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Q2 2023 Earnings-Transcript
Operator: Good morning. My name is Jeremy, and I will be the conference operator today. At this time, I would like to welcome everyone to the Noble Corporation’s Q2 Earnings Call.
Unidentified Company Representative: 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.
Robert Eifler: 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 orderly dividend program, starting with a $0.30 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 2 years have been centrally focused on consolidation, cementing our brands with customers as a first voice 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 imperative 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 return 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 upcycle, albeit one conspicuously without the frothy asset level conditions that drove the supply side off the rails last time and with structurally sounder balance sheet. This presents a highly constructive setup for what we anticipate as a multiyear up cycle not just for day rates but for sustainable free cash flow as well.
And year-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 Mars drilling combination. This initial quarterly dividend represents the next logical step in our strategy for Maxim. 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 and 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 confirmed the continuing strength in the ultra-deepwater market. The largest backlog addition was for the 2.5-year contract for the Paco with Petrobras. This contract valued at nearly $500 million is expected to commence early next year at the BM-S-11 and 2P 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 pictures on shorter-term duration. Noble 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 Colombia and extends the Voyager’s backlog through the end of this year. Next, the Noble Discoverer received a 1-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 Momo and certain additional services. Next, the Noble Viking had 3 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 Deliver has received a 9-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 jackup side, Noble Intrepid has a newly announced contract with Harbor Energy for a 10-month accommodation scope in the U.K. North Sea that is scheduled to start in the fourth quarter of this year. This contract also has a customer option for a 3-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 5 of the slide presentation. Now I 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 6 months with the recent pause in demand growth driven by tight supply. Other saline statistics, including expanding offshore driller backlogs as well as total contracted 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 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 8-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 5 rigs contracted to start up over the next 6 to 7 months, including the Noble Pecos. Additional open demand from Petrobras totaled 8 rigs, including 7 domestic rigs and 1 for Columbia. We expect the combined 7 domestic tenders to net 4 incremental UDW rigs required to be imported into Brazil, including perhaps a couple of stranded newbuild 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. Additionally, just over the past week, Petrobras has launched another tender for 3 high-spec floaters on 2.5- to 3-year terms as well as a 125-day tender for a more float, all 4 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%. The 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. While the Noble Globetrotter I is the only currently active floater in Mexico today, there is currently open demand for several programs of short to midterm duration with various operators in 2024. Increased activity in Mexico is likely to support continuing tightness in the Gulf of Mexico, given the lack of spare capacity.
Mounding out the Americas, the Guyana-Suriname Basin is expected to remain constant at 6 to 7 UDW rigs through 2024 with potential upside from 2025 onwards. And Colombia continues to be a reemerging exploration play that should occupy 1 to 2 rigs with increasing consistency at 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 Ecopetrol 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 in Nigeria.
We see incremental demand of 3 to 5 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 2 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 as 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 drillships and sideline capacity yet to be contracted, including our drillship 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 mix Domino’s fall and continue to believe that the $500,000 day rate threshold will be eclipsed fairly soon. We maintained a patient bidding discipline with our cold stacked drillship 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 span depending on their 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 of food, we believe that we have sufficient contract visibility now to call the first half of this year is the trough for our jackup fleet with tangible utilization improvement expected over the next 4 to 6 quarters. This is supported by recent and pending contract start-ups 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 the shipyard in the Netherlands scheduled to finish the work on its leg and tracking 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 jack-ups 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 all 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 Noble 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 injection at Project Greensand carried out by the jackup Noble resolved 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 jackup 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.
Richard Barker: 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 $0.45 and adjusted diluted EPS was $0.38. Cash flow from operations was $211 million. Capital expenditures were $107 million and free cash flow was GBP 104 million. As anticipated, revenue and 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 jackets 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 5 of the earnings presentation slides, our total backlog as of August 1 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 9 months in with the Maersk Drilling integration, which continues to progress extremely well. We continue to expect to have realized over 3/4 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 billion and $2.55 billion, adjusted EBITDA between $725 million and $825 million and capital expenditures of $325 million 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 derisked 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 Pecos Act, which is now scheduled to work through most of the third quarter before it goes off day rig for several months of contract prep and mobilization of 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 jack-up 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 by 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 $0.30 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 multiyear offshore up cycle, 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.
Robert Eifler: 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 have 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 Noble 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 drillships 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 newbuild orders by nimble entrepreneurs, followed by a combination of speculative and contracted newbuild 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, newbuilds are way off the radar because even without the aforementioned soft constraints, the economics are simply entirely out of the money. — hypothetical new build with comparable capabilities as the current Tier 1 seventh generation drillship would likely cost at least $850 million to build and require at least 3 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 million and $370 million per Tier 1 drillship within our fleet, consistent with the range that we observed 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 and cynics and valuation for a compelling investment thesis and the basis for a sustainable cash flow runway for Noble. Just to wrap up here. We’ve been through an extremely busy and dynamic past 2 years, moving as briskly but thoughtfully as possible to execute our consolidation and integration playbook to keep our customers front and a center to optimize the balance sheet and ultimately to deliver on our ambition to create a differentiated cash flow-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.
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Operator: Perfect. Thank you so much. [Operator’s Instructions] It looks like our first question comes from the line of Kurt Hallead.
Kurt Hallead: So kind of interested here on the thoughts. The — your commentary is kind of spot on with respect to leading-edge rates being kind of mid- to high 4s and the expectation to kind of reach above that $500,000 marker for a north of 500 for a semisubmersible in Australia. So 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 the dam breaking once the first rate goes above 500, the rest are going to follow pretty quickly.
Robert Eifler: 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 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 probably holds on given the outlook, the market probably holds on to those incremental steps up as they come.
Kurt Hallead: Okay. Appreciate that. So 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 2, 3. And obviously, we’ve had a couple of tenders out there for 5 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 I think I’m seeing in that contract durations are going to be more like 3 years on average?
Robert Eifler: Well, we excluded Brazil in our Guyana contracts in that 8- to 11-month analysis just to try to get a sense of maybe pulling out a few outliers I think we’re ways off from 3 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.
Kurt Hallead: Okay. And maybe if I might wrap up on use of cash. So you made a pretty substantial commitment in establishing this — the dividend. So when you think about your overall game plan or commitment on returning cash to shareholders, what kind of percentage of free cash flow would you be comfortable with committing as you go forward?
Richard Barker: Yes, 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% as it relates to more specificity than that. I’m not sure we’re not providing that at this stage. But obviously, our return of capital program is very much going to be a hybrid or balanced approach. And as our free cash flow continues to grow, and obviously, 2024 should be another step change for us as a company. I think you should expect that the amount of capital that we return to shareholders will obviously grow significantly as well.
Operator: Our next question comes from the line of Eddie Kim.
Eddie Kim: So just looking at your floater fleet, you have 5 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 5 loaders get recontracted here in the coming months, should we expect them to reprice higher around that same level, mid- to high 400s or could be state 1 or maybe even 2 of these rigs finally clear that $500,000 a day threshold that you mentioned?
Blake Denton: Yes. 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 very varied rates associated with those. All of them will be consistent with market for each of their asset classes. You’ve got the 7G that you referenced, those day rates. And then you’ve got the globe charters and the rigs, our DP plus more semis that are — they’re kind of just a step behind the 7G 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.
Eddie Kim: And just shifting gears to reactivations. One of your peers yesterday highlighted the attractive economics for one of the rigs they’re reactivating. So just in that context, do you think it’s likely that we’ll see the Meltem reactivated sometime this year and for the Suroco, 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 attractive contracts for the Meltem?
Robert Eifler: Yes, I can take that one. The Meltem will go to rig to work, excuse me, before the Suroco. We’re not marketing the Suroco right now. We are marketing the Meltem — to your question about timing, we’re not going to — 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 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.
Eddie Kim: Okay. Got it. And just the reactivation expense you quoted for the $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?
Robert Eifler: That’s a fully ready to work, everything, including expenses. So that includes shipyard costs, crews includes our own rig crews, that’s everything.
Operator: [Operator Instructions] And our next question comes from the line of Greg Lewis.
Greg Lewis: And I did just want to follow up on that last comment since you were getting pretty granular, Robert. Does that include mobilization to site?
Robert Eifler: No. The $125 million no, doesn’t include mobilization.
Greg Lewis: Thank you for the color around the capital allocation dividend. I was hoping realizing that it’s always a Board decision, 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. — gating Noble has the benefit of not really having a very strong balance sheet. So 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 2 or 3 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 when people start asking about sustainability.
Robert Eifler: Yes, it’s a great question, kind of right at the heart of the decision. Well, first of all, we’ve been spending time in coming up with the dividend and announcing it, we are all very aligned in making sure that it’s sustainable. So you’re right. we look at through cycle rates. — and we can consider what happens post a dayrate 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 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 of obviously being dividend and buybacks.
Greg Lewis: And then just wanted to talk a little bit about the North Sea market. Obviously, there’s some open days here, but really, I guess, were contractors. I guess a 2-part question. One is, should we see any white space on kind of the North Sea fleet get filled up in the back half of this year? Or is it really looking ahead to 24% and that — I imagine the answer will include that. Any kind of view on the recent news by the U.K. government about — it seems like they’re trying — it seems like they’re beyond the flat tax that they’re changing and the — it seems like more recently they’re talking to trying to incentivize some more activity out of the U.K. just around the whole energy security team that everybody at this point is pretty familiar with.
Blake Denton: Yes, 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 in 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 jack-ups into 2024.
Robert Eifler: And I’d add to that, too. I think we’re — sorry, but just quickly, I think I agree completely. And I think, too, it’s a bit of a funny period of time right now where utilization in the North Sea and Rest of World is out of balance. And so I think that’s just a time and a place. I think that, that 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 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.
Greg Lewis: Great. interests you both mentioned the CCS dynamic, 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 jackup demand coming from in realizing CCS is more of a, call it, medium, longer-term probably demand driver. But would that just — any — what would those rigs kind of be doing as they’re working on that. I don’t think they’re drilling new wells.
Robert Eifler: 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 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 we’re not calling for that or anything. But it will produce some level of utilization through time. We drilled the carbon capture well last year, as I mentioned. It’s medium and long term, as you say, but it is real, and they’re drilling — we’ve drilled carbon capture in Australia. — 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 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 in money that’s moving towards some bigger projects. But again, that’s medium and long term, as you say.
Operator: Our next question comes from the line of David Smith.
David Smith: So one first, 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 steps that I’ve made question…
Robert Eifler: I very much appreciate that. Hopefully, there’s a wide range of new investors that heard that.
David Smith: The question I had relates to some of the requirements we’ve seen since late June for 5-year plus terms for drillships from a couple of — on the one hand, I’m sure they’re looking for a discount to leading-edge rates, but I can’t think that’s the main driver for the higher duration. I don’t expect they have very defined work programs in years 4 and 5 or beyond. So it felt to me like the extended terms are really about securing availability. They’re maybe getting nervous then the dwindling of the incremental supply. But I’m curious how you think about the emergence of requirements for 5-year plus terms from IOCs, maybe the implications of that because I think the equity market might not fully appreciate it.
Robert Eifler: It’s a great point, and you’ll fill in if I miss anything here. But I think after years and years of every deepwater 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 the evidence exactly. Now there are a few programs that are 5 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 where certain E&P companies see the cycle going and how they see longevity, which, of course, we and our competition have been screaming from the mountain tops here for a while.
David Smith: Very, very much appreciated. And a quick follow-up, if I may, with some of the requirements emerge and 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 work, the chance to reduce their historical rate discount to Tier 1 covigilship?
Robert Eifler: Yes. For sure. The globe charters 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. I know it would take any other rig, I think 90 days, something like that. So there’s a massive advantage there. So any time you hear Noble say Black Sea we’re probably talking about the load charters. And so — but we’re hopeful that a well or 2 could play out that would include the globe charters there. And yes, we would anticipate that, that would close pricing gaps that we would otherwise see.
Operator: All right. Perfect. And those are all the questions in the keys. So I’d like to turn it back over to the team at Noble Corporation to close things out.
Robert Eifler: Thank you, everyone, for your participation and interest in the call today, and we look forward to speaking with you again next quarter. Have a good day.