 of the -- well, all of the rigs are competing -- well, they're competing in slightly different markets. The Viking, I think it's very likely to stay in Southeast Asia. We have a number of opportunities for that rig that would close some of the gap before its long-term contract. So I think it could perhaps get up to in the 50% type range on utilization next year. But as the fleet status shows, we need to win some work there. And then I would lump the other rigs probably into more of a similar group. So we mentioned on the prepared remarks that we do have some work for the BlackHawk that we're hopeful comes through prior to its transfer transit down to Uruguay. And then there's a fair amount of work following that. And so we think between the Hawk and the BlackRhino that there are a lot of opportunities towards the end of '27 and '28, most of which are for long term -- for the long term. So we're pretty comfortable that we're going to fill in some white space on those rigs.

The Stanley Lafosse has work potential both in the U.S. and then outside the U.S. And I guess what I would say there is if it were to go outside the U.S., that's more likely to go back to work in late '27, early '28, that kind of time frame.

All right. That's very helpful. And then as a follow-up, 3 or 2 questions, if I were to sound completely honest. The first one is with the rates being higher for ultra-deepwater market at the moment, what kind of delta should we expect for the Guyana rigs in terms of repricing and the mechanism that's at play there? I think it's being discussed it every September and March or something? And how will that play into your financials next year and '28 for that matter? And second, are you able to provide some guidance on how the agreement on the Globetrotter I work since it's more of a call-out arrangement with minimum utilization rather than a regular day-to-day contract?

Yes. So on the CEA, I guess I'd kind of say what we always say, which is it tracks market extremely well. We set the latest rate about a month ago that will start next year. And because we had one rate through all of '26 and then we have a rate that will start in late '27. We never disclosed the rates. What I would say is that it was set right around a month ago, maybe just a bit more and tracks the market very closely. And that will be a 6-month rate starting in January 1. And we've just adjusted the timing on that this year. So we had one rate for all of this year and then the next 6-month rate starts January 1. It's just easier for everybody. Over to the Globetrotter I, putting aside its exploration drilling well. The intervention project is 3 years long. It has a minimum of 150 days per year included in that. And then as most people listening probably know the intervention market is just a little bit different than the drilling market. It's planned on a much, much shorter cycle and it's more -- I'd call -- we call it call-out work, which compared to our drilling work, it is effectively call-out work.

And so the way I would think about that program is that it's roughly kind of breakeven at the minimum number of days per year. And then as call-out work fills in extra days, then we can earn some margin on top of that. We really like it. We think that rig is very well set up to kind of be that hybrid where it does intervention work, but can also head to run to some drilling wells where needed as we've seen and with a potential uptick in exploration and our belief for a long time that intervention is going to grow through time. We think this is a good contract for the rig, even if it's not going to be a real needle mover for us from a free cash flow generation perspective.

Your next question comes from the line of Scott Gruber with Citigroup.

I just wanted to follow up on the last line of question. So on the Globetrotter, as you kind of cycle between kind of working and not working, can you help us on the cost side of things? How should we think about cost well working and not working? And how you think about kind of managing those costs through the kind of on-off schedule?

Yes. So not working, we can get the costs well down, call it, to about 50% of what a Tier 1 drillship might cost. And while it's working, it's only slightly higher than that, call it, 60% of a working drillship in that range. That's an intervention mode. So when I mentioned the -- that sort of cash flow breakeven to moderately better than that, that's assuming that full intervention cost load all the way through. So that's, call it, 60% of the cost of a working Tier 1 rig.

Got you. And do you have much insight today in terms of the uptime extending beyond the 150 kind of days annual commitment?

We don't right now. I mean we're hopeful that we can -- I think I'm just going to throw out there. A great year, we think, would be to be able to double that number and keep it working kind of around 300 days. And then an average would probably be halfway between 150 and 300. So just over 200 -- low 200s per day -- I mean, per year, excuse me.

Yes. If I could just squeeze in one more, too. On the Guyanese rates, those are measured against market rates, not spot, correct? And is the measuring stick a global market rate or more region-wise to Latin America or the Americas in total?

It's a global market rate for a Tier 1 drillship.

Got you. For realized rate, not spot.

Yes. So what -- yes, it is. It's -- the way I would say it works in practice, which I love the way this is set up is because it's negotiated each round. And so because fixtures are all so bespoke and almost every fixture has some sort of special story to it, all of that does go into consideration. So that kind of all gets thrown out on the table and negotiated. It's not just a formulaic average of an Excel sheets print out. And frankly, that's why I think it tracks the market so well.

Your next question comes from the line of Keith Beckmann with Pickering Energy Partners.

I just wanted to ask around -- I want to dig into the Gulf a little bit more around some of the comments you had earlier. I mean, are you seeing some of the smaller independent drillers in the Gulf worry about a lack of rig supply into next year as we see potentially several longer-term programs in West Africa and Southeast Asia. And in that case, I mean, is that what potentially caused them to move some of these programs up from maybe what their expectations were before? Just any commentary around that.

What I would say is it is becoming increasingly obvious that supply could be an issue. I think, to our customers broadly, whether they're small or large. Whether someone has brought a program forward out of that, I wish I could say yes, but I'm not sure that we've actually seen that.

Okay. And then my second question is just around, I mean, how are customers thinking about contract duration today? We've seen day rates continue to tick up here a little bit here over the last couple of months. Are they looking to lock stuff up for potentially prices rise further? Or are they potentially pushing stuff off right now, thinking hopefully, day rates come back down? Just maybe recent customer conversations around that.

Yes. I would say just tracking over the last 90 days that urgency has gone up, not down. But I would also say that we're far from a market where there's legitimate concern about not being able to drill a program because of supply. So whatever kind of middle ground that is, I think we're starting to hear more comments about how it's looking pretty tight going into 2028. The deepwater market is looking pretty tight. But we're still a ways away from the urgency we've seen in certain past cycles where you really -- where it's really driving duration decisions. I think duration decisions are still largely driven by need.

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

So you mentioned that the deepwater market is firming up despite no demand uplift so far this year from higher commodity prices. Could you elaborate on that for us? Is it your view that the recent contracting increase we've seen would have happened even without the increase in oil prices and that we should have seen more multiyear contracts announced by now given the elevated level of oil prices? And if that's the case, what do you think is the main reason that the customers are sort of holding back at this point?

Yes. It's -- Ed, you're breaking up a little bit, but -- so why are the higher commodity prices from this year not driving activity? We cast it as a positive because just because obviously, more cash flow for our customers is good for us. We really haven't seen very much increasing. We haven't seen -- I don't think we've seen any demand that's arisen from this. And I think it's because, a) discipline has ruled our customers for this entire cycle, up cycle, mid-cycle, wherever we are right now. And that's not going to change. And so there's additional cash flow right now, which is good. It's not translating into drilling just yet, which obviously we wish it had. I think we remain hopeful that in '27, we'll see some additional exploration work. We mentioned that earlier. And then I would say just the nature of all of the markets this year have been, I think, a little bit baffling for a lot of people. So I think there's an understanding that the oil -- current oil price could go right back down almost overnight given the geopolitical drivers and everything that's out there. And so people aren't really willing to make long-term decisions off of it right now.

We've pointed to the middle part of the Brent curve is probably the best indicator of our business for quite some time. And as we mentioned, it's bumped up a little bit, but it has been a lot less volatile than near-term pricing all the way through all of this. And so I think we've just seen our customers maintain a disciplined and steady posture towards deepwater drilling. It's positive. I think any of our customers would say that they have a belief that deepwater is going to gain market share here through time, but it's not being strongly affected by the events of this year.

Got it. Understood. My follow-up is just on your commentary on leading edge day rates on recent contracts for Tier 1 drillships now in the mid-400s and close to $500,000 a day, which is evident from kind of the recent contracting we've seen. I mean it wasn't too long ago when we were in the low 400. So just curious if sort of the progression of day rates has increased faster than you would have expected at the beginning of the year or if the pace has been sort of in line with your expectations based on the demand outlook that you have seen.

Yes. So I think there's 2 things going on. The answer is no, it's not surprising. Back in '21 and '22, that kind of time frame, we saw rates move at least as fast, I would argue actually on a percentage basis, much faster. So it happened. So I think there's a couple of things going on. One, we are plus 5-ish units here recently. The marketed utilization is up to like 99%. So probably working utilization matters a little bit more for total pricing. So I think you'd see an even a much bigger move if working utilization -- if working utilization goes up to that 99% range, which, as we said in the comments, you can see a path to that for 2028 right now. But nonetheless, people can see out and see what we see, which is not only 99% market utilization, but a working rig count in late '27 that's roughly equal to where we are today, maybe slightly up from where we are today, which means every incremental contract that's signed for late '27 adds to the working rig count. And so people see what we see and the market is pricing accordingly. I think it makes sense.

Your next question comes from the line of Jeff LeBlanc with TPH Research.

I wanted to see on the jack-ups, is the expectation that the 4 jack-ups should remain in Norway moving forward? Or should we still expect some move between the 2 sides of the market?

Yes. I think we're finally, for the first time in years, hopeful that the 4 newest CJ-70s are going to stay in Norway.

Okay. And then the secondary question is on the global -- Globetrotter, excuse me, is the expectation that, that drillship will remain in the global marketed fleet once the sale completes? Or will it be removed?

Into the GT2, no, it's coming out of the drilling fleet.

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

It's really interesting to hear what you've seen as far as continued support for exploration out there in the marketplace. And I guess that makes me think a bit more about maybe pivoting back to talking about the development side. So of course, products are generally economic at far below the current prices we're seeing. But I'm just wondering, do you -- are you detecting any greater confidence among producers may be reflected in their budgeting for 2027 into 2028, where perhaps the industry is taking the Iran war supply disruptions considerably more seriously than certainly the markets have. So I just wonder if you sense a little bit more urgency on the development side.

Yes. I got to say we have -- from what we see, which granted is never at the very cutting edge of how our customers are thinking about how it gets down to like thinking about drilling rigs. But we have seen remarkably little change in the stance of our customers. And they continue -- by our observation, they continue to use very conservative breakeven oil price assumptions, and they continue to be extremely disciplined. I think -- we're thinking about the future as if that does not change. And I'm fond of saying that we're fans of efficiency because the deepwater is drilling itself into work as it gets more efficient. But we very much see the future of deepwater working because barrels are profitable at that kind of 60s and 70s range and really below that for breakeven, but that our customers are willing to drill and develop large projects at prices that fit nicely into the middle parts of the Brent curve. We haven't changed our stance on that at all in the outlook.

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

Robert, you provided a lot of color on the market. I was hoping to kind of get a big picture around like how we should be thinking about CapEx. I think one of the things, clearly, you guys are generating a lot of cash. I guess kind of a couple of questions around here. But like coming off of the down cycle, kind of like as you look at your fleet today, is it kind of where it needs to be for the next couple of years of the up cycle, i.e. I get we're upgrading the GreatWhite, the Claus rig and -- but like other rigs, right, as we think about where they are, could we be thinking about, hey, you know what, this rig needs this upgrade, this rig needs that upgrade? Or could we actually see kind of a move lower in CapEx as we look out over the next couple of years?

Yes. How about -- let me explain a little bit around the types of upgrades we made, and then I'll hand it to Richard and he can give you a little kind of, I guess, history of our CapEx and how it fit into the cycle. So everything we've done -- the Bachmann, we fundamentally changed the marketability of that rig by making it Norway compliant. So I think that's baked in now that rig is worth substantially more because of its increased earnings power because of the upgrades that we're performing on that rig right now. So it's been -- the rig is capable of working in Norway will go to Norway, and it's a great place for the rig. We're very, very proud to be supported by our customer in moving that rig into that region. Everything else falls into kind of a different bucket, which would be a range of, obviously, maintenance CapEx over to some more specific upgrades. But I'm extremely pleased with where we're going to sit by the end of 2027 on all of our Tier 1 drillships. Every single one of those will have MPD. We will have 2 million, 2.8 million pound Derricks that are highly competitive in the U.S. Gulf.

We've added grown non compensators where needed. And already a majority of our fleet has larger thrusters that allow them to work effectively anywhere around the globe. There's are a lot of drillships out there that actually can't work in some of the emerging markets. So -- it's obviously coming at a cost right now in '26 and in early '27. But we are so well set up with the quality of our fleet going into late '27 and '28. These are life of asset upgrades. And I actually think the timing is darn close to perfect for us on having made these investments.

And Greg, just to add to that, obviously, we're spending a lot of capital on the fleet right now. That will continue, if you will, to kind of mid next year. But obviously, the earnings power that this kind of increases or the increase in earnings power around that fleet is significant. So once you get to kind of second half of next year, kind of the EBITDA and free cash flow run rate is pretty significant. Maybe just to put kind of normalized CapEx into focus here. What we said at the beginning of the year was that net CapEx would be in the high 300s to kind of $400 million range on a normalized basis. This would exclude the Claus Bachmann. We are seeing some inflationary pressure. So I think you should think about normalized CapEx for us in the high end of that range, so within that kind of $400 million kind of area type context. Obviously, that excludes the Claus Bachmann. And as you think about 2027, we probably have just over half of the Claus Bachmann CapEx to spend in 2027. So from a kind of a net CapEx perspective, I think hopefully that gives you some guidance here for kind of '27 and beyond.

Yes. And just so as we think about that rig, that rig is starting up in March. So when it leaves for that maiden voyage, that it's good to go. It's not going to go back in, right?

Correct. That is right. Yes.

Okay. And then I did have one other question. Just -- Robert, this is for you. Just it's been interesting I mean, clearly, we've always seen rig pocket contract, right? Obviously, you guys have the 4 rigs with Exxon and Guyana. You were able to get those 2 Shell rigs. This development work, we've been talking a lot about development drilling. But I guess my question is, at this point, as we look out over the next couple of years and our understanding is there is still a couple of opportunities for multi-rigs going with one customer in one region for development drilling. Are we at a point now with the fleet where we need to start maybe being a little more selective in some of the work we're doing simply because we want to be in the right place at the right time to potentially win some of these multi-rig tenders?

Yes. So there are multiple multi rig development programs out there. And I think that's one of the things that makes us so excited going into exiting '27 because those we think now we have some clearer sight that those are going to come through. I think we've always been selective. We have really embraced efficiency and technology, as I mentioned, around the CapEx upgrades. And those really pay for themselves in development projects way more than anywhere else. And so we've targeted and really wanted to be in some of these bigger development projects. I think we've done a good job with had a fair amount of success there. That won't necessarily change for us, and there are some additional projects out there that are on the table for us and nothing is done yet. But obviously, pricing has moved and we'll continue to move with whatever the market dictates. But nothing's really changed about where we see our strengths as a company.

There are no further questions at this time. I would like to turn it back to Ian MacPherson for closing remarks.

Thank you, everyone, for joining us today. We appreciate your interest in Noble, and we will look forward to speaking with you next quarter. Have a great day.

This concludes today's conference call. You may now disconnect.

Hello, everyone. Thank you for joining us, and welcome to the Noble Corp. Second Quarter 2026 Earnings Call. After today's prepared remarks, we will host a question-and-answer session. [Operator Instructions]

I will now hand the conference over to Ian MacPherson, Vice President of Investor Relations. Ian, please go ahead.

Thank you, operator, and welcome, everyone, to Noble Corporation's second quarter 2026 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. We also have with us Blake Denton, Senior Vice President of Marketing and Contracts; as well as Joey Kawaja, Senior Vice President of Operations.

During the course of this call, we may make certain forward-looking statements regarding various matters related to our business and companies that are not historical facts. Such statements are based upon current expectations and assumptions of management and are therefore subject to certain risks and uncertainties. Many factors could cause actual results to differ materially from these forward-looking statements, and Noble does not assume any obligation to update these statements.

Also note, we're 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'd like to turn the call over to Robert Eifler, President and CEO of Noble.

Thanks, Ian. Welcome, everyone, and thank you for joining us. On today's call, I will first briefly recap the second quarter results and then cover our recent contract awards and market outlook, including our semiannual assessment of global deepwater rig demand. Next, Richard will provide a financial overview, and then I'll wrap up with closing remarks before we go to Q&A.

Starting with the second quarter, we reported adjusted EBITDA of $212 million. We have maintained our robust return of capital program, returning an additional $80 million to shareholders through our $0.50 per share quarterly dividend in Q2.

And yesterday, our Board declared a $0.50 per share dividend to be paid in September. Q2 was adversely impacted by $43 million due to an operational suspension that impacted both of our rigs in Brazil. Richard will provide additional detail on how we have factored this into our revised guidance for the year.

Apart from this discrete headwind, operational and financial performance across the balance of the fleet was strong and was complemented by a successful debt refinancing in June.

On the commercial side, we have secured 2 new contracts over the past 3 months. First, the Noble Viking has been awarded a 6-well contract in the Asia Pac region, expected to span most of 2028 with options into 2029.

And additionally, the recently renamed Noble Claus Bachmann, originally the Ocean GreatWhite, has been awarded a 3-well contract with BP in the U.K. North Sea with an estimated duration of 150 to 210 days at $320,000 per day, plus mobilization fees.

This program is slated to commence in March 2027, directly preceding the rig's 3-year contract with Aker BP in Norway. This renaming recognizes the years of service and leadership from Claus Bachmann, our VP of Operations in Europe.

Having recently celebrated our 105th birthday as a company, we're proud to carry on the valued tradition of periodically naming rigs in honor of long-tenured employees who have made a lasting impact here. Claus, thank you, and congratulations.

On a combined basis, we have booked approximately $200 million of new backlog across these awards with our backlog as of the fleet status report published yesterday, now standing at $6.8 billion. I would also add that we anticipate signing several additional contracts fairly soon, which would further augment our backlog. So stay tuned.

Now on to the market outlook. While the Iran conflict continues to exert preternatural volatility on oil prices, underlying demand for our business has been more stable by comparison and continues to trend in a positive direction overall.

For starters, 77 rig years of UDW backlog contracted during the first half of this year was by a comfortable margin, the highest level seen in well over a decade. And on the back end of this historically large surge of fixtures and despite the withdrawal of most of the ONGC rig tenders that surfaced earlier this year, open floater demand of over 95 rig years still remains at a notably high level, especially considering that all of this open demand pertains to markets outside Brazil.

Put differently, open floater demand in the rest of the world, excluding Brazil, is actually about 20% higher compared to the recent high watermark of 2 years ago. Global UDW floater utilization remains firm with 104 rigs contracted now or in the future, which is down 1 rig quarter-on-quarter, but represents 95% contracted utilization of the marketed fleet and 87 UDW units currently under contract, equating to 79% current utilization.

We continue to expect the latter statistic to trend upward over the next few quarters as long-term programs ramp up, including several of our own. As the market continues to firm up, day rates have recently begun to move higher with recent fixtures in the mid-400,000s per day. Current bidding and recent fixtures have generally been characterized by higher rates for longer-term programs out into the future versus lower rates for near-term gap filler work.

At a high level geographically, recent developments essentially distill into a tale of two halves, i.e., a slightly reduced demand picture in the Western Hemisphere, driven by softer activity in the U.S. Gulf and Brazil, which has been more than offset by Eastern Hemisphere strength, keyed by Africa and Asia-Pacific. On a combined basis, global UDW demand looks as strong today as we have seen at any time in the past several years.

Starting first in South America, UDW demand is currently 41 units, down from 44 compared to 6 months ago. Brazil comprises 32 of these 41 rigs and is down from 34 at the beginning of the year.

Petrobras' activity reduction has been the primary downward driver in the region. And upon conclusion of the Noble Faye Kozak's contract, Brazil is expected to decline by 1 additional unit.

The rest of the region appears poised to grow moderately, keyed by baseload demand of 7 to 9 units throughout the Guyana-Suriname Basin, where Noble has drilled approximately 75% of the wells to date, plus an expanding array of opportunities of longer and shorter duration spanning Colombia, Peru, Uruguay and potentially Venezuela. In total, we expect the South American region to absorb about 2 to 3 incremental units over the next year or so.

The U.S. Gulf has softened recently, dropping to 19 units currently versus 21 as of 6 months ago. While current customer indications support higher levels next year, there remains a limited amount of near-term activity to bring the rig count above the high teens over the balance of this year.

Commonly a more economically sensitive basin, the recent volatility with crude prices hasn't necessarily been helpful, although current oil prices, if maintained, should certainly support a stabilized market of 20 rigs over time. Meanwhile, the likely departure of 2 to 3 units for international opportunities is expected to keep drillship capacity in the Gulf fully utilized.

Next, in West Africa, contracted UDW demand stands at 14 rigs, down 1 versus 6 months ago with a strong pipeline of open demand throughout the region, comprising 22 rig years across public tenders and pre-tenders throughout the West Africa plus Mozambique region.

This includes 7 long-term programs with average duration of 2.5 years, spanning Namibia, Nigeria, Ghana, Mozambique and Cote d'Ivoire, supplemented by a variety of smaller-scale requirements throughout Angola, Mauritania, Congo and Equatorial Guinea.

The African market appears poised for further growth into the high teens by the second half of 2027. The Mediterranean Black Sea region has grown as expected to an all-time high of 12 UDW rigs, up 1 unit compared to 6 months ago.

There are currently 2 open tenders in the Med as well as 2 contracts expiring during the second half of this year. We continue to assess this as a structural 10- to 12-rig market going forward, underpinned by Turkey's upsized fleet of 6 owned drillships.

Next, the Asia-Pacific plus India region continues to be perhaps the most dynamic growth market for deepwater with a recent range of 10 to 11 contracted UDW rigs, up from 8 rigs 6 months ago, and representing a multiyear high since pre-COVID times.

Meanwhile, the open demand pipeline is increasingly promising. Even despite the withdrawal of 4 of ONGC's 5 long-term rig tenders, open demand in the region still currently stands at 42 rig years.

This equates to 45% of total open demand globally compared to a current rig count share of only 10% of the global total. While some of these requirements are expected to be satisfied by existing capacity in the region, Asia Pac could expand into the low teens by late 2027 with optional upside on a longer-term basis related to India.

Recent indications are that India's multi-rig exploration campaign is likely delayed by about a year due to planning and funding lead times rather than canceled outright. Rounding out the global picture, the harsh environment in North Sea and Norway market currently represents 24 units of total floater demand, 9 of which are satisfied by UDW semis, both of which are up 2 units compared to 6 months ago. Norway comprises about 80% of the floater rig count in the region, including all 9 of the UDW units.

Despite persisting regulatory and fiscal headwinds, open demand in the region indicates the potential for increased activity. However, with 100% contracted utilization in the region currently, any potential rig additions, whether for Norway, West of Shetlands or incremental P&A scopes in the U.K. sector would require harsh-semi capacity to migrate back from other international locations.

Rolling all of these regional outlooks together, it's realistic to see a path to today's marketed fleet becoming essentially fully contracted by late next year. This is very similar to the industry status and outlook that we've held in mid-2023 prior to the demand downturn that tracked with Brent prices melting from $90 per barrel down to $60 by the end of 2025.

However, with global oil inventories and sideline rig capacity both significantly tighter now versus a few years ago, plus the increasing premium on energy security worldwide, we are optimistic about the direction of the deepwater market from here.

Before passing the call over to Richard, I'd like to also touch on the CJ-70 jackup market, which is gaining traction as well with 100% contracted utilization across all 11 units in Norway and the U.K. We are looking forward to the Noble Interceptor's reactivation later this summer for a 5- to 8-month accommodation program and are bidding the rig toward promising opportunities for subsequent drilling activity in 2027.

In the U.K., we have transferred most of the Noble Innovator's remaining backlog with BP to the Noble Intrepid, which has removed some revenue from the second half of this year while availing the Intrepid for incremental opportunities in 2027. Overall, day rates for the CJ-70 are generally flat, and we are optimistic about securing improved utilization in '27 compared to 2026.

With that, I'll pause here and pass the call to Richard.

Thank you, Robert, and good morning or good afternoon, all. In my prepared remarks today, I will briefly review the highlights of our second quarter and then discuss the outlook for the remainder of 2026.

Starting with our quarterly results. Contract drilling services revenue for the second quarter totaled $679 million. Adjusted EBITDA was $212 million and adjusted EBITDA margin was 30%.

Q2 cash flow from operations was $144 million. Capital expenditures were $205 million and free cash flow was negative $59 million. As Robert mentioned, Q2 was adversely impacted by $43 million due to the operational suspension of our 2 rigs in Brazil.

I'd also like to highlight a few additional items that impacted the quarter. Firstly, we completed the lease buy-out on the third of 4 Blackships BOP systems for $18 million, which impacted Q2 cash flow. The buy-out of the last remaining BOP system is expected to occur in the fourth quarter for the same amount.

Secondly, we recorded a $42 million impairment in the second quarter associated with the sale of the scrap proceeds of the Ocean Apex. The closing occurred in early July, generating net proceeds of $5 million.

Lastly, we refinanced all of the legacy Diamond bonds plus the portion of the existing Noble bonds in June with the issuance of $800 million in new 6.25% senior unsecured notes due 2034. This refinancing enables us to simplify our capital structure into a single credit silo, unlocking $35 million in annual cash benefits, primarily interest expense and tax-related going forward.

As summarized on Page 5 of the earnings presentation slides, our total backlog as of July 27, stands at $6.8 billion. As a reminder, our backlog excludes reimbursable revenue as well as revenue from ancillary services.

Our current backlog includes approximately $1 billion that is scheduled for revenue conversion during the remainder of 2026 and $2.3 billion scheduled for 2027.

In addition to the new contract awards that Robert highlighted, our current backlog reflects the transfer of backlog from the Noble Innovator to the Noble Intrepid as well as an earlier anticipated end date for the Noble Stanley Lafosse in January 2027 rather than July 2027 previously.

For this rig's wells-based contract, the well sequence has shifted, which has resulted in an earlier expected completion of the campaign. With respect to the Noble Courage and Noble Faye Kozak, both rigs are currently operating in Brazil.

However, our revised guidance does reflect an additional revenue reduction of at least $15 million through January 2027 as we work towards administrative solutions following the suspension.

Referring to Page 9 of the earnings presentation, we have updated our full year 2026 guidance for total revenue to a new range of $2.8 billion to $2.9 billion, down from $2.8 billion to $3 billion previously, and this still includes approximately $150 million in reimbursable and other revenue.

We've also revised guidance for full year adjusted EBITDA to between $850 million and $925 million, down from $940 million to $1.02 billion previously. This reduction is driven primarily by adverse revenue impact from our Brazil rigs, but also by the Intrepid/Innovator swap and the Viking options likely moving into 2027.

Capital expenditures guidance for this year is unchanged at a range of $615 million to $665 million. As a reminder, this range includes estimated customer reimbursable CapEx of $25 million.

With that, I'll now pass it back to Robert for concluding remarks.

Thanks, Richard. To wrap up, despite our recent revenue headwinds, we continue to see very encouraging indicators across the deepwater and ultra-harsh jackup markets that should support a meaningful earnings inflection by the second half of next year, at least as strong, if not better, than what we have previously described.

This outlook is predicated on contract start-ups that are already in backlog, plus a relatively small handful of contracts to be secured against our limited remaining available capacity in 2027, including the BlackRhino, BlackHawk, Viking, Stanley Lafosse and Faye Kozak.

The opportunity set confronting these units looks very promising with utilization and day rates trending better. And we do expect to have some contract news to report for some of these units relatively soon.

Meanwhile, we are intently focused on delivering our contract start-ups on a timely and budgeted manner. And we have a very strong financial position and capital return program intended to afford shareholders the luxury of being paid to wait for the next leg of the cycle and Noble's cash flow trajectory to kick into high gear in the second half of 2027.

With that, I'll turn it back to the operator for questions.

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

Robert, I was wondering if you could elaborate on your commentary on just general demand trends you're seeing in the Eastern Hemisphere versus the Western Hemisphere. And just thoughts about how this could inform your future strategy on what markets that you'd like to play in.

Obviously, as we sit here today, Noble has quite a bit of leverage to the U.S. Gulf of Mexico or Gulf of America and obviously, a great program with Exxon and Guyana. But how should we think about future rig moves because you are arguably a little bit underrepresented in West Africa and Asia Pac?

Yes. No, thanks for the question. So I guess what I'd say is the increase in open demand and actually activity in Asia Pac, and I don't know if I would call it a surprise, but certainly an upside that wasn't assured a couple of years ago.

So that's very welcome to the entire market. We said in the prepared remarks, the situation in India has been a bit fluid as everybody knows. And we mentioned in there too, we hope that those tenders will come back into view after a year or so delay. So I think there's some more upside, not only from India, but also kind of spread out around the region there.

I think that region, one could assume, is particularly affected by some of the heightened energy security issues that have come out of the conflict in Iran. And I think that we can anticipate seeing some activity that bridges from that.

So we've been a long-term player there, as you said, oftentimes smaller. Way back, we had, I guess, fewer jackups than some of our competitors had there, but it's really never been a substantial floater region. We've been in Australia for quite some time, but then it's always been just a handful of floaters and oftentimes in somewhat more captive markets. And that's what's changing right now.

There is a demand for drillships, which wasn't the case earlier in my career. And we're pretty excited about what all of that might bring.

For Noble specifically, which is your question, I could easily see an additional unit moving over there, but it's a little too early to say definitively on that right now.

Got it. Got it. And you mentioned...

And West Africa, let me just -- yes, sorry. West Africa, we've been there for -- Asia Pac, that's actually my first region I covered. That has been the -- that was the growth story early, and then the kind of pause story that we're working through right now, and continues to be the growth story going forward. I listed the countries in my prepared remarks.

We believe -- well, a lot of the uptick there is already FID-ed and some of it contracted. But we think that, that is very real. And we're very optimistic about the additional demand that's going to be represented there, kind of, West Africa all the way around Mozambique over the next 2, 2.5 years for start-ups.

And that's going to cover up to 5 or 6 years from now in terms of contract coverage for the market. So yes, and I can also see Noble expanding our presence there as well. But again, a little too early to tell.

Yes. Great. And Robert, you mentioned a couple of times that it sounds like you're quite optimistic on some near-term contract news, which will hopefully improve some of the utilization trends. Any things you can maybe unpack a little bit? Is this perhaps opportunities for some of the idle floaters today? Or is this kind of maybe opportunities to add on to backlog in existing rigs that are working today?

Yes. Here's what I'll say: so of course, most of the work out there is weighted towards second half of 2027. And we have a number of opportunities, all of which, of course, won't go to us that will go -- that will really help demand around the industry.

And that's the single point of the most optimism that we hold right now. I think we're clear in the comments about that. But I would also say that we do have -- at least we have an opportunity that would potentially start this year.

And then we have a couple of others that would start in, kind of, first quarter, second quarter of next year. And so we would be talking about those if we could right now. We still have a little bit of work to do, but we're pretty hopeful that we'll have some news here in the coming quarter.

Your next question comes from the line of Jeff LeBlanc with TPH & Co.

I wanted to see if you could talk about the resequencing and outlook for the Noble Developer. Outlook for the Noble Developer.

Sorry, yes. Oh, yes. Sorry, sorry. Thank you. Look, what I'll say is the D class rigs have been in very high demand in a couple of different regions around where they're best fit technically.

And that kind of CARICOM region is one of those places and then in Australia as well. The outlook for the D rigs has perhaps changed the most dramatically in a positive way over the last 18 months.

And those rigs are among the highest quality and most marketable rigs globally in the specific areas that benefit a semisubmersible that has both more a BP capability. And so there's around in CARICOM, I would say right now, there's more work than there are rigs that can perform the work, which is great.

And the resequencing there is something that we're extremely supportive of and we think will ultimately be better not only for Noble, but also for the various different customers that need rigs down there in the near term. So there's a pipeline of potential work behind what we've booked. And we're very hopeful that we can tag on some additional work around there.

Your next question comes from the line of Scott Gruber with Citigroup.

I had a question on how we should view the available rig time in '27. You noted that UDW rates are ticking up into the mid-400s (sic) [ mid-$400,000s ] as exemplified by the Viking contract, but that starts in '28.

And so do you think you'll be able to book if you do take a 1-year job in '27 for some of the available rigs, do you think the market is at the point where you could get mid-400s for a 1-year job? Or do you really have to be looking at work out into '28 or multiyear jobs to be in that mid-400s range?

Well, let's see, Scott. What I would say is you mentioned what we had said where we think the market is pricing right now out in '27 and '28. There's been quite a range over the last 18 months, 12 to 18 months.

And that probably is slowing or narrowing, but it definitely persists today. So I actually think the market will track just like the norm. And we've seen some deviations from the norm over the past 5 years, but I think it will track generally with the norm where gap filler type work is going to be priced at a discount, which is natural and longer-term work is going to be priced at a slight discount, which is also very natural.

And then everything, kind of, else fits into the middle there, which would be that type of range I mentioned on the prepared remarks.

That makes sense. It makes sense.

And we do think -- we do see -- if I just reiterate, we do see a path, as we mentioned, in '27 here to full utilization for the entire industry floating drillship fleet for sure, a high-end fleet. And so those contracts are in process, and it's going -- it's not going to become entirely evident in the next week or even a couple of months.

But the programs are there, in many cases, and we've heard some of the service companies mention this, the FIDs are largely there for a lot of it. Our customers are in budget season right now. And of course, we discover more about that towards the end of the year. But we're, I'll repeat, we're as optimistic as we've been about second half of '27 forward here on the demand we see.

That makes sense. Things are clearly moving in the right direction. And then just coming back to the revenue impact on the Kozak and the Courage, you mentioned an additional $15 million through January '27. Just any additional color on how the $15 million hits 3Q, 4Q or a bit in January? Just how to think about that.

Yes. I would just say I would spread that out over kind of remaining second half of this year. We've never given specifics on cash flow on quarters. And that contract is very early in January anyway. So this is really a second half '26.

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

Robert, I wanted to continue the conversation about the administrative solutions currently being negotiated with Petrobras. Can you just go into a little more detail about what these might be? Are they day rate reductions, additional idle time? Is an early termination of some work a possibility here? Just trying to frame the potential outcomes here.

Yes. Thanks, Doug. So what I'll say, which we've said is that the rigs had some shutdown time during May and June. That was a result of an ANP audit, which is a regulator down there.

And that is an ongoing matter that -- unfortunately, I would have a very incomplete answer for you today because we cannot say much about it. But I can offer that our revised guidance reflects not only the $15 million that Richard mentioned, but also a range of outcomes that could go kind of on either side of that as we work through all this. Both rigs are operating today, and we're just working through all of that with the regulator down there.

I appreciate the sensitivity there. And maybe just any more color you can provide just on the Lafosse? I'm just trying to get a sense, is this something we might see more in the future? Or is it really just schedules getting shifted around and not indicative of a trend you might see going forward?

Yes. So that's a wells-based contract. In times past, that's worked in our favor. In this instance, it obviously hasn't for 2027. The customer will be continuing with the rig line.

They're out to tender for that. Noble is participating in that tender. And it's a little too early to tell exactly, of course. That's ongoing. So we don't have an answer there.

I guess I would offer that, that rig with -- along with this resequencing, it obviously increases the likelihood that, that rig could work elsewhere, either in the U.S. or actually outside of the U.S. Gulf of Mexico, where there's some opportunity.

Your next question comes from the line of Ben Sommers with BTIG.

So kind of to build off the last question, curious looking at the 2027 kind of opportunities we're seeing in the U.S. Gulf. I know we have the BlackHawk rolling off at the end -- later at the end of this year, and then we have BlackRhino still there. Just kind of curious what you're seeing for the opportunities in the U.S. Gulf. And then I guess just what it would take to potentially maybe move rigs out of that region.

Yes. Thanks. Good question. So I mentioned earlier that kind of how the timing of the starts of the stuff we see and how those are weighted, which, of course, is more towards the back end of '27.

There are hope for our rigs, there are opportunities in the U.S., Gulf of America, in West Africa and in Asia Pac that -- and sorry, and I skipped over Central and Northern South America, where we -- there's a lot out there that right now is yet to be contracted. So I think you could anticipate 1 or 2 of our rigs moving regions. And I think that's a good thing in the long run. And so we're working through all of that right now.

Super helpful. And then as we think about the sale of the Apex and just fleet optimization moving forward, kind of any color there on just how you're thinking about the broader fleet?

No, we like where our fleet sits today. The GT2, obviously, is held for sale. We haven't had any announcement on that, but it is held for sale. Outside of that, we have a pretty well contracted fleet even among some of the older rigs.

And we manage that carefully like you would with any older rig, but they've generally performed well and are producing cash flow for us right now.

Your next question comes from the line of Keith Beckmann with Pickering Energy Partners.

Just kind of wanted to ask around now that the Ocean Apex has been scrapped and sort of follows up on the last one, I mean, are you thinking about potentially the Globetrotter 1? I mean is that -- do you think contract there is potentially still realistic?

Or do you think disposal could potentially be more likely? And then maybe more broadly, how do you think just about kind of macro-wise? Do you think some of these older lower-spec assets potentially start to sort of get scrapped more and more? Just any thoughts around all that.

Yes. So the GT1, we've said, is bid essentially for intervention work. And we've just finished in the Black Sea. So there's -- including that plus another opportunity or two, there are a few drilling wells out there that are uniquely suited to the Globetrotters because of their design and capabilities.

So where only a Globetrotter can reasonably perform the drilling work, we've been bidding that. And then outside of that, it's -- they're actually very well suited to intervention, and we've been working hard on finding some intervention work for the rig. We don't have anything to announce on this quarter, but nothing has changed in how we're approaching the market with that rig. Yes.

Sorry, Keith, you asked more broadly as well. Look, of course, everybody sees what we see around demand in the back half of '27, I assume.

So of course, scrapping would generally be slower in -- with visibility like this. In a very old rig, let's say, 40 years plus, 35 years plus, something like that, it's always a judgment call based on the specific availability of work for that rig.

So SPS costs go up and every drilling company ever looks at costs, which cover you for effectively another 5 years and trying to make a determination based on the outlook of whether it's worth putting the capital back into the rigs.

So I don't remember the number, 20 or so rigs out there that probably fall into that bucket. And those are always going to be evaluated on kind of an SPS-by-SPS basis. And if in a specific instance, the market is not lining up for a specific rig, that's where you can see someone making a rational decision, whether it's us or someone else.

That's just kind of how the business works. So I think you'll see some of that. But I also think the incentive to be extremely disciplined around fleet management has dissipated a bit from, say, a year or 2 years ago.

Awesome. No, that's very helpful. And then my follow-up question, I just wanted to ask around -- obviously, there's been talk around energy security and that potentially adding more into the market.

The last few months, contracting has been a little bit slow. I just wanted to get a sense on if you think -- and you guys hit on this a little bit, the volatility around, obviously, the commodity price bouncing back and forth a lot. Do you think that's what's holding up a lot of these projects and energy security over the long term wins out here and maybe more contracts to see over the next several months? Just trying to get a sense on why you think things have been a little slower here and if that lines up.

Yes. I think the way I think about that is, obviously, oil price volatility has been significant. I do not think our customers -- it's a question for them, obviously, but I do not think our customers generally have raised their long-term pricing outlook.

And the middle part of the Brent curve really hasn't changed. It's changed by a couple of bucks total through all of this turmoil. So long-term outlooks haven't changed dramatically based off of oil price.

I think you are very much seeing the effect of this trend, which has been ongoing for several years now of a rotation somewhat away from the Permian and back into deepwater. And if you look at decline curves and all of that, that supports the deepwater market quite well.

And we've said this for quite some time, and I think there's an extremely strong thesis around deepwater and the need and the call on deepwater barrels over the next few years and then continuing for decades past there.

And I think that trend has produced a number of the FIDs that we've seen, and it's going to drive this uptick that we're predicting in 2027. But I do not think that it's been dramatically changed positively or negatively by the world events so far in 2026. That's a steady trend that's been ongoing. And of course, it's good for us.

And then if you look at specifically the energy security, that's an even bigger ship to turn than long-term production for some of these massive customers, which are massive organizations. That's geopolitical.

And I think you can anticipate that energy -- the demand growing out of energy security would take even a bit longer because it has to work its way through, obviously, political processes and governmental and regulatory processes.

Oftentimes, it would then be put to more of an NOC than a major. And I think that's something that very naturally would not have manifested at this point after the Iran conflict broke out.

So all that's to say, we haven't changed our view at all, nor have we based any of our view, I think, on overly optimistic visions of the future because I think primarily what everyone is planning around is the Brent oil curve that hasn't changed that much and people are continuing to screen well.

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

I just wanted to pick up on what you mentioned about the rotation or the notion of rotation from the Permian to the deepwater. And sort of as a reality check, I -- we have been hearing from some of the onshore-only players sort of about new formations that they're pursuing across some of the shale basins with these formations being presented as sort of like an exciting frontier.

And -- but from what I'm understanding you're hearing, it sounds like the customers who are both on and offshore are not changing their opinion about core exhaustion in the onshore at all and that is a motivation for getting back offshore.

Yes. So to be clear, I'm making no comment on onshore feasibility, viability, new formations. It's not our business. We're not close to it.

If you ask my personal opinion, I think the Permian always outperforms and will continue to because it's a real innovation generator there and what they can do technically is unbelievable over the past -- over a decade, as everybody knows.

I think the whole world is searching for how to replace the known decline in global oil reserves going into the 2030s. I'm for sure they're looking in the Permian and using technology to leverage that. And for sure, they're looking elsewhere on land.

For sure, everyone is looking for additional shale plays. I just feel confident and particularly backed by conversations with our customers that within all of that mix, deepwater screens well. It has huge denominators and good carbon footprints, which still matters in a lot of instances and is likely to gain market share going into the 2030s.

It's obviously not going to be any sort of sole source, but it's, I think, set up and screening very well. And we're seeing the proof, again, in what we're seeing through sanctioning right now.

And I talked one of the big -- I mentioned exploration on this call, but we've talked about exploration before. Kind of one of the big unknowns right now is where does exploration go into deepwater.

We've heard a number of anecdotes from our customers that we can anticipate that that is going to increase. And so I think all eyes on that as an early indicator on some of this. And it's -- that's, I think, something that we can anticipate over the next couple of years, hopefully increasing and setting up the future.

Great. And as we look over the past year, 1.5 years and how the contracting pace and utilization has had its fluctuation down and then has turned back up again, the producers do seem to have benefited from a fairly gentle increase in day rates that were at least among what we've been hearing.

I just wonder, just from your example of your experience with past cycles, do you sort of have any examples in mind of what could sort of steepen the day rate increases from here? I mean, maybe it's just as simple as utilization by region gets to a place where people get a little nervous and want to be sort of more assured that they can secure the rigs they want and the timing they want. But any thoughts there would be great.

Yes. I mean, look, in my career, we've seen instances where day rates move extremely quickly in both directions. And that's not been -- that's not how this market has been over the past year or so. And I actually think that's a very good thing for everybody.

Typically, to have a sharp turn upward on day rates, you need to have a real sense of scarcity felt in the marketplace. That is not the case right now. I think you could make an argument that perhaps you're a little closer to that as you look into '27 than we would have been a year or more ago.

But the -- I guess the [indiscernible] for a customer oftentimes is to simply not drill and to wait. And that's still very much on the table, I think, for a lot of our customers. And they are going to continue to be disciplined.

We mentioned price targets earlier and budget. We don't anticipate any change in their commitment to discipline here. And so we actually think that the path forward here is a bit more -- a bit less severe and perhaps you've got more organic, where demand ticks up towards a fixed supply.

And that creates higher utilization, which gives rise to some upward pressure on day rates, but probably not from what we foresee right now with any massive spikes upward, like, kind of, what we've seen in times past in 2005, '06, when I came into the industry and then we saw it again after the short bounce down in around 2011, 2012.

So we've seen it happen. I think right now, we are hoping for and anticipating something that's a little more predictable and flatter.

And let me just close by saying that works both ways because if you look at what has kind of played out to be quite, perhaps, short term, but somewhat dramatic downtick here that we're living through right now, day rates held up quite well through this. And so what I'm hoping we're seeing is a bit of a smoothing on the volatility on day rates. And again, I think that's very good for everybody.

There are no further questions at this time. I will now turn the call back to Ian MacPherson for closing remarks.

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

This concludes today's call. Thank you for attending. You may now disconnect.

Hello, everyone, and welcome to Noble Corp First Quarter 2026 Earnings Call. Please note that this call is being recorded. [Operator Instructions]

I would now like to hand the call over to Ian MacPherson, Vice President of Investor Relations, you may now go ahead.

Thank you, operator, and welcome, everyone, to Noble Corporation's First Quarter 2026 Earnings 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 in the Investor Relations page of our website as well. Today's call will feature prepared remarks from our President and CEO, Robert Eifler, as well as our CFO, Richard Barker. We also have with us Blake Denton, Senior Vice President of Marketing and Contracts; and Joey Khawaja, Senior Vice President of Operations.

During the course of this call, we may make certain forward-looking statements regarding various matters related to our business and companies that are not historical facts. Such statements are based upon current expectations and assumptions of management and are therefore subject to certain risks and uncertainties. Many factors could cause actual results to differ materially from these forward-looking statements, and Noble does not assume any obligation to update these statements. Also note, we are referencing non-GAAP financial measures on the call today. You can find the required supplemental disclosure for these measures, including the most directly comparable GAAP measure and an associated reconciliation in our earnings report issued yesterday and filed with the SEC.

Now I'll turn the call over to Robert Eifler, President and CEO of Noble.

Thanks, Ian. Welcome, everyone, and thank you for joining us. I'll open today's call with a brief summary of our Q1 highlights and recent contract awards, followed by an update on the market. Richard will then cover the financials before I wrap up with closing remarks and move to Q&A.

During the first quarter, we earned adjusted EBITDA of $277 million and generated free cash flow of $169 million. We again distributed our 56th quarterly dividend and yesterday, our Board declared a $0.50 per share dividend for the second quarter, maintaining our consistent and highly differentiated return of cash strategy. Overall, it was a solid start to the year and I'd like to thank our outstanding men and women of Noble around the world for your fantastic teamwork in helping us to realize our first choice offshore performance standards. While it's an understatement to say that energy markets have seen extreme volatility over the past couple of months since the outset of the Iran conflict, we are fortunate to have experienced limited operational disruption confined to just 1 jackup in the Middle East, the Mak O'Brien, which we sold in January but have continued to operate under a bareboat agreement.

All of our crew and related personnel were safely evacuated from the rig during the early days of the conflict, and Richard will expand on the rig's current status. Outside of the war impacted region in the Middle East, commercial momentum throughout the offshore drilling market remains brisk, irrespective in many ways, of the recent oil price surge. However, the recent reawakening of energy security concerns around the world and the corresponding move higher in the oil futures strip are clearly supportive of the already steadily improving demand trends evident in the deepwater and harsh environment offshore markets where we operate.

Over the past 3 months, we secured new contract awards totaling approximately $565 million. First, the Noble courage received an extension with Petrobras of slightly more than 3 years which will keep that rig committed in Brazil through the end of 2030. This extension represents net incremental backlog of $339 million with the current day rate reduced from $290,000 to $280,000 from April 1, 2026, through late 2027 followed by the extension of slightly over 3 years at just over $309,000 per day.

Next, I'm pleased to announce that the Noble Deliver has been awarded a 5-well contract from Woodside in Australia, which will support that rig's reactivation. This contract is valued at $121 million based on an estimated 300 days of firm scope, excluding options, and also does not include revenue for additional services or potential rig upgrades. In Guyana, the Noble developer has been awarded a 1-well contract with ExxonMobil at $375,000 per day, which is scheduled to slot in after the rig's current program right around year-end.

Next, the Noble BlackRhino has recently commenced an exercised option well for Beacon in the U.S. Gulf with an estimated duration of 100 days. In Ghana, the Noble Venture has been awarded a 1-well contract with Planet 1 in Ghana at a day rate of $430,000 expected to commence late this year with estimated duration of approximately 45 days with 2 unpriced options.

And finally, in Southeast Asia, the Noble Viking has received an additional 1-well contract in Malaysia, which is expected to extend the rig through October this year. With these awards, our current backlog stands at $7.5 billion.

Now I'll share a few observations on recent developments in the market. In short, all measurable and anecdotal indicators of deepwater rig demand are flashing green, and I would submit that this is not a reflection of $100 oil because most of what we're seeing in the market today has been in motion for months or longer. But of course, recent events absolutely have elevated energy security priorities around the world and improved upstream cash flows will only serve to enhance an already strong and expanding demand picture and deepwater exploration thesis. In parallel, the volume of deepwater contract fixtures have spiked in the early part of this year, partially but not entirely due to the execution of Petrobras' wide-reaching contract extensions. The first quarter saw 32 rig years of UDW fixtures, which was roughly double the average quarterly run rate of last year. And with conclusion of Petrobras' extensions in April, this month alone has already had more than 40 additional UDW rig years fixed, bringing year-to-date backlog additions significantly above the entirety of last year's contracting volumes for the full year.

Petrobras has comprised over half of 2026 year-to-date deepwater rig years fixed and non-Petrobras contracting activity has also continued at a healthy level. And notably, despite this recent surge in contract fixtures, the pipeline of open demand in the form of tenders and pre-tenders has actually continued to expand rather than deplete. Last quarter, we observed slightly over 100 rig years of open floater demand, which was a 33% year-on-year increase. This figure has now eclipsed 110 rig years. All this tendering activity is developing alongside an increasingly tightening supply-demand balance. Total UDW contracted utilization is currently 105 rigs or 95% of marketed supply. This is approaching recent peak contracted demand levels of 2 years ago, albeit with markedly different directional momentum especially considering the renewed length of backlog across the South America region, trucks deposed against open demand throughout the rest of the world that's now more than 55% higher compared to the previous high watermark PAUSE 2 years ago.

The contracted UDW count of 105 includes 14 rigs of future contracts that aren't yet working today, 6 of which happen to be Noble rigs. We have been anticipating the convergence of future contracted utilization in present utilization as a critical factor that could substantially eliminate industry wide space and result in a comprehensively tight market. This convergence becomes increasingly tangible as these 14 future contracted assets ramp up over the next 6 to 12 months with average contract durations of 2 years per rig. Taken together, all these market dynamics are resulting in upward day rate pressure. Therefore, we believe it is likely that we will begin to see floater rates move higher as we move through the rest of this year. So overall, with the continuing positive development of our backlog as well as the state of the drilling market more broadly or even more optimistic about the years ahead than we were last quarter.

Now I'll pass the call over to Richard for the financial review.

Thank you, Robert, and good morning or good afternoon all. In my prepared remarks today, I will briefly review the highlights of our first quarter and then discuss the outlook for the remainder of 2026.

Starting with our quarterly results. Contract Drilling Services revenue for the first quarter totaled $742 million. Adjusted EBITDA was $277 million and adjusted EBITDA margin was 35%. Q1 cash flow from operations was $273 million, capital expenditures were $104 million and free cash flow was $169 million. I'd like to touch on a few discrete cash flow-related items during the first quarter. Firstly, we received $210 million in cash proceeds from the jackup sale to Board drilling. In addition to the $150 million seller note, which is recorded in other assets on the balance sheet. Secondly, we completed the lease buyout on the first 2 of the 4 black ships BOP systems to $36.5 million. The buyout of the remaining 2 BOP systems is expected to occur during Q2 and Q4 this year for approximately $18 million each. In total, the lease buyout for all 4 systems is expected to cost $73 million.

The cash outflow for these payments is not part of capital expenditures, but instead is part of financing activities on our cash flow statement. Lastly, during the first quarter, we redeemed $55 million principal amount of the 8.5% senior secured notes at 103 as an opportunistic and efficient use of capital. As summarized on Page 5 of the earnings presentation slide, our total backlog as of April 26 stands at $7.5 billion. As a reminder, our backlog excludes reimbursable revenue as well as revenue from ancillary services. Our current backlog includes approximately $1.8 billion that is scheduled for revenue conversion during the remainder of 2026 and $2.4 billion scheduled for 2027.

Referring to Page 9 of the earnings presentation, we are maintaining full year 2026 guidance for total revenue between $2.8 billion and $3 billion which includes approximately $150 million in reimbursable and other revenue and adjusted EBITDA between $940 million to $1.02 billion. Capital expenditures guidance for this year has increased by $25 million and this is due to the contract awards supporting the reactivation of the Noble delivery. The lower side of our adjusted EBITDA range is fully contracted by current backlog. Although we have banked a somewhat stronger-than-expected first quarter in terms of adjusted EBITDA, this is offset by a few discrete items, including a recent notice of early contract termination on the Michelin the lower near-term day rate revision resulting from the courage as blend and extend and slightly later estimated contract commencement dates for the Jerry DSUs and Endeavor driven by customer schedules.

Regarding the Mico Brian, recall that we closed the sales of all drilling in January and have continued to manage the rig through the completion of its current contract in Qatar with a corresponding bare boat that we paid to bore into early December 2026. On April 12, we received notice of early release from the customer, ELNG and we are now in the process of winding down operations. The contract termination is effective after 30 days, and this will result in an estimated negative impact of approximately $15 million due to our remaining bare boat obligation through early December as well as stacking costs for the rig.

To sum up, we have had a very solid start to 2026 from a financial short point of view. With continued contract wins in the quarter and solid project execution, we continue to solidify the expected path to a healthy inflection in both EBITDA and free cash flow starting in 2027 as we outlined in detail on our call last quarter.

With that, I'll now pass it back to Robert for concluding remarks.

Thank you, Richard. Starting in the summer with the Voyager, Jerry DeSouza and Interceptor start-ups, followed by the Valiant and endeavor later this year and then the great White deliver and venture throughout next year. We have a sharp organizational focus on project execution. This is a large slate of projects to deliver in a normal time. And these are, of course, hardly normal times, given the various dislocations resulting from the Strait of Hormuz impact. But overall, I'm pleased to report that all of our projects are progressing very well so far. and we're incredibly excited to be preparing for commencement on these important drilling campaigns for our customers. These programs span virtually all of the major non-OPEC offshore basins around the world which are increasingly critical to current and future energy supply.

To wrap up, as outlook for our business continues to improve, Noble is very well positioned to grow into the next leg of the offshore drilling cycle with a strong balance sheet, $7.5 billion of backlog and repricing opportunities across some of the most capable drillships and jackups in the world. If anything, we feel better about 2027 today versus last quarter, given the deliver contract as well as the improving market dynamics confronting our open drillship capacity. Meanwhile, we will continue to drive shareholder value through our robust return of capital program.

With that, I'll turn it back to the operator for questions.

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

Robert, what are the themes of OFS earnings thus far has been just the potential impact from rising energy security concerns on just the CapEx cycle, in your case, what this means for offshore rig demand. Robert, historically, when we've seen a sharp move up in combined prices, it's obviously tend to positively impact shallow water demand. But I was wondering if you could maybe elaborate on your thoughts on how some of these energy security concerns could impact the deepwater. And I'm thinking about are there kind of projects that call it the majors have been sitting on that they may not have pursued in a lower commodity price environment that may come back into the fold at strip.

Yes. Thanks, Arun. It's a good question. I think it's topic on everyone's mind right now, including our end. I'd say a couple of things. First of all, I'd reiterate that I think all of the positive indicators that we mentioned in our prepared remarks and that we're focused on right now started before the conflict in Iran. And so this growing narrative around deepwater, I think, is very real. And I think what I would say is there are certain regions that respond more quickly to oil prices in the deepwater than others. Traditionally, BS Gulf of Mexico has been 1 of those. So we're hopeful that we see something that comes perhaps as an early indicator out of the U.S. I think it's less likely that at this point today, our customers have rewritten their budgets or made huge 5- or 10-year moves that also would be a question for them.

And -- but I think from what we see in here, we don't have necessarily really tangible evidence today of positive changes that have hit us. But I think that we hear obviously positive narrative as you do, and we're pretty hopeful. And we don't really see any way that this doesn't turn out positively for our business on top of everything else that we've already seen. And these aren't necessarily the end all be all on indicators, but the numbers we used just a moment ago I think are really striking. When you think about the amount of deepwater backlog that's been printed so far this year by Noble and our competitors and compare that against the amount of outstanding activity that we've seen. Obviously, our numbers were just open tenders, but there are direct negotiations and everything that comes along with our business behind all that as well.

Got it. Got it. And maybe just a housekeeping question. You guys are buying in your lease options on the BOPs, which you talked about in the prepared remarks, can you maybe help us think about the impact on OpEx from buying in those BOPs I'm thinking about maybe the impact in '26 and maybe as we think about '27 on a go-forward basis when you buy in all 4 of those leases.

Sure, Arun. Yes. So we obviously we're buying in the leases during the course of this year. And on an annualized basis, it will have a benefit to EBITDA of about $25 million. And so in 2026, probably about half of that will be realized.

Your next question comes from the line of Scott Gruber of Citigroup.

Yes. Robert, Richard, I kind of want to follow on Arun's question just around how customers may respond to higher oil prices. And I know it's early days, but -- just curious, in the conversations you're having with customers, are they starting to indicate incremental interest in exploration? I know people were talking about it even before the conflict, but is there a sense that there will be incremental interest in more exploration? Is there incremental interest in infill activity with quick paybacks. Just any additional color you could provide on what the conversations with customers are indicating to the potential incremental activity.

Yes. Thanks, Scott. Look, I think -- so for sure, yes, there is an increase in narrative around -- and discussion around exploration work. I don't know that -- like I said before, I don't know that we can put our finger on a specific example that has a direct cause an effect related to Iran. But I think that generally, we're seeing conversations gain momentum. And I think across the board, the realization that deepwater is going to play a really important part in the supply stack post everything that's happened here. Our hope is that some of the demand that we've seen, whether it be from India or elsewhere is more likely to solidify than before the Iran issue. But today, I'm not sure that there's a direct link so far.

We'll wait and then on the developer deliver, on that rig, you bumped a full year CapEx by $25 million for the reactivation costs. Is that the total cost of restart? Or is there some more spend required next year? And then does the incremental spend, including the upgrade investment that would add to the day rate? Or is that just your restart cost?

Yes, the $25 million is the total we acquired for the Woodside contract. If there are any incremental rig upgrades in the -- there would be incremental capital to that. But think about the $25 million is what's needed for the Woodside contract. Scott.

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

You highlighted the high EDW contracted utilization currently at 95% and that the market is beginning to tighten here, which, of course, results in higher pricing over time. We haven't quite seen that move up in day rates yet. It feels like leading-edge pricing is still in the low 400s. But just based on the current backdrop and the amount of tendering and activity you expect to see over the next year or 2. Do you think by some time in 2027, we could be back up into the mid- to high 400s, which is where leading hedge pricing was at about a year or 2 ago. Is the market chromisetting up for that based on what you see today?

I guess what I would say is we definitely see the market tightening. And that's because of that convergence I mentioned, but also because of this, a lot of the demand that we see behind even the 95%, the demand that's creating that 95% number. And obviously, time Mike leads to higher day rates. So we'll see what happens, but we're pretty optimistic about a really tight market.

Got it. Got it. Great to hear. My follow-up is just on the Petrobras blend and extend. It seems like they handed out a lot of extensions. Were you all surprised by just the number of rig years they extended? Or was this kind of all part of their plan and in line with your expectations?

So I think it's in line with our expectations. We had always kind of thought Petrobras on total rig count would be flat, and they're going to end up dropping by a couple of rigs, at least in the near term. We're still hopeful that through time, their number remains flat and there's some possibility, I guess, that it could actually go up. But look, I think this is -- Petrobras are very savvy, and I think this is in line with their behavior through time, and they've secured their rig supply and probably done it at a pretty good time.

Your next question comes from the line of Keith Bachman of Pickering Energy Partners.

I just kind of wanted -- we've kind of talked about some of the really strong contracting that we've seen to start the year here. A lot of it driven by Petrobras in Brazil. Are there any other regions in particular that maybe you have stronger confidence in now for more significant tender conversion throughout the rest of the year? Maybe on the back of energy security, but just any regions in particular you wanted to highlight that could potentially be stronger contract version through the rest of the year?

Sure. Yes. I mean, here's what I would say. I mentioned the U.S. earlier, which I think is a region that sometimes responds quickly. So we don't have anything necessarily tangible to report there, but fingers crossed. But I think the real -- probably the meat of your question would sit in 2 places. First would be Asia where we think that we had growing demand even before the Iran conflict. And we think that, that's very likely to solidify going forward because of the renewed security concerns, which is obviously a good outcome if that happens for the Viking and follow-on work also in Australia.

And then secondly, I would say that a lot of the growth that we've been forecasting has been from West Africa and higher oil prices just helped that region. There's just no way that hurts all of that. So I think, if anything, if not incremental in West Africa, then projects on the table, we're hopeful that projects on the table are just even more likely to come through in time.

Awesome. That's really helpful. And then my second question was just trying to get the outlook for a few rigs. So I think about kind of the Black Rhino, the Globetrotter I and Apex system rigs that could still sell up some work they roll off or already off contract. Maybe what you -- do you think the BlackRhino could still potentially find work in the Gulf for do you think it may have to head elsewhere? And then just any potential work goes to the Globe chatter Warner Apex at this time, so you could help me out on that.

Sure. Yes. So Black Brado could very easily stay in the U.S. that's most likely to be 27 work. But like I said, our fingers are crossed about potentially some 26 work popping up. It is bid outside of the region as well. So we'll -- just a little too soon to tell where that rig will end up -- the GT 1 is in the same place it's been where we're chasing primarily intervention work. We believe in that market and everything that's happened it kind of makes us believe at least as much, if not more, in that market. So we're hopeful to have some sort of news on that rig. And I don't know, in the next couple of quarters. But it's -- it remains focused on intervention work.

And then there's a couple of jobs out there like the 1 in the Black Sea that really kind of worked very well for that rig. We're not bidding it into very many drilling programs. But there's a couple of things out there that we're chasing right now. So we're hopeful to have something for that rig, which would be like '27 start.

And then the Apex is an older unit and we're just evaluating options on that rig right now. There are some opportunities for the rig, and we'll make a decision on what to do with that rig here over the next couple of quarters as well.

Your next question comes from the line of Frederick of Clarksons Securities.

Over to the team. I hope you are well. Thank you for the prepared remarks and the market commentary in particular. I wanted to circle back briefly on Brazil and Renacom. You got the extension on the courage, which was nice to see, keeping that rig working until end 2030. But I was wondering about the pay as well. That's rolling off, I think, later this year or early next year, but nothing announced on this one. Does that mean that it's hasn't been part of Renecom? Can we expect that to be extended nonetheless? Or did you feel like the terms that were potentially agreeable for Petrobras went agreeable for you and that you might see that work -- sorry, that rig working elsewhere.

Yes. So the Faces Act is not a part of the planet extends that have now been announced. We did have it very close on a different program. And so what I would say is there are opportunities in South America for the rig that we're chasing but that we're also starting to bid that rig elsewhere. It's obviously not impossible for that rig to continue working for Pension bras but it's not part of the current blend and extend discussions.

That's very clear. And then 1 for Richard as well. in addition to buying or buying out 2 of your BOPs with 2 more following later this year. You also bought back some of your 2030 secured bonds? And I think you said that you bought back $55 million, which based on cash flow, at least would suggest a price of 103, at least if it's 55 bank, which would be good compared to market pricing. But I was also wondering if we should kind of read more into this given the call structures of the bond that this is early stages of a potential refi since you're still siloed in a way with legacy Noble legacy Nibor, legacy Noble legacy Diamond debt structures at the moment and everything is paying pretty high versus historical spreads at is. So any commentary around that would be super-helpful.

Sure, yes. So there was a specific clause in the legacy Diamond notes that allowed us to buy back 10% of 103. The bond was trading at 105, 106. So we think it was a very valued move for our shareholders, if you will, to provide in that debt. The legacy Novo bonds accordable now, the legacy Diamond bond is callable later this year. And at the right time, we'll definitely refinance the capital structure and class step back it all collapsed down into 1 silo. And through that process, we would expect to realize material cash interest savings on an annual basis. So obviously, both bonds are trading well in excess at par today but we're going to find the right time to go further for us.

Your next question comes from the line of Doug Becker of capital.

Robert, just as the market evolves, do you see an opportunity for some upgrades on the drillships to even improve their competitiveness even further?

That's a good question. I think we highlighted in last call, but as a reminder, we feel we've got 1 of the most competitive fleets on the globe right now. All of the rigs will have MPD here in the not-too-distant future. And we -- I think we have more of NOVs, automation equipment installed in our rigs than the entire rest of the world combined. So we're really proud of where we sit on rig technology. We have upgraded or will upgrade a couple of the rigs for dark capacity, which is a pretty easy upgrade for a couple of our rig classes. I could see us doing something like that for certain programs. By and large, we're pretty happy with where everything sits right now, though.

And I guess I'd add 1 caveat we are constantly in communication with our customers around technology that they value and of course, work with them as a normal course of business to find technology that works for our rigs. And there's always some discussion around who pays that stuff. But I think right now, what we're seeing is a real push by customers to have the best technologies as a lot of things are really starting to prove their value, whether it's in the form of safety, perhaps resident management or on -- of course, on efficiency, which would be more like NPD and automation and other things. So we think that the trend will continue. Some of that's going to come from customer supply CapEx. Some of that's possible from us. But I think we're starting from a pretty high place right now as a company.

No, I would agree. Richard, a quick one. You mentioned the low end of the range was kind of derisked through contracting. What would we need to see happen to get to the high end of the range for this year?

Yes. I think there's a few parts, if you will, to get to the high end, obviously, in Q1, we had great uptime performance and fantastic cost control throughout the entire company. I think, obviously, opportunities, there's opportunities there, if you will, to drive cash flow that way. I think specific maybe to the black line and obviously, if opportunities come to the ton for that rig in the back half of the year, then that would lead, I think, to us being towards the high end of the range.

Your next question comes from the line of Ben Same BTIG.

So first, I kind of want to ask a bit more about your comments earlier that the U.S. Gulf is a basin that typically reacts quickly to changes in oil prices. Just kind of curious if you've heard anything yet from customers in the region, and I guess thinking more about your fleet, maybe how that could have some implications for really like the Black run.

Good question. I wish I had a great story for you. I can't say our customers continue to reach discipline, and we'll continue to be disciplined but I think the U.S. is a place where that some of the smaller independents can be a little bit more price sensitive in the near term, perhaps than some of the majors are. And I would say, but also kind of related to Richard's save in just a moment ago. To the extent that something pops up for the Black rinothat's some upside in 2026 for us. And so we're hopeful that this environment eventually translates to a little bit of incremental work.

Great. And then I just wanted to turn to the jack-up fleet quickly. Now with the closing of the sale behind us. Kind of just curious on anything you want to highlight on the longer-term outlook in Norway and the U.K. And I know that a lot of '26 has spoken for these rigs, but I guess thinking about '27 and beyond?

It's a good question. I think for the CJ70s in 2027, we're '27-- we've got I think we feel really good about having 4 of those rigs contracted and with multiple paths to having all 5 of those rigs contracted. And so we're happy with that. We're probably a little bit short of scarcity in that market on programs that genuinely require CJ70s, -- but I think I would kind of broadly characterize our view as flat to up for CJ70s, and so we're -- it been a little while since we would say that with that conviction. So cautiously optimistic there.

Your next question comes from the line of Josh James of Daniel Energy Partners.

Over the next 12 months and the focus on execution. Could you speak to what you're...

Two seconds yes. Let me interrupt you. You just came in. We didn't hear the first part of your question.

Can you hear me now? Yes. So just want to touch on inflation and supply chains. So you highlighted a number of projects and rig start-ups you'll have over the next 12 months and the focus on execution. Could you speak to what you're seeing with respect to global supply chains, maybe not just only the straight, but also outside of the straight and how you're managing things to make sure the projects start on time with no delays.

Yes, thanks. It's a good question. It's something we're extremely focused on here, as we mentioned. So I would say logistics are strained. And some of that started before we end. But obviously, fuel prices are way up now. And so that's adding a little bit of cost into the system. Right now, I would say, cost-wise, we're not seeing material effects as directly correlated to the war. Transportation costs up, yes, -- but I think everything else -- all the stuff we're buying for these projects has been built effectively. And so we feel reasonable, although there's probably -- there's risk there, obviously, given everything happening.

We're really focused on timing right now. And that's where we're seeing a lot of pressure, and we're going multiple layers deep here track the equipment we need and then just try to ensure that we get everything on time so that we're ready to go for our customers. So again, we're I guess I'd say we're optimistic and working hard to make sure that we stay on time here. There is a lot of pressure out there on the groups trying to pull everything together.

Understood. And then maybe just 1 follow-up, just to address the latest developments in autonomy. So there was a release in March where Noble in conjunction with Halliburton and Exxon automated rig operations and subsurface interpretation, real-time hydraulics maybe you could just speak to that and where you think we're going over the next couple of years with respect to advances in autonomy on the rig floor.

Yes, that's going to continue. That's the path of everything. We just -- we don't Noble doesn't do anything specifically subsurface. We are focused on making sure that we have the most efficient rigs and then some of the logistics around that. But we work very closely with other service companies and with our customers, of course. And I think 1 of the things that the mark of kind of where things are headed, is that everyone that's much more collaborative today so that I think maximum efficiency is achieved by service companies and operators really working together early collaborating on shared technologies like what you just referenced and there are a number of examples like that out there.

But that is the path of drilling today. And I think we've said before that kind of wax poetic about the change from the concept of drilling ourselves out of a job, and into the mindset of drilling yourselves into a job. We mentioned previously that we've seen that work directly in Guyana. where they've had FID under a set of circumstances that probably were not possible even 3 or 4 years ago, given efficiency then. So we think that technology and automation is really an enabler for deepwater work going forward. And the further Deepwater comes down the cost curve, the more there is for the entire industry. So we're really optimistic about all of that.

Your next question comes from the line of James West of Melius Research.

Robert and Richard. Robert, curious, as we think about the various regions around the world that you guys participate in, which 1 would you say, over the last 1 or 2 or 3 over the last kind of 90 days have started to show a bit more urgency on moving FIDs maybe forward or just getting FIDs done for projects as this deepwater cycle steps up?

I'll give an answer and look at like, make sure I get it right. But I think Asia, for sure, we've seen a real change in the amount of demand and urgency there. And then I would say, Pericom, where there's an enormous amount of work that obviously, a lot of it we knew in Guyana, but then suddenly, Venezuela seems more open and a number of other actually kind of shallower water trends that are creating a lot of demand through that region is all pretty interesting.

Okay. Okay. Got it. And then on the managed pressure drilling, I think you mentioned all of your rigs are now or will be outfitted with MPD. What percentage of the wells now are being drilled with in PD? And how much of the actual well is drilled with BD?

Yes. So just to clarify, the drillships will have the drillships that have been visual I may have to -- I don't know if I have a percentage on it's a high percentage. And so there are certain technologies out there that can be used outside of MPD. But the feeling for us has been that over the past, really, 10 years that MPD is kind of going the path of the top drive, where it's almost ubiquitous. And so we're pretty happy with where we are on having the rigs outfit it. It's $25 million to $30 million expense depending on where your piping is and then -- and that's before you get out of service time. So we're pretty happy to have all that pretty much paid for.

Your next question comes from the line of Noel Parks of July Brodersen.

We've touched on sort of the edges of this, but I've been thinking, of course, that 1 of the artifacts of things tightening up again in the rig market could be that we have begun to see some lengthening of contract term length. And it seems like I don't really necessarily seen that yet, but I do like I have noticed some more prompt contract extensions, maybe suggesting that any operators who might have been betting on lower for longer day rates may realize you're losing that bet. So I'm just wondering if you were we seeing that yourselves.

Yes. Sorry, when you said term, do you mean like contractual terms or the length of the contracts?

Length of the contract.

Yes, yes. So if you recall, 2 or 3 years ago, the last time we kind of hit this inflection, I think average contract term was still less than a year -- and so we're -- I think that's 1 important point we kind of made in the comments is, yes, if you have -- I don't think there's a ton of priced options out there. If someone has a price option, I think they're pretty likely to take it right now. But across the board, I think we're seeing more and more big development projects that are driving this demand. And like we mentioned earlier, I think the average contract term was at least 2 years on some of this recent contracting that's a huge change compared to where we were before. So you think about hitting kind of similar utilization point as when the last time day rates hit right at 500 were similar -- approaching a similar utilization point, but with more term and a lot more open demand than before, like double of in demand. So we're pretty optimistic.

Great. And I'm just wondering, you did mention briefly that the factors of disciplined capital discipline are still very much in place with producers. And I was just wondering if this time around, I'm sort of thinking with the geopolitical term labs, you're thinking back to 2022 that we had -- we still had sort of more uncertain macro environment. The rate environment was about to take off and had a lot higher. So I was just wondering if this as far as you see them trying to decision make during the uncertainty, is this very reminiscent of sort of our last big international flare up or do they sort of are just looking past it and just thinking about whatever comes next.

Yes. I mean, our customers are very long-term minded obviously, and I think that they are -- there has been this big movement towards exploration in the deepwater, which to me is the most important test of the market. That started before ran that hasn't slowed down. We hope that it is only solidified by what's happening right now. And so I guess one -- another way to put it would be we certainly wouldn't expect our customers to waiver from their commitment to discipline and our optimism does not require them to abandon any discipline.

Your next question comes from the line of Erin Rosenthal of JPMorgan.

Can you just elaborate on the moving pieces with the Mick O'Brien. I think you called out $15 million impact maybe how much is the fair piece of that versus I believe you mentioned a stacking cost? And then the termination or I guess when the rig does go stacked, does that effectively end the relationship between the entities and that rig is free to see work out osewhere? Or are there any other lingering items we should be aware of?

Yes. So obviously, it's an early termination for the rig. So the $15 million, if you think about that as about the 6 months of the BerboCharterplus stacking costs. So that's essentially the $15 million. So that's the extent of the impact. We don't see any other impact to our financials. And obviously, once we get to early December, that will move over to Bo.

As you break now, we don't have any pending questions. I'd now like to hand the call back to Noble Corp management for closing remarks.

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

Thank you for attending today's call. You may now disconnect. Goodbye.

Thank you for standing by. My name is Carrie, and I'll be your conference operator today. At this time, I would like to welcome everyone to the Noble Corporation Fourth Quarter 2025 Earnings Conference Call. [Operator Instructions]

I would now like to turn the call over to Mr. Ian MacPherson. You may begin.

Thank you, operator, and welcome, everyone, to Noble Corporation's Fourth Quarter 2025 Earnings Conference Call. You can find a copy of our earnings report, along with the supporting statements and schedules on our website at noblecorp.com. We will reference an earnings presentation that's posted in 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. We also have with us Blake Denton, Senior Vice President of Marketing and Contracts; and Joey Kawaja, Senior Vice President of Operations.

During the course of this call, we may make certain forward-looking statements regarding various matters related to our business and companies that are not historical facts. Such statements are based upon current expectations and assumptions of management and are therefore subject to certain risks and uncertainties. Many factors could cause actual results to differ materially from these forward-looking statements, and Noble does not assume any obligation to update these statements.

Also note, we are referencing non-GAAP financial measures in 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. Welcome, everyone, and thank you for joining us. Today, I'll walk through our financial and operational highlights, recent commercial wins, market outlook, including our semiannual review of deepwater rig demand around the world and a brief update on our fleet strategy. Richard will then provide a financial overview, and I'll wrap up with closing remarks before we go to Q&A.

Starting with Q4, we reported adjusted EBITDA of $232 million and free cash flow of $35 million, bringing adjusted EBITDA for the full year 2025 slightly above the $1.1 billion midpoint of our original guidance. We have maintained our return of capital program, returning an additional $80 million 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've continued to see strong booking levels across our fleet with backlog increasing to $7.5 billion. First, the Noble GreatWhite has been awarded a 3-year contract with Aker BP in Norway, valued at $473 million, including mobilization, but excluding additional fees for integrated services and bonus potential. This marks the GreatWhite'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 million 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 million over the 3-year contract period, essentially targeting a recovery of the capital in the first 2 years of the program and positioning the GreatWhite 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 Gerry de Souza was awarded a 2-year contract with Exxon in Nigeria. This contract valued at $292 million is scheduled to start around the middle of this year and is followed by 3 1-year options. We are looking forward to redeploying the de Souza in Nigeria following the rig's previous campaign there from 2023 to 2025. In the U.S. Gulf, the Noble BlackRhino has recently been awarded 1 well plus 1 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 3-well contract with BP in Trinidad that's scheduled to commence in early 2027 at a day rate of $375,000 with estimated duration of 240 days, plus 3 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 and 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 5 rig years. Additionally, the Deliverer looks well positioned for a good amount of work that's 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 Noble Endeavor has been awarded an 11-well contract with an undisclosed operator that's 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 5 to 6 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 rigs through this year and beyond.

Now on to the market outlook. Despite the ongoing abundance of macro uncertainties and Brent prices hovering around 5-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 day rates we've seen recently.

These divergent utilization statistics tell us a couple of things. First, the industry fleet has added backlog depth but hasn't 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, 6 of the 14 rigs that sit idle today with future contracts in hand are Noble rigs, the Noble BlackRhino, Voyager, Valiant, GreatWhite, Gerry de Souza and Endeavor. We believe this is a strong indicator of improving utilization on the come 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, day rates for Tier 1 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 upticks 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 and is planned to commence its 3-year campaign with Total and Suriname. We remain in constructive dialogue with Petrobras regarding contract extensions for either or both of our 2 Brazil rigs, the Noble Faye Kozack 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 next year relative to today's record high contracted UDW rig count of 44. U.S. Gulf has softened recently with the Noble BlackRhinos' recent contract award bringing the contracted UDW rig count back up to 21, which is 1 to 2 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 to West Africa, where contracted UDW demand has recently rebounded to 15 rigs with the Noble Gerry de 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 5 active or pending long-term tenders throughout Angola, Nigeria, Côte d'Ivoire, Ghana and Namibia, plus the potential for multiple additional 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 7 to 9 last year. And this could expand to 12 rigs by the second half of this year with the commencement of 2 programs in the Med offsetting the conclusion of the Noble Globetrotter I's contract in the Black Sea. Visibility beyond this year isn't 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 the 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 4 rigs to 8 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 of 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, 7 of which are satisfied by UDW semis, which is up by 1 to 2 units compared to a year ago. We are very excited to kick off preparations for the Noble GreatWhite 3-year program with Aker BP starting next year and the redeployment of both the GreatWhite 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, but there's 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, we 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 $60s 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 day rates. The great news for Noble is that our backlog progresses have 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 capital 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'd like to provide a brief update on our fleet strategy. Last month, we completed the sale of 5 jackups to Borr Drilling for $360 million. Additionally, the $64 million sale of a sixth 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 GreatWhite 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 GreatWhite next year.

With that, I'll pause here and pass the call to Richard.

Thank you, Robert, and good morning or good afternoon, all. In my prepared remarks today, I will briefly review the highlights of our fourth quarter and full year 2025 results and then discuss our outlook for 2026.

Starting with our quarterly results. Contract Drilling Services revenue for the fourth quarter totaled $705 million. Adjusted EBITDA was $232 million and adjusted EBITDA margin was 30%. Q4 cash flow from operations was $187 million. Capital expenditures were $152 million and free cash flow was $35 million. Last quarter, we terminated the BOP service agreement on the 4 Black ships, which increased fourth quarter CapEx by $18 million. For the full year 2025, we generated $3.3 billion in revenue and $1.1 billion in adjusted EBITDA. CapEx net of proceeds from insurance claims of $497 million included approximately $25 million of rebillable CapEx and the aforementioned CapEx for the termination of the BOP service agreement. This all resulted in $454 million in free cash flow for the year.

As summarized on Page 5 of the earnings presentation slides, our total backlog as of February 11 stands at $7.5 billion. As a reminder, our backlog excludes reimbursable revenue as well as revenue from ancillary services. Our current backlog includes approximately $2.3 billion that is scheduled for revenue conversion during the remainder of 2026 as well as a slightly greater amount that's already booked for 2027. This is the first instance in many years in which our year 2 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'll circle back to this point in just a moment.

Referring to Page 9 of the earnings presentation, we are providing full year 2026 guidance for total revenue between $2.8 billion and $3 billion, which includes approximately $150 million in reimbursable and other revenue and adjusted EBITDA between $940 million to $1.02 billion. 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 million and $640 million. This range includes approximately half of the $160 million GreatWhite project CapEx, with the remaining half included in the 2027 CapEx, approximately $25 million of customer reimbursable CapEx and approximately $50 million of additional project-related CapEx associated with the $1.3 billion 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 GreatWhite, Endeavor and Gerry de 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 higher 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 million to $400 million, excluding the remaining GreatWhite 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 million associated with the possible buyout of the BOP leases on the 4 Black ships. This possible buyout is not included in our capital expenditure guidance.

Next, we expect a favorable working capital reduction of around $100 million this year, partly driven by CapEx reimbursables. Additionally, when modeling cash balances, recall that the sale of 5 jack-ups to Borr Drilling brought in $210 million in cash proceeds last month plus $150 million seller note. We also expect to close the additional $64 million cash sale of the Noble Resolve to Ocean Oilfield in the third quarter. As it relates to the Noble Resolve, we received approximately 1/3 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 for a healthy inflection in both EBITDA and free cash flow next year. By way of illustration, assuming 13 of our 15 Tier 1 drillships working at current market rates, contribution from all 3 D rigs and the remainder of our fleet essentially contracted at current status quo, we can envision an annualized run rate of around $1.3 billion in EBITDA with corresponding free cash flow of approximately $600 million in the second half of 2027.

With that, I'll pass the call back to Robert for closing remarks.

Thanks, Richard. To sum up, I'm incredibly excited about this moment for Noble. All of the strategy and effort that our organization has invested over the past 5 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 CML systems. 2/3 will be equipped with NOV's leading-edge automation technology, including advanced robotics on several rigs and 2 will feature 2-million-pound derricks. Additionally, the GreatWhite's modifications will place it as a Tier 1 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 in 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 2 backlog in the books than current year backlog, serves to provide a direct line of sight to run rating approximately $1.3 billion of annualized EBITDA by the second half of 2027, even without any improvement in day rates. 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 with 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 pre-tenders 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 million to $500 million of run rate free cash flow by the second half of 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 million of run rate free cash flow by the second half of next year at current market rates with significant leverage to day rate 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 day rates from here. As we've 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'll turn it back over to the operator for questions.

[Operator Instructions] Your first question will come from Arun Jayaram with JPMorgan Securities LLC.

Robert, I was wondering if you could give us your thoughts on industry consolidation. Obviously, seen a large merger announced earlier this week. And just your overall thoughts on the implications to Noble and your overall strategy.

Yes. I mean, look, consolidation has been the path for this industry post-COVID. Obviously, we participated in that. And then this week, there's been a really significant announcement. I think with the outlook for our industry, I think consolidation is the obvious path throughout the energy complex, throughout the entire chain. It's obviously been no different for the drillers. And I'd say we certainly have benefited from it through the past years. We're a better company today than when we started this journey. And I'm hopeful that broadly consolidation makes the entire industry better and more capable and more efficient because that's the path forward for the drillers.

Got it. I have my follow-up, Robert. Obviously, you've been a participant, as you mentioned, in industry consolidation, including the Diamond Offshore transaction, Maersk. You obviously have a very capable offshore rig fleet, 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? Obviously, you've been divesting some of your shallow water jackups.

Yes. 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 -- I repeat myself, but we're a better company today than we were before because of the scale we've 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 kind of the right place for us as a company in terms of the type of asset and the quality of the asset.

Your next question will come from Scott Gruber with Citigroup.

I want to inquire about the recent strength in the sixth-generation market. I think your recent contracts surprised the market. I guess, first, what's driving that? Is that just a collection of kind of projects moving forward? Is it a bit of kind 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.

Yes, it's a good question and not necessarily something we would have predicted a couple of years ago for sure. What I would say, I think -- so 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're set up particularly well for certain types of operations. And so what I would say is for that class of 3 rigs, it is a project-specific right place, right time kind of phenomenon. I think it's sustainable. I don't mean to suggest that this is a window in time. But I think the fact that they've kind of contracted prior to the seventh gens is a phenomenon being at the right place and the right time for the right projects. It's not a value decision by our customers, as you mentioned, which is a good thought. But I do not believe that's what's driving it at all.

Got it. And then we've kind of long thought that the sixth gens, we need to see better utilization to get another round of upward momentum in rates across the collective seventh and sixth gen marketplace. It seems like the direction of travel there is positive. And you mentioned line of sight to potentially getting back to 105 UDWs. What does it take to get some upward momentum in rates? Just do you think you have to kind of eclipse that level if crude prices do stay subdued or just kind of getting back there? Do you think you've inject enough tightness back into the market? Or do we need to see crude prices improve to kind of see some additional spending capacity by customers? Just some thoughts on the conditions that could drive some day rate improvement here.

Yes. It's really a question I wish I had the answer. I think it's a mixture of both. I think what we're -- this phenomena where we're seeing higher backlog kind of in year 2 than year 1 right now, I think, is somewhat crude agnostic, and I think is perhaps driven more by the realization that a volume of barrels is going to have to be produced from deepwater, and those are all obviously long cycle, et cetera. And so I think that is more driven by this return to deepwater that we've seen play out over the last couple of years. However, the incremental rigs that probably define the tightness in supply and demand, our crude price does matter for near-term projects. And that's 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 the prepared remarks. But we need another, say, 5 rigs -- rig contracts that we don't see anywhere out there today to come through to really get to an extremely tight market, call it. I'm pretty confident that all of the -- that everything is set up to supply that. I don't think there's any reason that, that couldn't happen by 2027, let me put it that way. But we're a little cautious to say we're kind of going to have to see how '26 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 Noble, just across the board over the next few months. And I think that, obviously, that should all be well received. We're including all of that in our analysis. And we're pretty hopeful that here going into 2027, we've got the various pieces for a tightening market.

Your next question will come from Eddie Kim with Barclays.

I'll ask sort of the pricing question in a little bit of a different way. And I appreciate all the detailed commentary on the outlook. You said recent day rate fixtures for Tier 1 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-400s range? Or does that maybe look like more of a 2028 event just based on conversations you're having and the opportunities you're 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's a 50-50. I don't know. It's 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. I would say a couple of things about us specifically. One, the things Richard laid out in his script are all completely out with day rate improvement.

So we feel with our unique backlog curve where we've done a lot of the 2027 work already, we feel that we're extremely well positioned for an inflection here without day rate improvement. And then two, I would say, also, I really like the way the fleet is -- fleet contracting is staggered right now. So we've got a nice mix of short-term availability, long-term contracting. And then, of course, our CEA reprices up and down. And so I think I'm pretty pleased right now with the way the Noble fleet sits looking forward and everything.

Got it. Got it. My follow-up is just on negotiations with Petrobras. We haven't really heard any news about blend and extend either from you or anyone else. I would have thought that we might have seen something on the Faye Kozack in your fleet update several weeks ago. You mentioned negotiations are still ongoing. When do you expect these will conclude? And separately, I mean, Petrobras has a tender out for Búzios and Tupi and Mero field. Is it fair to say they're unlikely to award these contracts until those blend and extend negotiations have concluded? Just any thoughts there would be great.

Yes. It's a good question, something we're tracking closely along with everyone else. We're 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 with their -- they've got more deepwater 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's a heavy lift. And so you could easily see how that could get pushed out a little bit past the next couple of months.

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, plans change. And so we're generally positive, optimistic about Brazil being kind of worse, flat, which is in a really good place right now and hopefully up by a couple of rigs over the next couple of years.

Your next question will come from Fredrik Stene with Clarksons Securities.

Thank you for the prepared and detailed remarks on the rig market in particular. I wanted to ask a bit more about the Norwegian market because a couple of moves here that you've done recently, one, obviously signing the GreatWhite with Aker BP and focusing your jackup fleet solely on the 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've seen in many years. Are you able to elaborate a bit on that and maybe specifically on the jackup side since the GreatWhite after all has been contracted for 3 years? Why -- what makes you optimistic? And what should we -- how should we think about the jack-up fleet in '27, '28, where there is some space that definitely needs to be filled?

Yes, it's a good question. I don't want to imply more than too much optimism. Look, we've got contracts for the CJ70s. A number of those are in the U.K. sector, which is great. I'm not sure that we see a renaissance in shallow water in Norway right now. So I don't 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 and the multiple customers. But I think with the rigs kind of in a steady state utilization right now and some ongoing conversations, it just feels like it's 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 we think we have the most capable rigs in the world ready to go if we do get an incremental unit or 2 of demand in Norway.

That's very helpful. One quick one more. Turning to the floater fleet. You have the Globetrotter I soon will go off contract. You have the Apex that's idle. Deliverer, you seem very optimistic about potentially having a good chunk of work from '27 and beyond. But do you have any commentary on how you view the Ocean Apex and the Globetrotter in your fleet as we look forward?

Yes. So on the Globetrotter, we've said before that we're effectively bidding those into intervention or niche drilling applications. So obviously, the Black Sea qualifies for that since those rigs can go under the bridge pretty quickly and efficiently. I think the intervention market remains out there. And we're -- I'd say we're kind of chasing a mixture of intervention and potentially some niche programs for the Globetrotter. Apex is probably -- we'll see what happens with that rig. So there's, I guess, less on the horizon for that rig. We're going to keep looking hard at that one.

Your next question will come from [ Ben Sommers ] with BTIG.

So first on the BlackRhino and kind of just the U.S. Gulf market in general. Just kind of curious, it was great 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.

Yes. It's a good question. That's -- we're spending our -- myself and our marketing group spending a lot of time on that rig. We have multiple opportunities. So I would say for 2026, we're hopeful that there's some spot work out there, but there's 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've got a couple of different opportunities with some of our closest customers globally, and we're hopeful that we can land something there. That rig is an excellent rig. It's outfitted very well for big development campaigns and obviously can perform with the best of them for shorter-term exploration jobs as well. So we're hopeful to land something here before too long.

Awesome. And then 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? Or are we pretty confident here that, that's 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, I don't wake up concerned about things getting pushed to the right. So it's obviously always a risk in our business. When you've got Brent in the $60s, it's always going to be a risk in the business. Partly why we're not exactly calling for or predicting with certainty what happens in 2027. But I will say, with all of the backlog that's 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've seen in quite some time.

We threw out the statistic about the kind of open demand that's out there. There's obviously direct negotiations that are in excess of those numbers. And we look at where we sit today in the year and the rollovers, it's kind of -- there's no story -- 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's 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.

Your final question will come from Keith Beckmann with Pickering Energy Partners.

I had a question kind of relating around the CapEx on the 9 contracts outside of the GreatWhite. So I think it's about $50 million of CapEx, and I believe you guys said it was related to the Endeavor and the de Souza. Can you sort of bucket between those 2 rigs roughly what that is for me?

Yes. So I think you're talking about the incremental $50 million of contract capital that we announced in conjunction with the $1.3 billion of backlog here about 2 weeks or so ago. I think about that incremental capital is kind of split between the Endeavor and the de Souza.

Awesome. And then my other question was just relating around -- I think this was said on maybe a little bit earlier, but just relating around the remaining 5 jack-ups. 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.

Yes. Look, it's a good question. No, we're committed to the CJ70s. When we announced the merger with Maersk, we chose to put our secondary headquarters in Stavanger. We have an established extremely capable operation there. And with the addition of Ocean GreatWhite, some added scale. So we're pretty happy with where we sit there right now.

And that concludes the Q&A portion of today's call. I would now like to turn the call back over to Mr. Ian MacPherson for any closing remarks.

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.

Thank you for your participation. This does conclude today's conference. You may now disconnect.

Thank you for standing by. My name is Carly, and I will be your conference operator today. At this time, I would like to welcome everyone to the Noble Corporation Third Quarter 2025 Earnings Call.

[Operator Instructions]

I would now like to turn the call over to Ian MacPherson, Vice President, Investor Relations. Please go ahead.

Thank you, operator, and welcome, everyone, to Noble Corporation's Third Quarter 2025 Earnings Conference Call. You can find a copy of our earnings report, along with the supporting statements and schedules on our website at noblecorp.com. We will reference an earnings presentation that's posted on the Investor Relations page of our website. Today's call will feature prepared remarks from our President and CEO, Robert Eifler; as well as CFO, Richard Barker. We also have with us Blake Denton, Senior Vice President of [indiscernible] [ Angeli Calaza ], 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 therefore, are subject to certain risks and uncertainties. Many factors could cause actual results to differ materially from these forward-looking statements, and Noble does not assume any obligation to update these statements. Also note, we are referencing non-GAAP financial measures on the call today. You can find the required supplemental disclosure for these measures, including the most directly comparable GAAP measure and an associated reconciliation in our earnings report issued yesterday and filed with the SEC.

Now I'll turn the call over to Robert Eifler, President and CEO of Noble.

Thanks, Ian. Welcome, everyone, and thank you for joining us on the call today. I'll open with a brief summary of our Q3 highlights and recent contract awards, then provide some perspective on the market outlook. Richard will provide more detail on the financials before I wrap up with closing remarks and move on to Q&A.

During the third quarter, we earned adjusted EBITDA of $254 million, generated free cash flow of $139 million and received an additional $87 million in net disposal proceeds. We again distributed $80 million to shareholders through our $0.50 quarterly dividend. And yesterday, our Board declared a $0.50 per share dividend for the fourth quarter, bringing total 2025 capital return to $340 million. The highly competitive cash yield on our stock continues to be a critical component of our story as we traverse this mid-cycle [ low ] for our industry.

Before we discuss the market, I'd like to commend and thank our crews and operating teams for achieving excellent operational uptime and HSE performance, aided by tools like our [ norms, Horizon 56 and ] operations performance platforms. Our teams have continued to push the envelope in technically challenging well construction and completion activities. In Guyana, our drillships continue to post record-setting results within the [ Wells Alliance ]. We have now constructed over 200 wells in the basin, delivering 60% of the most recent 25 wells in under 35 days. In the U.S. Gulf, the Noble BlackHornet set a new benchmark in deepwater drilling operations, earning high praise from the customer for outstanding execution of MPD influx management on a complex exploration well. Nearby, the Noble BlackLion recently performed the longest step out yet for BP in the Gulf at over 12,500 feet, which was also delivered well ahead of AFE. Results like these continue to be a defining success story for the deepwater industry and are leading the way in bringing deepwater sharply down the cost curve and thereby structurally increasing the size of the [ prize ].

We've also had another solid quarter on the commercial front with backlog increasing to $7 billion currently on the back of several key contract awards. First, the Noble BlackLion and Noble BlackHornet have both been extended by an additional 2 years by BP in the U.S. Gulf, extending the rigs into September 2028 in February 2029, respectively. These extensions are valued at $310 million per rig, excluding MPD services and both come with an additional 1-year priced option. These contract extensions further amplify the merits of the Diamond acquisition, which has materially over delivered on our original accretion expectations as the legacy Diamond Rig continue to perform and recontract at very high levels. We are thrilled to continue the BlackLion and BlackHornet's long-term assignments, which will now be approaching 1 decade in tenure. These long-duration engagements demonstrate the power of the deeply collaborative service posture that we have been working hard to cultivate over the past several years in order to drive value for our customers and earn their repeat work to [indiscernible] performance.

Next, the jackup Noble Resolute has been awarded a 1-year contract with Eni in the Dutch North Sea at a day rate of $125,000. This contract is expected to commence later this quarter. And the Noble Interceptor has booked a 5-month accommodation contract with Aker BP in Norway, which is scheduled to start next August. Lastly, the [indiscernible] Noble Developer has had an option exercised by Petronas for an additional well early next year. In the drillship Noble Venture was awarded a 1-well contract from Amni and Ghana at a day rate of $450,000. This well is scheduled to follow in direct continuation of ongoing [indiscernible] [ working ] Ghana, which is expected to resume in its second phase within the next several days before the rig mobilizes to the U.S. Gulf for long-term work commencing in late 2027.

Beyond these specific contract awards, the broader contracting and utilization trends in deepwater are showing gradual signs of stabilization and improvement. The committed UDW rig count of approximately 100 rigs and low 90% marketed utilization is, in fact, up slightly compared to recent quarters despite some lingering near-term availability across several units with longer-dated contract starts. Additionally, deepwater contracting momentum is on an uptrend with an average of 18 UDW rig years per quarter fixed in Q2, in Q3 this year, up 10% compared to the preceding 2 years. These are encouraging indicators and there remains a significant number of additional fixtures anticipated over the next few months.

Noble's backlog picture as summarized on Page 5 of the earnings presentation slides, shows 57% contract coverage across our entire fleet in 2026. When zooming into our 15 high-spec drillships, we are now 70% booked for available days in 2026, excluding options. However, we have active conversations behind all of our available rigs in 2026, including the [ Jerry DeSouza, Viking and Blaine. ] And while we are also tracking the number of contract opportunities across the balance of the fleet, both jackups and floaters. Securing additional work for these 3 drillships is a key priority, and our objective is to obtain 90% to 100% contract coverage across our 15 high-spec drillships by the second half of next year.

On the jackup side, activity in the harsh environment Northern Europe market has been stable at 28 rigs and marketed utilization at 90%, flat with last quarter with leading-edge day rates for drilling programs in the Southern North City holding flattish. Although the contracting environment has remained relatively subdued, we do have line of sight towards several opportunities so we hope to be able to -- relatively soon. With the Interceptor's pending reactivation, we now have improving contract coverage for all 5 of our ultra-harsh CJ70 jackups as we progress through next year. Our 6 harsh rigs presently have limited contract coverage in 2026, we do expect this picture to improve based on several bidding opportunities currently in process.

So overall, we are encouraged by the shape of things and the opportunity set at hand, which includes a broad range of UDW requirements throughout the Golden Triangle, Asia Pacific, Mozambique, Mediterranean and harsh environment basins. The pipeline for early 2026 jobs is still significantly more limited compared to late '26 and early '27. But at this point, we are not seeing indications of additional project or procurement deferrals. Assuming reasonably stable oil prices, the path toward a methodically tightening floater market with deeper backlog appears to be on track.

Now I'll pass it over to Richard to discuss the financials.

Good morning or good afternoon all. In my prepared remarks today, I will review our third quarter results and then discuss our outlook for the remainder of the year as well as some additional high-level perspectives on 2026. Starting with our quarterly results.

Contract Drilling Services revenue for the third quarter totaled $798 million. Adjusted EBITDA was $254 million, and adjusted EBITDA margin was 32%. As expected, Q3 revenue and adjusted EBITDA were sequentially lower, primarily due to a number of rigs rolling off contract during the third quarter. Free cash flow of $139 million in Q3 excluded an additional $87 million in disposal proceeds driven by the sale of the Pacific Meltem and Noble Highlander. Thus, we ended the quarter with a cash balance of $478 million, which is up $140 million compared to last quarter. Subsequently, in October, we have completed the sale of the Noble Reacher for [indiscernible] use outside the drilling market for $27.5 million. As a reminder, the Reacher has not worked in drilling mode for several years having recently completed a long-term and low-margin accommodation contract. The rig would have required a significant amount of capital to return to drilling mode again. And as such, the Reacher was an outlier within our group.

As summarized on Page 5 of the earnings presentation slides, our total backlog as of October 27 stands at $7 billion, which includes approximately $0.5 billion that is scheduled for revenue conversion for the remaining 2-plus months of this year and $2.4 billion and $1.9 billion scheduled for conversion in 2026 and 2027, respectively. As a reminder, these figures exclude reimbursable revenue and revenues from ancillary services.

Referring to Page 10 of the earnings slides, we are now in the range for our full year 2025 guidance for adjusted EBITDA to $1.1 billion to $1.125 billion. The midpoint of this range implies Q4 adjusted EBITDA that is marginally lower versus Q3. I would point out that the exact start date of the [indiscernible] contract in the Black Sea, which we currently estimate in mid-December is the key sensitivity for Q4 revenue due to the relatively compressed duration of the full contract value, including mobilization. We are now guiding for full year 2025 CapEx net of customer reimbursables to a range of $425 million to $450 million. Reimbursable CapEx is expected to be approximately $25 million this year, including approximately $20 million year-to-date through Q3.

We plan to provide 2026 guidance on next quarter's earnings call. In directional terms, I would say that the shape of our current -- status report would indicate an EBITDA trough in the first half of 2026 that would be somewhat below second half 2025 levels as well as lower results on a full year basis for 2026 versus 2025. Our [indiscernible] current and anticipated backlog, we are tracking toward a material inflection from late 2026 onwards, which we will look to define more sharply next quarter as the next [ slug ] of foundational contracts are expected to come into backlog. We continue to anticipate approximately $450 million in CapEx, net of customer reimbursables next year based on our current contract status. However, this estimate may be subject to an increase to the extent that additional contract supported opportunities arise with compelling accretion. The capital to react at the Noble Interceptor will be reimbursed through an upfront mobilization payment.

Additionally, we are likely to incur additional outlays totaling up to approximately $135 million associated with the termination of the BOP service and lease contracts on the legacy Diamond [ black ships ]. During the third quarter, we delivered a termination for convenience notice for the service agreements, and we are currently in discussions around the lease agreement. We expect an approximate $35 million of cash outlay during Q4 2025, which is expected to flow through OpEx and CapEx and then the remainder during 2026. These amounts are not included in the aforementioned guidance ranges. However, as a reminder, this cash outlay would be offset by annual savings of approximately $45 million across OpEx and lease payments on the agreements on a combined basis.

We are focused on building cash in the last quarter of this year in anticipation of next year's capital requirements, including the potential BOP-related payments. We are also committed to maintaining a robust return of capital program and a prudent balance sheet position. Based on existing backlog and current customer dialogue, we would expect to help the EBITDA and cash flow inflection late next year.

That concludes my remarks. And with that, I'll hand it back to Robert.

Thanks, Richard. To wrap up, we're continuing to see a number of positive signs of increased deepwater activity after the anticipated trough over the next few quarters. This is essentially very similar to how we assess the outlook last quarter albeit with additional backlog in our books today to help lay the path towards that outcome but also with a bit more slippage with certain program start dates, which continues to bifurcate the 2026 versus 2027 picture. We still have some work to do with securing a few more key contracts in order to support our expectation for a meaningful free cash flow inflection by late next year. But the opportunity set there is highly encouraging and progressing well.

We continue to watch our customers' budget announcements closely, which, of course, have an aggregate [ and less than ] inspiring at a headline level and which remain the ultimate growth governor for our business. But the same time, it has also been highly encouraging to see the relative resiliency of rig contracting activity this year in the face of elevated macroeconomic noise, sluggish oil prices and upstream capital restraint. These divergent dynamics underscore the strategic long-term criticality of deepwater within the global upstream supply stack. We see this and the renewed emphasis and urgency surrounding our stream reserve replacement metrics.

And in that same vein, on the ground here in Houston, there is a palpable growing sense of the capital imperative towards deepwater exploration in a way that feels different from anything over the past decade. So I would encourage investors to pay close attention to this important litmus indicator in the months and quarters ahead. Meanwhile, as we wait for these anticipated demand tailwinds to materialize, we continue to manage our costs and marketed capacity to optimize cash flow, and we remain committed to paying a competitive dividend and maintaining a strong balance sheet through the cycle.

With that, let me hand it back to you, operator, to go to the Q&A section.

[Operator Instructions] Your first question comes from Aaron Dorian from JPMorgan.

Robert, I wanted to maybe start with your thoughts on improving the utilization for your high spec floater fleet. You mentioned that you're 70% booked for 2026 with a target of getting to 90% to 100% by the second half of 2026. Talk to us about the opportunity set to get there, and kind of how long is a [ plot ] using a gulf analogy, would it take to get there?

Thanks, Aaron. So really it revolves around the [ Viking, the J D' Souza ] and the BlackLion. And let's see, continue at the gulf analogy, I'd say it's really not a very long -- I think we -- while we didn't have any real new news for you this quarter versus last, but we are advancing conversations around all 3 of those rigs. And we hope have some news for you here in the not-too-distant future. So we're -- those are all very technically capable rigs. We're bidding the discussions around a couple of different areas, but we do have line of sight towards the work that we're hopeful to win.

Great. That's helpful. And maybe if you guys could maybe just elaborate on the Diamond Offshore or BOP leases. I believe those are agreements of the rigs that you acquired. Can you just go through maybe the mechanics of that a little bit? It sounds like it's a pretty quick in terms of a cash return payoff given the savings and maybe just go through the numbers a little bit, just so we can tighten up our models.

So there's 2 components to it. There's the service agreement and the lease agreement. So we've now terminated the service agreement, and we'll have about a $35 million payment on that here in Q4. Okay. So that's $35 million of kind of cash out of the door during the fourth quarter of this year. On the lease agreement, we're still working through that. There is a cap on that agreement of $85 million, and that would be payable next year. Obviously, there's a few remaining lease payments as well. So if you sum that all that together, there's a maximum of $135 million of cash out of the door and then the kind of the annual cash savings, if you will, [indiscernible] is about $45 million for that. So it's about 3x EBITDA on the multiple on that, if you will.

Your next question comes from Greg Lewis with BTIG.

Robert, I was hoping for a little more color, and I guess you kind of touched on it with some of the comments to [indiscernible] But like as we think about the first half of '26, [ the kind of the ] moderately down versus what we are going to do in the second half of '25. As we kind of look at those drill ships, some of them all [ have idle ] time in the second half of '25. It looks like there's going to be some idle time in the first half of '26. Is that largely what's driving that? Or is there other costs? Is it maybe some idle time on the jackup fleet, just kind of if you could kind of help us maybe bridge why we're thinking it could be down? And what -- I mean, I'm assuming the answer to getting it higher would just be [indiscernible]? .

Yes. It really is largely driven by the floaters. Last quarter, we mentioned trying to get to a run rate [ of about $400 ] million and $500 million of cash flow here in kind of back half of the year. And really, the driver there are the 3 rigs I mentioned earlier. I think what -- I guess also I mentioned we just -- we're aiming to get back to effectively market utilization [indiscernible] 90% to hit those numbers. And that translates to kind of 2 out of the 3 of those rigs working at any given time. And [indiscernible] different different jobs. We're not going to win everything that's out there, but we feel pretty confident that as we work through things that the goal of having 2 out of those 3 is very achievable and [ hopefully cannot perform by finding work for all ] 3 of them.

The [indiscernible] about spot work. I think right now, it's one of those times in the market. It's actually a more unique time, I think, than I've seen previously, where there is a fair amount of work on the horizon starting in '26 and '27, but there is a definitive gap in between, where it's quieter than we've seen in multiple years. I'm probably missing some piece of history as I reflect on that, but I find it somewhat similar in nature. And so I think the spot work, the gap filler work, so to speak, is going to be really separated from the rest of the work that's out there as it prices and as people think through it. So I anticipate that to be a dynamic that plays out through 2026.

Okay. Great. Super helpful. And then just the other question I had was around -- I know it's hard to look at snapshots in time but just plan of trying to understand, I think we all see the work out there, whether it's West Africa or parts of Asia. But as we look at some of those term jobs that are out there, do we get a sense [indiscernible] [ are those states ] kind of remaining firm, just given some of the macro out there are jobs that maybe 3 to 6 months ago, we thought were going to be in the second half of '26 still lining up to be in the second half. I'm trying to understand if there's been any drift or slippage in some of this work that's -- that me and you and a lot of people are waiting to kind of [ start early ], yes.

Yes, it's been a mixture. I think there's some that have helped [ firm ] and then there are some that have moved to the right. We really haven't seen anything being pulled back forward. That's certainly not the feeling [ in it ] right now. But I'm just off the top of my head, I can think of a handful of jobs that are -- that have been pushed by, say, 6 months. And I can think of a handful of jobs that are right on schedule with our customers eager to start kind of in the middle or the beginning of the start window. So I think it's a mixture.

Your next question comes from Eddie Kim with Barclays.

Just wanted to touch on your expectations for the first half of next year. So you mentioned you expect moderately lower earnings and the cash flow compared to second half '25 levels. Consensus currently has you guys at around $440 million in EBITDA, which represents about a 10% decline versus what your guidance implies for second half of this year. So just curious if you could speak to your expectations for first half [ '26 ] relative to where -- what consensus is that now? And what it would take maybe in terms of some incremental contracting and spot market from here to achieve that level of EBITDA or if that level might be a bit too optimistic at this point?

Yes. So we're not -- we haven't given out quarterly estimates. So let me [ think about how. ] [indiscernible] true directionally that all that fits with kind of our narrative in the prepared remarks. And I think I would focus also on the fact that there's not a whole lot of work that we see in the first half of '26. There'll be a couple of announcements out there. There is some [ depth ] for the work that I mentioned earlier. The really -- I don't think there's a lot of room for upside improvement in the first half of the year. That does change pretty dramatically in the second half of the year. Of course, some of [ that is known and ] contracted and announced for both us and our competitors. But there's other work out there as well that's being negotiated hasn't been announced industry-wide.

So I think we're really focused on the timing of that. Working, we've set everything up, as we've mentioned, to hit this cash flow inflection. And for us, the timing is a little less certain around that back half of the year. But we certainly see it coming.

Got it. Got it. Understood. Follow-up is just on your expectation for that, you call it the deepwater utilization recovery by late '26, early '27. Could you just talk about your confidence level in this recovery? Is it based on the tenders that are out there currently or the tone of your conversations with customers or contracts that you already have in hand. So if you could just talk to your confidence level in that recovery. .

Sure. Yes. I mean, it's a mixture of both. We -- starting with the contracts in the U.S. and in [indiscernible] , I think we've kind of baked in somewhat of a floor for ourselves starting in the back half of next year. And we really see a tightening of the market out there. Some of that's announced and out there. Some of it is rumors that we understand some of our competitors [indiscernible] work and some of it's stuff that we're working on ourselves. We're cautiously optimistic here that day rates have bottomed. And not to say that there won't be some lower day rates that get announced after I've made the statement, but we're cautiously optimistic that from here, the market is tightening to a point late '26 and '27 that we bottomed here. So stay tuned.

Your next question comes from Fredrik Stene with Clarksons Securities.

Well, [ I think you think ] the -- relatively, I guess, optimistic picture of demand from the second half of '26 and beyond, then you've mentioned a handful of rigs by name are typically the [indiscernible] [ BlackLion ], which you seem to be relatively confident that you'll get some work on. But I was wondering, there is a [indiscernible] and [ there to deliver ], for example, do you have any additional color on how we should think about those rigs specifically going into next year? And maybe even more so [indiscernible], is that also going to be at some point a divestment candidate after this contract? Or do you think it can get more work?

Yes. That's a good question. So in [ GT1 ], we continue to chase interventional work, as we've mentioned, in that we continue to believe that, that is an interesting market for that asset. We also have said that it could be a divestment candidates. So it's a little too early for us to kind of give anything firm there. But I would say that both of those, frankly, are on the table. If we can't find work for the rig in the intervention market, then we'll make a decision there.

On the [ delivery ], so I would maybe group all of the [indiscernible] together as a bundle and say that we see more work today than we've seen at any point since at least the Noble side [indiscernible] for the last few years. Our outlook does not require all 3 of those rigs to be working. So I think all finding work for all 3 would be [indiscernible] for us. But we have -- we think we have a pretty good line of sight to at least 2 working and again, probably more increase than we've had at any point.

That's very, very helpful. And as a follow-up, just turning on the less spoken about assets also on the floater fleet and maybe more in the harsh environment side. You have the great [ white the Apex and the endeavor ] that's currently idle. And I guess there's a 2-part question here. One, on the [ GreatWhite ] is originally a U.K. type of rig, but have you thought anything more about potentially taking that rig into Norway, getting a proper [ AOC ]? And I'm sure that [ will convert with a ] major CapEx payment, if you like to do something like that? And on the Apex and the endeavor, how do you think about the [indiscernible] size in general? Or do you think that's maybe [ 1, 2 many rigs ] that are [ our current guidance on ] the lower spec harsh environment side?

Yes. So the [indiscernible] we're marketing but a number of [ different regions around ] the world. You're right, it was not built to a Norwegian spec so there would be a capital cost to take it into Norway, if that were to become an option. So I think we're just a little too early right now to give guidance on where that rig might end up. There will be some white space on it and we're trying to find the best fit for it at any point in the future. There are several different jobs out there in different places around the world. .

The Apex and Endeavor likewise have opportunities. And like with all of our older rigs, we'll continue to have a very sharp control and look at opportunities closely. And for us any opportunity needs to stand on [indiscernible] for those rigs, and that's pretty firm on our side. And so those are being marketed and hope they have some update on direction there. Perhaps next quarter, we'll see.

All right. This is very good. Thank you for all the details, and I'll hand it back.

Have a good day.

Your next question comes from Doug Becker with Capital One.

Robert, [indiscernible] expand on the prospects for the BlackLion specifically? Is this likely to be well to well worked in U.S. Gulf [indiscernible] more likely to be term work in the U.S. Gulf or some other region? [ Just given you talked about line of sight to contracting that rig ].

[indiscernible], sorry. Yes. Look, I think we're talking to customers of that book. And actually, we think we have opportunities both in the Gulf and outside the Gulf right now. So I wish I had more direction than that. But we're kind of honestly, we have opportunities that fit in all 3 of those categories, short-term U.S., long-term U.S. and long-term [ non-U.S ]. So we're going to have to just see what comes through for us here.

Fair enough. And then maybe slipping back to Norway, it was kind of encouraging to see the reactivation of the Interceptor. Does this mean that there's a meaningful tightening in that market and really kind of thinking about some of the CJ70s that are working outside, the way the potential of moving back in, say, '27 or so.

Yes. Look, I would say, I wish I could report that we saw a flood of work coming in Norway for the CJ70s. I can't claim that right now. We do have more opportunities today than we did 6 months ago and certainly a year or 2 ago, and that's driven us to look at reactivating the Interceptor there. I'd say that will be probably the most marketable rig in the region that doesn't have a contract that rolled out of [ that combination ] work. So we like where it's positioned. And we're hopeful that perhaps rig demand picks up by 1 or if it's already picked up by 1 side kind of maintain steady there. But it is a little too early to tell. And this contract I had stands on its own, and we're really happy to have it.

Your next question comes from Noel Parks with Tuohy Brothers.

I just had a couple. Is it safe to say at this point that price sensitivity is not in the mix in a big way in customer decisions either from sort of a formal perspective, which would maybe urge them to commit sooner rather than later or so from a bargain hunting perspective. So is this sort of just what we [ wanted you being ] conservative on their budget commitments, the main driver [ that's at work these ] days?

I wish I could say yes. I don't think so. I think our customers are as [ price sensitive as ] ever. The [indiscernible] is obviously variable and uncertain. There's some downward oil price beliefs. And we'll learn more as 2026 budgets start to get announced and become more clear. But we're -- I would say we're seeing the opposite. I'd say we're seeing extreme price sensitivity in our ongoing negotiations.

Okay. Okay. And you did mention serving in the wrap-up of the prepared remarks that in Houston on the bound there, it feels different from how it has in terms of settlement towards the deepwater at any time in the past decade. I wondered if you could talk a little bit more about, I don't know if there's a sense of being like an inevitability of the [indiscernible] offshore relative to onshore opportunities. But just any sort of color or feel you can give for what you're hearing?

Sure. I think here, it feels like it's well known that deepwater is going to be an important part of the supply mix going forward. That is obviously in the context of a slowing plateauing Permian, which eventually some day has to decline. Deepwater. It's obviously a long cycle and it requires forward thinking and investment. And those investments have to start at some point, to me, that's the most obvious connector between the delays in the macro environment in a world where a lot of people are calling for perhaps lower oil prices in the near term with the '26 and '27 opportunity set that we see in 2026 and 2027. And so I think we see more activity than perhaps 1 would have predicted if just given the macro uncertainty out there today. And to me, that explanation is -- 1 possible explanation is the understanding that deepwater is an important part of the energy mix going forward.

Right, right. And if I could just...

I'll just add, Noel. We mentioned [ operation ]. I can't say today that we've seen any uptick in exploration wells. I have seen an analysis that shows that the higher explanation of the difference in rig count from last market cycle high in 2013, '14 to today is the difference between development work and exploration work. And so I think that's something we've watched very closely. I don't think it's right on the horizon as a driver for demand in our business, certainly not in 2026. But I do think that's an important litmus test, which is why we mentioned that because we're running at around 90% utilization today on the pretty heavy development load or put a different way on a pretty low total exploration -- and so we watch that very closely. And we'll see what happens over the next couple of years here.

Great. And I just wanted to ask [ 1 more on that about ] I think last quarter, you were observing that in general, in West Africa, customers were a little slower to commit than compared to South America. So I just wondered if that's unchanged. And you're talking about oil sentiment. It has [ been ] surprising to me that there seems to be just a lack of attention to sustained geopolitical premium in the oil strip these days despite [ there still ] quite a few hotspots out there to be sure. And I just wonder if there are -- if you saw the sort of concern about future oil prices or oversupply or whatever, if you saw it playing out more strongly and just thinking of customers in 1 region than another?

Yes, sure. So first, just on West Africa, that's a long-cycle region takes a lot of planning. I think last quarter, we mentioned [indiscernible] mentioned that really a difference between where we, at 1 point, we're hopeful the demand picture would be around this time. And reality here is explained by a lack of West Africa demand. We see that starting to play out in a number of countries in West Africa. [ We mentioned those in beat too. ] I think that comes online in the next couple of years. So if that corrects itself, I think that's a few units of demand that I think is going to really help in like '26 and '27 bring total utilization -- or excuse me, [ total demand ] back where we were predicting it to be.

On the oil piece, I think there's a lot of negative sentiment. There's a lot of people hold the belief that it's likely to go down before it goes up. We struggle to predict obviously. I will say, I guess, kind of -- what I said around what we see on service demand [indiscernible] services, which is encouraging. And then I always point to kind of the middle part of the Brent curve which has moved so much less than spot pricing and then a very volatile sentiment. And if you're a deepwater operator, you're obviously having to take 5- and 10-year view. So if it makes sense that with that middle part moving less that we're seeing -- planning continue, perhaps beyond what the otherwise [ auto macro would ] suggest.

[Operator Instructions] Your next question comes from Josh, Daniel Energy Partners.

I just had one. I think it was at the end of the prepared remarks. You talked about the balance sheet and some cost rationalization. Maybe you could speak to the efforts you're taking on the cost side. And if you view those as sort of structural or if these are things that you're doing, assuming that we have a trough in the first half of next year before we [ recover ] maybe just go into more detail on the things [indiscernible]

Sure. Yes. Obviously, the cost in the [ down markets ] could be very important -- and I think as you think about the Diamond transaction as an example, [ right, ] in that deal, will be [indiscernible] $100 million of synergies. We achieved that order, I guess, in Q2 of this year. And so we [indiscernible]. [ Now obviously, some materially ] higher than that. But it's hard to bifurcate what is the synergy versus the other kind of cost work that we're doing in the company. So we haven't put out a kind of an incremental cost savings target, but I think it's fair to say that we're realizing kind of the incremental cost savings [indiscernible], activity slows here in the first half of next year.

There are no further questions at this time. I will now turn the call back over to Ian MacPherson for closing remarks.

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

Ladies and gentlemen, that concludes today's call. Thank you for joining. You may now disconnect.