Noble Corporation

Good morning. My name is Jeremy, and I'll be the conference operator today.

At this time, I would like to welcome everyone to the Noble Corporation's Q2 earnings call.

Welcome, everyone, to Noble Corporation's second quarter 2023 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. This conference call will be accompanied by a slide presentation that you can also find located at the investor relations section of our website. Today's call will feature prepared remarks from our President and CEO, Robert Eifler, as well as our CFO, Richard Barker. Also joining on the call are Blake Denton, Senior Vice President of Marketing and Contracts, and Joey Kawaja, Senior Vice President of Operations. During the course of this call, we may make certain forward-looking statements regarding various matters related to our business and companies that are not historical facts. Such statements are based upon current expectations and assumptions of management and are therefore subject to certain risks and uncertainties. Many factors could cause actual results to differ materially from these forward-looking statements, and Noble does not assume any obligation to update these statements. Also note, we are referencing non-GAAP financial measures on the call today. You can find the required supplemental disclosure for these measures, including the most directly comparable GAAP measure and associated reconciliation in our earnings report issued yesterday and filed with the SEC.

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

good morning welcome everyone and thank you for joining us on the call today i'll begin with some opening remarks on our strategy and recent milestones and then provide some comments on the macro and market outlook before turning the call over to richard to review the financials after the prepared remarks we look forward to taking your questions first on strategy and milestones we announced the initiation of a regular quarterly dividend program starting with a 30 cent dividend here in the third quarter with this We are proud to introduce the first dividend program in our peer group since 2016. Coming out of the recent downturn, our existential strategic priorities over the past two years have been centrally focused on consolidation, cementing our brand with customers as a first choice drilling contractor, and establishing an industry-leading free cash flow generation and return of capital platform. Strict capital discipline and return of cash are absolute imperatives to the investment thesis for this industry, and Noble is committed to these investor priorities. Recall, the offshore drilling sector, including Noble, generated elite total equity returns throughout much of the 2004 to 2014 super cycle, with cash yield featuring prominently in the stocks during that era. We believe that we are in the early stages of the next long-term up cycle. albeit one conspicuously without the frothy asset bubble conditions that drove the supply side off the rails last time, and with structurally sounder balance sheets. This presents a highly constructive setup for what we anticipate as a multi-year upcycle, not just for day rates, but for sustainable free cash flow as well. More on this in a few minutes. Following near-to-date share repurchases of approximately $70 million, In addition to the $86 million of share repurchases that we made late last year, including the squeeze-out associated with the closing of the Marist drilling combination, this initial quarterly dividend represents the next logical step in our strategy for maximizing shareholder value. Going forward, we plan to return the significant majority of free cash flow to shareholders over time via dividends and share repurchases. and we will look to scale both of these instruments higher as cash flow generation continues to grow, while preserving a conservative balance sheet along the way. Richard will speak more to the financial results and outlook, but our second quarter adjusted EBITDA of $188 million was overall a solid result. So, congratulations and huge thanks to our fantastic crews and shore-based teams around the world for a job well done in staying laser-focused on safe and efficient operations. And of course, also in the category of important milestones, we were pleased to generate over $100 million of free cash flow in the second quarter. On the commercial front, we've had several noteworthy contract awards recently that confirm the continuing strength in the ultra-deepwater market. The largest backlog addition was for the two-and-a-half-year contract for the Fay-Kozak with Petrobras. This contract, valued at nearly $500 million, is expected to commence early next year at the BMS 11 in Tupi Fields. And we're incredibly excited to be renewing our participation in the Petrobras fleet, with so much activity growth expected to unfold in Brazil in the years ahead. We've also recently secured several additional floater fixtures of shorter-term duration. The Novo Voyager was awarded an additional contract from Shell for an exploration well in Mauritania, which is anticipated to follow in direct continuation of the current Shell program in Columbia, and extends the Voyager's backlog through the end of this year. Next, the Noble Discoverer received a one-well contract with Petronas in Suriname, expected to commence within the next few weeks, with an estimated duration of 90 days. This contract has a total value of approximately $43 million, including MOB-DMOB and certain additional services. Next, the Noble Viking had three option wells exercised by Shell and PTTEP, with total contract value of approximately $49 million, an estimated total duration of 111 days. And most recently, the Noble Deliverer has received a nine-month contract extension from INPEX in Australia, expected to extend that rig from July 2024 to April 2025 at $451,000 per day. On the jack up side, the Noble Intrepid has a newly announced contract with Harbor Energy for a 10-month accommodation scope in the UK North Sea that is scheduled to start in the fourth quarter of this year. This contract also has a customer option for a three-month drilling program that could be exercised at either the front or the back end of the accommodation piece. With these, our current backlog has expanded to $5 billion. up from $4.6 billion as of last quarter. You can find a summarized schedule of our backlog on page five of this slide presentation. Now I'd like to spend a few minutes on the macro and industry outlook. In short, the deepwater market remains tight with high utilization, limited and dwindling sideline capacity as reactivations continue at a measured cadence. In contracting and tendering momentum, it demonstrates the continued upward trajectory with expanding contract term and procurement lead times. Contracting dynamics for UDW rigs are thus far playing out consistently with our expectations. The worldwide UDW floater market balance is 91 contracted rigs out of 99 marketed rigs for a 92% utilization rate. This has been the prevailing contracted demand level over the course of the past six months, with the recent pause in demand growth driven by tight supply. Other salient statistics, including expanding offshore driller backlogs as well as total contract volumes, confirm a clear uptrend in pent-up demand. Notably, the 62 rig years of floater fixtures in the first half of 2023, which was a 35% increase over the first half of 2022. Average contract term is also lengthening. Even excluding Petrobras' long-term contracts and the term additions to Noble's CEA-related backlog in Guyana, the average term duration of all other floater fixtures in the first half of this year expanded to approximately 11 months, up from eight-month average terms in 2022. With these leading indicators, as well as our specific bidding pipeline, we continue to see a clear path toward incremental global demand for 10 to 15 UDW rigs through 2024 relative to current levels. I'll begin with South America, where FIDs in the first half of this year surpassed the entirety of 2022, 80% of which are for deepwater. Petrobras, of course, remains the largest buyer in the market, with 20 floaters currently under contract, up from 17 early last year, and an additional five rigs contracted to start up over the including the Noble Fay Cozac. Additional open demand from Petrobras totals eight rigs, including seven domestic rigs and one for Columbia. We expect the combined seven domestic tenders to net four incremental UDW rigs required to be imported into Brazil, including perhaps a couple of stranded new build reactivations. While subject to normal slippage, All of these tenders are expected to conclude this summer and bring Petrobras' deepwater rig count into the low 30s by the second half of next year on two and a half to three year terms, as well as four of which have 2025 commencement windows. It's too early to tell whether these most recent tenders will represent incremental rigs or if they will be filled by existing rigs being extended, but they do demonstrate Petrobras' ongoing long-term procurement needs. In the U.S. Gulf of Mexico, floater demand is 23 rigs, supply is 24, and utilization is 96%. Forward demand is expected to be flat to up slightly, and additionally, the Mexican side of the deepwater Gulf of Mexico

is getting increasingly active in the Gulf of Mexico, given the lack of spare capacity.

Rounding out the Americas, The Guyana-Saranam Basin is expected to remain constant at six to seven UDW rigs through 2024, with potential upside from 2025 onward. And Columbia continues to be a re-emerging exploration plate that should occupy one to two rigs with increasing consistency as the expected Petrobras-Columbia rig line commences next year. We have the Noble Voyager drilling a well for Shell in Columbia presently, and the Noble Discoverer is scheduled to drill a well for Echo Patrol later this year. In West Africa, there is 100% contracted utilization on 20 marketed floaters, although this total includes a few units that are actually preparing for future contracts in Brazil. So the underlying regional demand is actually 16 to 17 rigs led by Angola, Namibia, and Nigeria. We see incremental demand of three to five rigs in 2024, with the anticipated supply deficit evidenced by the increasing amount of long-term tenders in the market. There are currently several outstanding tenders for terms of two years or more, with intended start dates between 2024 and early 2025. So collectively, the Golden Triangle of the Americas and West Africa comprises 75% of current EDW floater count. with incremental demand of 10 to 12 rigs versus the current baseline, plus what has already been forward contracted. Our fleet is primarily concentrated in the Golden Triangle, with 14 of our 16 rigs working in these regions. That said, there are also bidding opportunities for floater programs across the Asia-Pac region as well. It's the Black Sea that we're evaluating. To summarize the overall state of play in the UDW market, The expected near-term demand growth of 10 to 15 additional units is well supported by the current tender pipeline, with the next group of Petrobras awards representing a significant step in that progression. There remain approximately a dozen high-spec drill ships in sideline capacity yet to be contracted, including our drill ship Meltem. We expect a few of the sideline rigs to be absorbed by near-term contract awards in Brazil and West Africa, and it has been commonplace for rigs coming out of reactivation to win work at below average day rates. We expect this dynamic to continue with the diminishing pool of sideline capacity. However, as evidenced by Noble's recent fixtures, there remains clear pricing power for premium hot rigs. Therefore, we see continued upside to leading day rates as these next dominoes fall and continue to believe that the $500,000 day rate threshold will be eclipsed fairly soon. We maintain a patient bidding discipline with our cold stack drill ship Meltem, and we do fully expect to win a high quality contract for this rig when the right opportunity aligns. With persistent cost inflation, we currently estimate that the Meltem would entail approximately $125 million in at least a year to reactivate, although these estimates could expand depending on the requirements that a specific contract opportunity might require. Now on to jackups. Obviously, this has been a lagging part of our business thus far due to demand softness in the North Sea and Norway. And although there isn't necessarily an assertive demand inflection afoot, we believe that we have sufficient contract visibility now to call the first half of this year as the trough for our jack-up fleet, with tangible utilization improvement expected over the next four to six quarters. This is supported by recent and pending contract startups for the Tom Prosser and Intrepid, which have both been idle throughout the first half of this year, as well as a constructive outlook for the Regina-Allen, expected to be redeployed by mid-2024 upon completion of its repairs. The Regina-Allen is currently in shipyard in the Netherlands, scheduled to finish the work on its lag and jacking system early next year, and has good contract visibility for work outside the North Sea next year when the rig becomes available. Beyond these discrete improvements, The longer-dated upside catalyst for our jackups would necessarily need to come from the Norway market. We're obviously following the tightening dynamics within the Norway harsh floater segment with great interest and attention since the competition zone of the Norwegian shelf could be impacted. There's nothing new to report today, and our base case is still for a choppy muddle-through market for the CJ70 jackups until late 2024 or 2025. That's not a permanent prescription. It could be subject to change, but that's our assessment as of today. It's also worth highlighting that while Northern Europe's heightened emphasis on energy transition and sustainability has certainly created policy friction and general headwinds for offshore drilling demand, it's also opening new market opportunities in CCS as well as collaborative opportunities for technology adoption. These are areas where we believe the combined Nebel Maersk Drilling Enterprise brings great value to the market. For example, we plan to build on our early leadership position in the offshore carbon injection market, following the first pilot injections at Project Greensand carried out by the Jackup Noble Resolve earlier this year. And we intend to also continue to advance our customers' decarbonization goals through the deployment of our proprietary emissions monitoring software and other emission reducing technologies. And certainly one of the critical selling points with our marketing strategy for the competition zone in Norway is the ability to displace a significant amount of emissions by utilizing a jack-up in place of a floater. So that wraps up the overview on the market fundamentals, and I'd like to pause now and turn the call over to Richard to go over the financials.

Thank you, Robert, and good morning or good afternoon all. In my remarks today, I will briefly review the highlights of our second quarter results and then discuss the outlook for the second half of the year. Contract drilling services revenue for the second quarter totaled $606 million, up from $575 million in the first quarter. Adjusted EBITDA was $188 million in Q2, up from $138 million in Q1. Diluted earnings per share was 45 cents, and adjusted diluted EPS was $0.38. Cash flow from operations was $211 million, capital expenditures were $107 million, and free cash flow was $104 million. As anticipated, revenue in EBITDA improved from first quarter levels due to higher day rates across the fleet. Our 16 marketed floaters were 90% utilized in the second quarter, down slightly from 91% in the first quarter with average day rates increasing to 363,000 per day in Q2, up from 332,000 per day in Q1. Our 13 marketed jackups were 62% utilized, with an average day rate of 129,000 in the second quarter, compared to 67% and 98,000 per day in the first quarter. The average embedded day rate in our current backlog is slightly above $400,000 per day, for floaters and slightly above $180,000 for jackups, providing positive repricing visibility into the future. As summarized on page five of the earnings presentation slides, our total backlog as of August 1st stood at $5 billion, up from $4.6 billion last quarter. This includes $855 million that is scheduled for revenue conversion over the second half of 2023 and nearly 1.6 billion that is scheduled for 2024. It is important to note that our backlog excludes reimbursable revenue, as well as revenue from ancillary services. We are now nine months in with the MERS drilling integration, which continues to progress extremely well. We continue to expect to have realized over three quarters of the 125 million targeted annual run rate cost synergies in the fourth quarter of this year. As of the end of the second quarter, we have achieved over $80 million of annual run rate synergies. Referring to page 9 of the earnings slides, we are maintaining our full-year guidance, including total revenue between $2.35 and $2.55 billion, adjusted EBITDA between $725 and $825 million, and capital expenditures of $325 and $365 million, excluding any customer reimbursable capex. While we are leaving the full year guidance unchanged, we do believe that through strong execution and recent contract awards, we have substantially de-risked the low end of the range for both revenue and adjusted EBITDA. We now anticipate a different quarterly sequential progression than before, as the third quarter is now expected to be the highest quarter of the year in terms of adjusted EBITDA contribution, followed by a temporary sequential downtick in the fourth quarter. Accordingly, we now expect the second half of 2023 to account for slightly below 60% of the full-year total, with Q4 landing somewhere between Q2 and Q3 levels. This is driven by a stronger-than-expected first-half result, as well as recent fleet status updates impacting the timing of contract sequences in the second half. The main change there is related to the noble FACOSAC. which is now scheduled to work through most of the third quarter before it goes off day rate for several months of contract prep and mobilization for Petrobras. We remain very excited about the financial prospects for 2024 and beyond, and we do expect a material step up in adjusted EBITDA and free cash flow in 2024 versus 2023. This year has been impacted by natural utilization friction associated with short-term contracting on the floater side, and this friction will likely persist to an extent in the first half of 2024. We have recently begun to see a modest pickup in jackup activity and do believe that we have seen the trough in EBITDA contribution from our jackups in the first half of 2023. Lastly, I would like to provide a brief word on cash flow. We obviously saw a very nice sequential improvement in the second quarter, which, as expected, benefited from the reversal of the first quarter's working capital build, in addition to the material sequential improvement in underlying financial results. As Robert stated, we are committed to returning the significant majority of free cash flow to shareholders over time via share repurchases and dividends. Of course, with the normal short-term volatility of working capital and other factors, Free cash flow progression is rarely linear as our Q1 and Q2 results demonstrated. In the first half of this year, we repurchased approximately $70 million worth of shares, which exceeded our free cash flow. Starting this quarter, a 30 cent per share dividend will provide a stable quarterly distribution to shareholders. Supported by a conservative and flexible balance sheet, growing contract backlog, and expectation for multi-year offshore upcycle, we will look to increase capital returns via buybacks and dividends in the future as our free cash flow increases. That concludes my remarks, and now I'd like to pass the call back to Robert for closing comments.

Thank you, Richard. To conclude, I just want to quickly follow up on my earlier statement regarding the promising setup that we see for a sustainable free cash flow cycle. Because I think this is a very important topic, and I suspect the most important consideration for many investors. First of all, we've been very clear and intentional with our capital allocation priorities. Strict capital discipline, returning free cash flow to shareholders and preserving a conservative balance sheet isn't necessarily a novel formula in the new energy order, but this does have profound implications in a highly capital intensive industry with long life assets such as ours. The reality is that our industry, has 12 or so remaining high-quality drill ships in sideline inventory, a few of which are soon to be absorbed on contracts. And then Tier 1 UDW capacity is tapped out. According to past cycles, this situation would have naturally triggered a supply response, typically first with a few early speculative new build orders by nimble entrepreneurs, followed by a combination of speculative and contracted new build orders by the larger players. Numerous factors argue against that version of history repeating itself, including cost and access to capital, shipyard complicity, current asset valuations, and risk aversion by public company management teams. But even more to the point, new builds are way off the radar because even without the aforementioned soft constraints, the economics are simply entirely out of the money. A hypothetical new build with comparable capabilities as a current tier one seventh generation drill ship would likely cost at least $850 million to build and require at least three years, if not longer, for delivery. In order to underwrite that asset, a rational buyer would require a contract of 10 years at $650,000 per day or greater, or some variation of rate and term along those lines. Essentially, you would need a sponsoring customer to take a 15-year view on scarcity day rates. By contrast, we anticipate generating attractive levels of free cash from the existing asset base after appropriate maintenance spending on the fleet, which is not inconsequential. And yet, where we sit today is nonetheless within a historically wide disconnect between day rates and embedded asset values. Depending on certain assumptions for individual assets, we would posit that our current equity valuation is discounting between $350 and $370 million per Tier 1 drill ship within our fleet, consistent with the range that we observe in research. This is significantly below 50% of replacement costs. However, by very stark contrast, during the prior new build cycle, capital markets were rewarding growth as offshore driller stocks were at that time commonly trading at embedded rig values above replacement cost. Therefore, new build orders were incentivized by the market because they were both economic and accretive at the time. This is a completely inverted state of affairs compared to today. Accordingly, We believe that the extreme remoteness of new supply combined with the current state of fundamentals, incentives, and valuation form a compelling investment thesis and the basis for a sustainable cashflow runway for Noble. Just to wrap up here, we've been through an extremely busy and dynamic past two years, moving as briskly but thoughtfully as possible to execute our consolidation and integration playbook, to keep our customers front and center, to optimize the balance sheet, and ultimately to deliver on our ambition to create a differentiated cashflow oriented investment platform. Noble is in a terrific position as a company right now, not by accident, but thanks to an immense amount of hard work, strategic planning, collaboration, and professionalism on the part of countless team members worldwide. Going forward, we will remain highly focused on execution and driving value for our customers and our shareholders. With that, We're ready now to open up the call for Q&A.

Perfect. Thank you so much. If you would like to ask a question today, please press star followed by the number 1 on your telephone keypad. That again is star 1.

We'll give it just a quick second for the Q&A roster to compile. All right.

It looks like our first question comes from the line of Kurt Haleed. Kurt, please go ahead.

Hey, good morning, everybody.

Good morning, Kurt.

Thanks for that. Thanks for that summary. So kind of interested here on the thoughts, you know, your commentary is kind of spot on with respect to leading edge rates being kind of mid to high fours and the expectation to kind of, you know, reach above that $500,000 marker for assuming an ultra deep water drill ship because I think one of your competitors, you know, put up a rate north of 500 for a semi submersible in Australia. So, you know, in the context of that, Robert, do you think this is kind of a trickle effect or do you think it's going to be like, you know, the dam breaking once, you know, once the first rate goes above 500 it's, you know, the rest are going to follow pretty quickly?

No, I think it's a trickle effect. I mean, what we've seen so far has been a relatively steady progression, perhaps with a little faster velocity in the early stages than more lately. But I think one of the things that will drive pricing are periods of scarcity where there's more jobs than rigs. And those likely will present themselves at different, you know, random periods, a little bit hard to predict as programs come to market at their own time. So I think you'll see little step changes up when you see these periods of scarcity. And then the market, you know, probably holds on. Given the outlook, the market probably holds on to those incremental steps up as they come.

Okay. Appreciate that. So the second dynamic is you kind of referenced the average duration now being at about 11 months, but some of the recent tenders are looking more like two, three, and obviously we've had a couple of tenders out there for five or 10 years. So as you kind of maybe fast forward the clock into the next quarter and just look at the next leg, are you kind of seeing the same thing that than I think I'm seeing in that, you know, contract durations are going to be more like, you know, three years on average?

Well, we excluded some of the, you know, we excluded Brazil in our own Guyana contracts in that eight to 11-month analysis just to try to get a sense of, you know, maybe pulling out a few outliers. I think we're a ways off from three years as the overall average, unfortunately. But I do think that we'll see, kind of like we are in day rates, a consistent trend towards more term on a total UDW basis.

Okay. And then maybe if I might wrap up on use of cash. So you made a pretty substantial commitment in establishing the dividend. So when you think about your overall game plan or commitment on returning To ask the shareholders, you know, what kind of percentage of free cash flow, you know, would you be comfortable with, you know, committing, you know, as you go forward?

Yeah, Curt, it's a very good question. So, we've said it's going to be a significant majority of our free cash flow. So, obviously, that's going to be closer to 100% than 50%, you know, as it relates to more specificity than that. You know, I'm not sure we're not providing that at this stage, but obviously, Our return to capital program is very much going to be a hybrid or balanced approach. And, you know, as our free cash flow continues to grow, and obviously 2024 should be another step change for us as a company, you know, I think you should expect that the amount of capital that we return to shareholders will obviously grow significantly as well.

That's great. Really appreciate the call. Thank you.

Thanks, Kurt.

All right, our next question comes from the line of Eddie Kim. Eddie, please go ahead.

Hi, good morning. So just looking at your floater fleet, you have five rigs coming off contract before year end here at a time when the demand picture, which you laid out, looks very promising. So just looking at the contracts you secured this past quarter, they were in the mid to high 400s range. So as these five floaters get recontracted here in the coming months, should we expect them to reprice higher around that same level, mid to high 400s? Or could we see one or maybe even two of these rigs finally clear that 500,000-a-day threshold that you mentioned?

Yeah, thanks for the question, Eddie. This is Blake. I think we've got varying asset classes that roll over here in fourth quarter and first quarter of next year. And so you'll see varied rates associated with those. All of them will be consistent with market for each of their asset classes. You've got the 7Gs that you referenced, those day rates. And then you've got the Globetrotters and the D-Rigs, our DP plus more than semis. that are kind of just a step behind the 7Gs in terms of marketability. And you've seen the rates trail a little bit on that asset class. And I think what we see is we reprice something consistent with what we've seen in the past.

Okay. Okay. Understood. Thanks for that, Colin. And just shifting gears to reactivation, one of your peers yesterday said, highlighted the attractive economics for one of the rigs they're reactivating. But just in that context, do you think it's likely that we'll see the Meltem reactivated sometime this year? And for the Scirocco, I believe it's slightly lower spec than the Meltem, but are you currently bidding this rig into work as well or holding off on this until you're able to secure an attractive contract for the Meltem?

Yeah, I can take that one. The Meltem will go to work before the Sirocco. We're not marketing the Sirocco right now. We are marketing the Meltem. To your question about timing, we're unlikely to kick off a full reactivation here this year. Could we secure a contract that works for us this year? Yes, it's definitely possible. And then most of that work would be completed during 2024. And then, you know, if I were going to just put a percentage to it between finding that contract this year or early next year, I'd call it 50-50 right now.

Okay. Very good. And just the reactivation expense you quoted for the multiple 125 million, Is that just the cost to reactivate the rig, or does that encompass kind of an all-in cost, including spare parts and adding the crew and getting the rig fully ready to work?

That's a fully ready-to-work everything, including expenses. So that includes shipyard costs, crews, includes our own rig crews. That's everything. Okay. Okay, perfect.

Thank you so much. I'll turn it back on. Thanks, Andy.

All right, perfect. And just as a reminder, if you would like to ask a question, please press star followed by the number one. All right, our next question comes from the line of Greg Lewis. Greg, please go ahead.

Hey, thank you for that. And I did just want to follow up on that last comment since you were getting pretty granular, Robert. Does that include mobilization of sites? no the 125 no doesn't include mobilization yeah good point okay um great you know thank you um you know for for the color around the the capital allocation dividend you know i was hoping you know realizing that it's always a board decision but but i was kind of wondering if you could provide at least your kind of high level thoughts as you think about the dividend clearly offshore drilling rates are cyclical. I think Noble has the benefit of not really having a very strong balance sheet. So at any kind of view, you have, Robert, around the ability to kind of push the dividend higher through the cycle as opposed to maybe what is the sustainable dividend in kind of more, and I would argue we're normalized, but as you think about Day rates and sustainability of dividend, I mean, just given where the balance sheet is, it seems like we could have a sustainable dividend at these levels, even in a much lower day rate environment, not that we're going there anytime soon. But just kind of curious at least how you're thinking about the dividend, realizing that the next two or three years should really just see cash flow and earnings go higher. But on the back of that, do you ever really get full credit for it? you know, when people start asking about sustainability?

Yeah, sure. It's a great question, kind of right at the heart of the decision. Well, first of all, in spending time and coming up with the dividend and announcing it, we are all very aligned in making sure that it's sustainable. So you're right in pointing that out. We look at through cycle, excuse me, we look at through cycle rates And we consider what happens post a day rate peak. As you said, the next couple of years look great. And we think, as we said in the prepared comments, that there are a lot of things that are very much in place to drive this cycle for quite a long time. much more than the next couple of years. We'll have to see how everything plays out. But we do think 24 and 25 are going to be step changes for us if the market plays out as we and others are predicting. And so we would look to grow our return of capital as that happens, always with a mind towards sustainability though on the dividend side. And I think that's also one of the reasons why having a mixture makes a lot of sense for an offshore driller today. A mixture, obviously, being dividend and buybacks.

Yeah, great. Thank you for that. And then just wanted to talk a little bit about the North Sea market. You know, obviously, there's some open days here, but really, I guess, we're contractors. I guess a two-part question. One is, should we really, should we see any white space on kind of the North Sea fleet get filled up, you know, in the back half of this year, or is it really looking ahead to 24? And that, you know, I imagine the answer will include that. Any kind of view on the recent news by the UK government about, it seems like they're trying, it seems like they're, you know, beyond the flat tax that they're changing, and it seems like more recently they're talking about trying to incentivize some more activity out of the UK just around the whole energy security theme that everybody at this point is pretty familiar with.

Yeah, Greg, thanks for the question. This is Blake again. Of course, demand in the North Sea is still lagging the rest of the world there. But there are some positive signs on the periphery. I mean, you mentioned a really important one recently in the new licensing comments. And then there's also some carbon capture demand that could play out. And, of course, the harsh environment tightness kind of can play out in the competition zone, particularly for our CJ70s, which are the most capable to compete with semis in that space. But all of that is a little bit too far in the future to see it and really talk about it as direct demand. And so we do see white space for some of our jackups, uncontracted jackups into 2024.

And I can add to that, too. I think we're sorry. Sorry, but just quickly, I think I agree completely. And I think, too, it's a it's a bit of a funny period of time right now where utilization in the North Sea and rest of world is is is out of balance. And so I think that's I think that's just a time and a place. I think that that that will will balance out perhaps as this year unfolds and certainly into 2024. whether that's because rigs leave the North Sea or because we see some sort of reaction to policy shift or CCS. We'll see. But these, you know, most of the jackups really excluding the Norway class jackups, but the non-Norway class jackups, ours and our competitors, are pretty mobile. And I think you'll see all of that balance out in time.

Great. And just since you both mentioned the CCS dynamic, you know, honestly, that wasn't something I was thinking too much about. Is that kind of more on the well intervention side? Like any kind of just high level views on where you see the jack up demand coming from and realizing CCS is more of a, call it medium, longer term, probably demand driver. But would that just, yeah, what would those rigs kind of be doing as they're working on that? I don't think they're drilling new wells.

Well, they're drilling carbon capture wells, so you're drilling into a zone to inject CO2. It's too early to tell. We saw a statistic that, as drillers, you always hang on to the most positive possible statistic, but we saw a statistic that you could have up to 30 30 rig demand for carbon capture wells in just in the North Sea going. I mean, that's years and years away. No one could possibly predict that. And, you know, we're not calling for that or anything, but it will produce some level of utilization through time. We drilled a carbon capture well last year, as I mentioned. It's medium and long term, as you say, but it is real. And we've drilled carbon capture in Australia. I think one of our competitors drilled one as well. And it's happening kind of around. There'll probably be some demand in the U.S. as well. So there's a couple of components to it. There's an initial project phase and then there's a really important maintenance phase on those wells as as you're reentering a zone that has already injected CO2. So a lot of that engineering work is being done right now. And there's a lot of, I think, investment and money that's moving towards some bigger projects. But again, that's medium-long term, as you say.

Great. Hey, super helpful as always. Thank you.

Thanks. All right. Our next question comes from a line of David Smith. David, please go ahead.

Hey, good morning, and thank you for taking my question. Good morning, David. I thought your closing remarks were maybe the best summary of the investment thesis for offshore drillers that I've heard. I'm including several stabs that I've made. We very much appreciate that.

Hopefully, there's a wide range of new investors that heard that. I hope so, too.

The question I had relates to some of the requirements we've seen since late June for five-year-plus terms for drill ships from a couple of IOCs. On the one hand, I'm sure they're looking for a discount to lead in edge rates, but I can't think that's the main driver for the higher durations. I don't expect they have very defined work programs in years four and five or beyond. So it feels to me like the extended terms are really about securing availability. They're maybe getting nervous seeing the dwindling of incremental supply. But I'm curious how you think about the emergence of requirements for five-year-plus terms from IOCs, maybe the implications of that, because I think the equity market might not fully appreciate it.

It's a great point and y'all fill in if I miss anything here, but. I think after years and years of every deep water contract being closely connected with specific programs, we are starting to see hints of a little bit more of a portfolio approach, which is an important next step in the cycle. And you've referenced, you know the evidence exactly. No, there are a few programs that are five years out there that are project specific. But to the extent that operators are looking to contract outside of already FID projects, I think it's, I do think it's to secure availability. I think a dynamic we've talked about a fair amount is that operators are seeking efficiency and finding efficiency through, I would say, a deeper relationship with a number of their contractors, including the drilling contractors. So I think there could be an element of that playing out as well, where operators, if they're going to take a little bit of risk, are going to pick a company to take that risk with in the hopes that you can also find long-term efficiency gains as you work through time. But we take it as a great sign and a sign as to where certain EMP companies see this cycle going and how they see longevity, which, of course, we and our competition have been screaming from the mountaintops here for a while.

Very much appreciated. And a quick follow-up, if I may, with some of the requirements emerging in the Black Sea. I'm wondering if you see maybe any opportunities emerging for the globetrotter rigs that might take advantage of their unique mobilization capabilities and whether that could come with the chance to reduce their historical rate discount to Tier 1 7th General Ships.

Yes, for sure. The globetrotters won't get every job in the Black Sea, but certainly they have that niche that you've described. So we can get under the bridge there in, I think, 10 or 11, 12 days, something like that. And it would take any other rig, I think, 90 days, something like that. So there's a massive advantage there. So anytime you hear Noble say Black Sea, we're probably talking about the globetrotters. But we're hopeful that a well or two could play out. that would include the Globetrotters there. And yes, we would anticipate that that would close pricing gaps that we would otherwise see. Well, thank you very much. That's all I got.

Thank you. All right, perfect. And those are all the questions in the queue, so I'd like to turn it back over to the team at Noble Corporation to close things out.

Thank you, everyone, for your participation and interest in the call today, and we'll look forward to speaking with you again next quarter. Have a good day.