Noble Corporation (NYSE:NE) Q4 2023 Earnings Call Transcript

Noble Corporation (NYSE:NE) Q4 2023 Earnings Call Transcript February 23, 2024

Noble Corporation isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Thanks for standing by, and welcome to the Noble Corporation Q4 Earnings Call. I would now like to welcome Ian Macpherson, Vice President of Investor Relations to begin the call. Ian, over to you.

Ian Macpherson: Thank you, Operator, and welcome everyone to Noble Corporation’s fourth 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 an associated reconciliation in our earnings report issued yesterday and filed with the SEC. With that, I’ll now turn the call 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 results and commercial activity, and then provide some market outlook commentary before passing the call to Richard to discuss the financials. After our prepared remarks, we look forward to taking your questions. The team delivered another solid operational quarter with Q4 adjusted EBITDA of $201 million bringing full year adjusted EBITDA to the upper end of the guidance range and Q4 free cash flow of $165 million excluding asset sale proceeds, which also punctuated a good free cash flow contribution for the full year. These fourth quarter results were achieved despite later than expected contract commencements for both the Globetrotter I and the Intrepid due to delays related to weather and permitting issues.

So otherwise, we saw very strong uptime in cost performance across the fleet. The heavy lifting associated with our merger integration is now substantially behind us, and our offshore teams continue to execute at a high level to perform safe and efficient drilling operations for our customers around the world. Our Board declared a $0.40 dividend for the first quarter of 2024 consistent with last quarter, and we also repurchased $15 million of shares in Q4. This brings total capital return to shareholders since the Q4 2022 merger close through the first quarter of 2024 to $337 million. As previously stated, you can expect Noble to continue to prioritize the return of the substantial majority of free cash flow to shareholders going forward between dividends and buybacks, which we recognize as a top priority for investors and one of the key pillars of our first choice offshore ambition.

Our outlook for our business over the next several years continues to look very promising, especially on the deepwater side, notwithstanding some lingering white space confronting a handful of rigs over the near-term. Despite a recent short-term downtick in the number of deepwater contract awards industry-wide during the fourth quarter, we have been pleased to announce several contract fixtures since late December that have meaningfully augmented our 2024 backlog. As I list these here in a moment, I’ll just say that we consider all of these recent fixtures to represent current market pricing, although, we are only disclosing day rates where customer approvals allow us to do so. First, the Noble Discoverer was awarded a 400-day contract with Petrobras in Colombia that’s set to commence in Q2 2024 following the rig’s 10-year survey.

This contract includes a price option for an additional 390 days. Next, the Noble Voyager was awarded a one well contract plus one option well with Petronas in Suriname that commenced earlier this month with an estimated firm duration of 130 days plus a 70-day option. So the Voyager is now firmly booked into June with the option period extending into August of this year. Next, the Noble Valiant received a six-month extension from LLOG in the U.S. Gulf of Mexico, extending that engagement from July into January next year. This day rate remains at $470,000, excluding additional fees for the use of managed pressure drilling. Next, the Noble Gerry de Souza received a nine-month extension with TotalEnergies in Nigeria continuing the program out to November 2024.

Last within the floater fleet, both of the Globetrotter drillships ongoing contracts with Shell in the Gulf of Mexico have been extended into early May Then, on the jackup side, the Noble Intrepid had an option exercised by Harbour Energy for a well intervention program in the UK North Sea, which commenced in January at a day rate of $120,000. This job started a few weeks later than planned due to challenging weather conditions. Also, the Noble Innovator received a one well extension estimated 90-day duration from BP at a day rate of $140,000, scheduled to commence in September 2024. BP’s subsequent priced options on the Innovator have been restructured into smaller components, which, if fully exercised would extend into Q2 2026. And finally, the Noble Resolute has recently received an additional 60 days of Petrogas at $145,000 per day, scheduled to begin in March 2025 in direct continuation of the rig’s existing backlog.

Collectively, these recent fixtures contribute an additional firm backlog value of $515 million, excluding mobilization, MPD revenue, and option periods. Our total backlog currently stands at $4.6 billion, essentially flat versus last quarter. However, excluding the six rigs we have operating under long-term contracts in Guyana and Norway, which don’t typically replenish backlog frequently, the remaining backlog across our other 23 marketed rigs actually increased by 10% over the past three months. Richard will go into the guidance in a few minutes, but as a quick preface, 92% of our mid-point 2024 EBITDA expectation is supported by firm backlog currently. As reflected on our new fleet status sheet, the remaining 2024 white space for Noble’s floaters sits mostly now with the two Globetrotter drillships and the 6th gen semi Noble Developer.

These three units are being marketed for both spot work and longer-term opportunities, although practically speaking, the near-term opportunity set is more focused around short-term spot work. One additional update that I’d like to callout on the fleet status is the revised timing of the estimated contract commencement for the Noble Faye Kozack in Brazil, which has flipped from a prior estimate of March to a current estimate of July 1. The original driver of this delay was the rig’s preceding contract with LLOG in the Gulf of Mexico, running about 30 days longer than initially expected, which impacted our planning and preparation timeline for the Petrobras work. Subsequently, the shipyard program for the Kozack SPS in contract preparation is unfortunately taking longer than planned, primarily due to protracted delivery lead times from some critical equipment shipments.

These delays have been exacerbated by the disruption of global shipping channels, but we’re doing everything we can to complete this major project and get to work with Petrobras by mid-year. Now, turning to the broader industry outlook, I’d like to go through our semi-annual review of the global deepwater market supply and demand picture. Overall, we continue to see very encouraging indicators for continued steady growth in the offshore drilling markets. Offshore upstream CapEx is expected to be up again by a low to mid-double-digit percentage this year, and I would mention here that while Noble’s 2024 revenue outlook is somewhat more muted than this range, this is due to a heavy slate of scheduled maintenance and contract preparation related to downtime across our fleet, which is more heavily weighted for the first half of the year, whereas we expect to be comping much better on an annual top-line growth rate basis in the second half of this year.

Additionally, the various other leading indicators from subsea tree orders to offshore FIDs and international license bid rounds are all flashing green for the 2024 to 2026 visible horizon. Zooming in on the UDW market, 2023 average contracted demand of 91 rigs was up nine rigs, or 11% over the 2022 average, with current contracted demand of 92 rigs representing 95% effective utilization of the immediately marketable fleet. Following 15 drillship reactivations since 2022 that have been completed or are still underway, there now remain 7 to 10 viable high spec 7th generation drillships in sideline capacity, including cold stacks and shipyard assets. These sideline rigs have capital requirements of $100 million to over $300 million per rig, with minimum one year reactivation lead times to deploy.

We continue to expect the majority of these, including our drillship the Meltem, to be pulled into service over the next couple of years based on expected demand levels, at which point high end UDW capacity would be fully exhausted. Perhaps the most striking statistics that we observe today relate to the sharp inflection in open demand for floaters, the current tally of public tenders and pretenders represents 108 rig years of open floater demand. This good year is up by over 50% compared to last year and is also at a decade high by a wide margin. Additionally, the average duration of each job opportunity within this 108 rig years of open demand is now 18 months, which is up 40% versus a year ago and 70% higher than the prior five-year average.

These statistics on open demand, by the way, have been updated since taking the total 10-year drillship job off the Board. This represents an important step change in longer-term visibility for our business. I would also mention that measurable open demand of public tenders is not by any means a complete picture. In Noble’s case specifically, in fact, the vast majority of floater backlog that we have booked over the past several years has come via direct awards and extensions, rather than from public tenders that these aforementioned stats describe. Looking out over the next one to two years, we see latent UDW demand growth of 10 or more rigs, again similar to the number of remaining rigs in sideline supply. However, between here and there, we do expect the combination of supply constraints and imperfect alignment between rig availabilities and demand requirements to result in some continued utilization inefficiencies over the near-term.

Overall, this results in a generally firm but balanced market until the sideline capacity is substantially absorbed as opposed to a scarcity situation. But certainly with opportunities for situational pricing increases along the way, which is similar to the dynamic that we’ve seen in recent months. From a geographic perspective, the fulcrum of demand strength through UDW rigs continues to be South America and Africa primarily. Starting in South America, there are currently 29 UDW floaters under contract in Brazil with a further six units contracted to startup over the course of 2024. Petrobras currently has open demand for five rigs on 2.5 to 3-year contracts with 2025 start dates, although these five tenders appear likely to be more renewals against expiring contracts than incremental units.

Guyana remains a core market for Noble, where activity remains at six UDW rigs, including four of our drillships, of course. We have not experienced any change or interruption in operating conditions in Guyana over the past few months following Venezuela’s territorial challenge over the Esequibo region, nor do we anticipate any likely disruption. In the background, it has been encouraging to see a successful bid round in Guyana recently with offers on 8 of 14 blocks and contracts expected to be finalized and announced soon, which could be supportive of additional activity outside of the Stabroek field in the years ahead. Suriname has vacillated between zero and three deepwater rigs in recent years and has recently increased back up to one rig with the Noble Voyager startup with Petronas.

Exploration activity in both the shallow and deepwater could support modest incremental demand in Suriname throughout 2024 and 2025. While FID for the country’s first major field development represents an additional demand for two floaters on multi-year contracts expected to commence in 2026. Colombia will similarly soon be back up from zero to one deepwater rig with the commencement next quarter of Noble Discoverer’s 400-day contract. And there’s a handful of additional potential exploration wells with other operators that could materialize for an additional unit of demand in Colombia over the next one to two years. Moving to West Africa, utilization is 100% on 18 regionally marketed floaters, including seven in Angola, four in Namibia, and three in Nigeria.

West Africa is a region with particularly strong demand visibility, with current tenders and pretenders representing 20 rig years of demand, including four unique multi-year rig requirements with late 2024 through 2025 targeted start dates. All of this again is net of the total 10-year job that has just recently come off the Board. Overall, we believe West Africa could grow to 21 to 22 floaters over the next year. This does not factor in any potential rig ads in Mozambique, which could represent two to three additional units of multi-year demand from 2025 and 2026. In the Gulf of Mexico, including the U.S. and Mexico, deepwater demand has ranged between 22 to 25 rigs over the past couple of years and currently stands at 24 with three idle marketed rigs resulting in 89% utilization.

Near-term demand is expected to remain approximately flat with some short-term variability around contract rollovers. So this is where we are seeing somewhat more white space, particularly among a few of the 6G units. We’re optimistic about some opportunities to add additional work this year for all of our Gulf of Mexico rigs. However, the Globetrotter drillships and the Developer are likely to experience lower utilization than the rest of our floaters. Outside the Golden Triangle, the Mediterranean and Black Sea are showing a positive uptick in activity with 10 contracted floaters currently up from six throughout the first half of 2023, and regional utilization at 100%. With continuing demand strength from Egypt, the Black Sea, and Libya, activity in this region is expected to range between 10 to 12 floaters throughout 2024 and 2025.

India has three UDW drillships currently, although two of these are wrapping up contracts soon and are expected to leave the region. However, despite India shedding a couple of rigs in the near-term, the government’s recently announced aggressive five-year investment plan of $67 billion to develop its natural gas resources appears more likely than not to support a revival in floater activity over the next few years. And then, finally, the Asia-Pac and Australia region has four units of demand, 100% utilization, and a healthy number of short, medium and long-term programs on the horizon for late 2024 through 2026, which suggest a potential upward bias to the region. So tying all this together, we remain quite optimistic about the upward trajectory of the deepwater market.

Demand growth won’t be linear, it never is, and supply constraint is a governing factor as well. But overall, this is a market that should see continued upward pressure in day rates as demand grinds higher and as the last several units of high end sideline capacity get absorbed. There will absolutely continue to be bifurcated pricing between the top end existing rigs in the market versus the rigs that are being reactivated from sideline into multi-year contracts. That’s well established and economically predictable. But overall, the trend for both day rates and contract duration is upwards. Now on to jackups. Although, this is still a smaller percentage of our earnings mix, the picture for our non-Norway harsh jackups continues to quietly improve, especially from mid-2024 on, once the Regina Allen and Resilient get back to work.

In fact, the steady improvement in market balances and day rates in the North Sea over the past couple of years has been quite a positive and still developing story. Demand in the non-Norway North Sea has ranged between 18 and 22 jackups over the past two years and currently stands at 22 with three idle rigs resulting in utilization of 88%. Two of these three idle units are ours, the Noble Highlander and Noble Interceptor both of which have limited 2024 work visibility at this time. But with the overall market firming up from the demand side drilling day rates in the North Sea have improved to the $130,000 to $150,000 per day range, up from $100,000 to $135,000 per day a year ago and as low as $70,000 to $90,000 a day a few years ago. We have decent visibility towards signing up additional backlog at healthy rates this year and looking out past 2024, there’s interesting demand optionality from additional CCS activity, which has just begun in 2023 with our involvement in Project Greensand.

The Norway jackup market remains subdued for 2024 with eight rigs of demand compared to its historically normalized demand of 11 to 12 jackups. The Noble Integrator and Noble Invincible continue to perform extremely well for Aker BP. We do not envision redeploying a third CJ70 rig into Norway before 2025, although customer dialogue for next year is more constructive than it has been in a while. So we will see how that develops, but we’ll certainly be ready and well-positioned with the right assets and team when the demand improvement does materialize. So that’s it for the market overview. Now, I’d like to turn it to Richard to discuss 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 fourth quarter and full year 2023 results before touching on our outlook for 2024. Contract drilling services revenue for the fourth quarter totaled $609 million, down from $671 million in the third quarter. Adjusted EBITDA was $201 million in Q4, down from $283 million in Q3. Cash flow from operations was $287 million, capital expenditures were $141 million, and free cash flow was $165 million. Our full year 2023 results came in towards the high end of our guidance range with full year revenue of $2.6 billion and adjusted EBITDA of $810 million. Turning back to the fourth quarter, as anticipated, revenue and adjusted EBITDA decreased from third quarter levels due primarily to lower utilization of our floater fleet, the market utilization decreased to 75% in the fourth quarter, down from 92% in the third quarter.

Scheduled contract gaps for the Noble Faye Kozack and the Noble Voyager, the delayed start for the Noble Globetrotter I and commercial white space for the Noble Developer were primary contributors to this sequential downtick, which more than offset an increase in average floated day rates from $404,000 per day in Q3 up to $437,000 per day in Q4. Our 13 marketed jackups were utilized 51% in the fourth quarter, consistent with the third quarter, with the average day rate improving to $148,000 in the fourth quarter, up from $141,000 per day in the third quarter. During the fourth quarter, we received cash proceeds of $21 million in the form of a deposit for the sale of the Noble Explorer, which essentially represents the net proceeds to Noble from the sale.

We expect to close the sale later in Q1 or Q2 of this year. As summarized on Page 5 of the earnings presentation slides, our total backlog as of February 23 stands at $4.6 billion. Current backlog includes approximately $1.94 billion that is scheduled for revenue conversion during 2024. As a reminder, our backlog excludes reimbursable revenue as well as revenue from ancillary services. We are firmly into the final stages of our integration. We currently have realized nearly $115 million of run rate synergies and are raising a total synergy target from $125 million to $150 million. Both the quantum and the pace of synergy realization have exceeded expectations. Referring to Page 9 of the earnings slide, we are providing full year 2024 guidance as follows.

Total revenue within a range of $2.55 billion to $2.7 billion, which includes a little over $100 million in other revenues such as reimbursables and contract intangibles amortization; adjusted EBITDA between $925 million and $1.025 billion; and capital additions, which excludes reimbursements of between $400 million and $440 million. The mid-point of this revenue range is currently 92%, supported by Q1 to-date revenues plus firm backlog for the remainder of the year, excluding options. We currently estimate that a little over 60% of full year adjusted EBITDA will be weighted to the second half of this year. Our jackup contribution is expected to increase in 2024, going from approximately 10% of our gross margin in 2023 to approximately 15% of our gross margin in 2024.

Certain key contract startups are expected to drive an increase in EBITDA starting in the third quarter, notably the Noble Faye Kozack in Brazil, the Noble Discoverer in Colombia and the Noble Regina Allen in Argentina. A key variable to our fourth quarter EBITDA exit rate will be the contribution from the three 6G rigs that are currently showing white space massive status report. We currently have active conversations behind each of these available 6G rigs, and shoring up work for these rigs would translate to an annualized adjusted EBITDA exit rate for 2024 of between $1.3 billion and $1.4 billion, assuming our other model assumptions hold. As a reminder, our 2024 CapEx budget reflects both a peak year for 10 USD assets and major projects across our fleet, as well as the contract preparation expenditures for the Noble Faye Kozack and Noble Discoverer.

The scheduling of this year’s major projects currently indicates that just over half of our CapEx will be raised to the first half of the year. Some other elements for 2024 to consider are as follows. We expect cash taxes in the range of 10% to 12% of adjusted EBITDA and costs to achieve the final synergies related to the Maersk transaction are expected to taper off to approximately $13 million in 2024. Additionally, our guidance reflects mid-single-digit percentage inflation rates in 2024 on average across our total cost structure, including OpEx and CapEx. And then finally, we would expect some measure of net working capital build in 2024, driven by both top-line growth and a reversal of some favorable net working capital movements experienced in the fourth quarter.

We do expect to see an increase in free cash flow for full year 2024 versus 2023. Due to the aforementioned factors, we expect to be modestly free cash flow positive in the first half of 2024 prior to any capital return to shareholders, with nearly all of the free cash flow for the year weighted to the second half. As we have said before, we would look to return the substantial majority of our free cash flow to shareholders. With that, I’ll pass the call back to Robert for closing remarks.

Robert Eifler: Thank you, Richard. I’d just like to wrap up here with a tremendous thank you to Noble employees worldwide who have worked so hard to get the company to the enviable position in which we find ourselves today. We had a sizable but ultimately an overwhelmingly successful integration effort last year. Not only have we exceeded our synergy targets both in terms of pace and size, but also we have done so while continuing to deliver outstanding and safe operations for our customers and strong financial results for investors. The next time we talk to you, the book will be closed on integration. Finally, I will reiterate that the multi-year outlook for our business remains highly encouraging, especially considering the recent inflection in open floater demand visibility for 2025 to 2026, as well as the continuing strong momentum in deepwater FIDs, which underpin longer-term drilling demand.

And these supportive demand signals are juxtaposed against a diminishing pool of spare rig capacity. For Noble, the shape of the year ahead is reminiscent of the past couple of years as we expect to ramp into a meaningful increase in EBITDA from the first half to the second half of this year based on the sequencing of contracts. As this anticipated ramp in EBITDA and free cash flow materializes, you can look for Noble to continue to demonstrate industry leadership with growing capital returns to shareholders, which we see as core to our value proposition for investors. With that, operator, we’re ready now to open up the call for Q&A.

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Q&A Session

Operator: The floor is now open for your questions. [Operator Instructions]. Our first question comes from the line of Greg Lewis with BTIG. Please go ahead.

Greg Lewis: Yes. Thank you, and good morning, everybody, and thanks for taking my question. Robert, I mean, clearly there’s been fits and starts in this market. As I look at the fleet, obviously there’s a lot of options attached to handful of these rigs. As we think about some of those options, any kind of color you can give us in terms of when those options, when do we find out if those options will be exercised, and then also any kind of rough guidance on how we should be thinking about at least the price options, what type of step-up, if any, there is on some of those options.

Robert Eifler: Yes, sure. So the options are tied to different things, I think, in the contracts. But I think generally speaking, we try to provide something like 90 days before the end of a contract when we’ll understand option pricing. Ideally, we’d like more than that. And sometimes we’re able to get it. Sometimes, they’re tied to reaching geospatial targets, sometimes they’re tied to end of well and sometimes, they’re just tied to timing. So kind of hard to give an exact answer. We have — and of course, we are giving fewer and fewer price options, and we have a couple, I think, probably the highest profile. You should think about maintaining kind of similar market price levels in the option period, although there’s a couple that have a step-up as well.

Greg Lewis: Okay. Great. And then just as I think about the North Sea market, we’re kind of in like a transition period. On the floater side, we’ve seen some rigs actually exit that market, which looks to be tightening that market, realizing that CJ70s are purpose built, really for the North Sea harsh environment and super spec rigs, maybe there’s not a lot of opportunities for those elsewhere. That being said, are we starting to see any opportunities for potential rigs, super spec rigs, that could be outside the North Sea that could start to tighten that market?

Robert Eifler: Well, there is — there are two rigs that are leaving the North Sea, and I think it’s — the question kind of has two answers, whether you’re talking about Norway or non-Norway, we’ve seen — excuse me, we’ve seen Norway leave — Norway rigs leave and go to non-Norway North Sea and back and forth. So that’s been a trend a little bit. We have not seen Norway rigs leave the North Sea and go elsewhere in the world. And I think that’s a less likely scenario for a couple of different reasons. And then in the non-Norway rest of the North Sea, there are a couple of rigs that are leaving this year, and I do think that those rigs are likely to leave or come back to the North Sea to balance markets with rest of world.

Operator: Our next question comes from the line of Eddie Kim with Barclays. Please go ahead.

Eddie Kim: Hi, good morning. Just wanted to ask about what’s embedded in your full year guide as it relates to contracting for the Developer and the two Globetrotter’s this year, which I assume is the biggest kind of link factor that gets you to the high end or low end of your guide, depending on what happens there. But does the mid-point of your guide, so it’s $975 million in EBITDA, assume maybe 40% utilization across those three rigs this year, or how should we think about that?

Robert Eifler: Yes, Eddie, it’s a very good question. I think the way to think about it is obviously we expect real white space for each of those rigs this year, but we do have active dialogue behind each of them. So I think you should think about our mid-point of our guidance, assuming that there is incremental work for each of those rigs here in 2024. I think that as you think about our earnings profile through 2024 and into next year, obviously with contribution from those rigs, we’ll be looking at an exit EBITDA run rate of, call it $1.3 billion to $1.4 billion at the EBITDA.

Eddie Kim: Okay. Okay, got it. Thank you. My follow-up is just on the Saudi announcement several weeks ago you only have one jackup in the Middle East coming to Qatar, so exposure is very limited. But still wanted to get your thoughts on how you see kind of the Middle East jackup market playing out in 2025 and 2026. If Saudi chooses not to renew some of their jackups, could we see rig moving out of Saudi into other countries like Qatar or the UAE or even outside the Middle East region entirely? Just would be great to get some thoughts there.

Robert Eifler: Sure. And again, we are a bit of an outsider right now on the whole situation, but my assumption is that their rig count is going to stay relatively flat. I think probably some anticipated multi-rig tenders that were potentially going to come out. People throw around 40-rig tender type quantum’s are, of course, not going to happen at this point seemingly. Rigs can move out and will move around the region as needed. But remember, also there is a high cost of entry back into Saudi Arabia because of some of the contract requirements. And so it’s not a decision, I would think to be taken lightly to move a rig out and — because you don’t know when you might get it back. And then ultimately someone has to pay for that reentry cost for the contract upgrades unless you’re lucky enough to get the exact same rig back. So rigs are mobile. They’re always going to move around regionally to fill demand. But I think our best guess is that things stay relatively flat.

Operator: Our next question comes from the line of Fredrik Stene with Clarksons Securities. Please go ahead.

Fredrik Stene: Hey, guys, hopefully you can hear me all right, and thanks for the comprehensive color both on the market and outlook for 2024. I wanted to touch a bit upon your fleet and one of your competitors that have reported already. My impression is that for stack assets, there are now more and more opportunities that could make reactivations more sensible than before. So my first question relates to just that. How are you now thinking about your two stacked drillships? Are you building them more actively? Are you only looking at the Meltem for now, or potentially both? And second, you said that the next time we speak, the Maersk acquisition is going to be — the books are going to be closed on that one. So are you planning any more major M&A steps when that’s done? Thanks.

Robert Eifler: Yes, sure. Thanks, Fredrik. First of all, on the drillships, Meltem will be first. That’s the one that we’ve selectively marketed. And I would not say that we’ve really changed our approach in marketing that rig. We’re still looking for a full return on the reactivation costs, which are around $125 million and take a year, maybe slightly longer to carryout. So that continues to be a smaller subset of opportunities, and I think we’ll continue to market into those opportunities. If you just look at the publicly available information through Petrobras or whatever, I think so far we’ve been less willing to provide substantial discounts off of market for that rig. And I don’t see that we’re necessarily going to change our approach of selectively marketing it into opportunities that fit the criteria for reactivation.

And we won’t make — we would not market this Roko until the Meltem has found a job. So we’ll just have to see, I mean it’s a little bit hard to predict when that right job emerges for the Meltem, but we do anticipate that rig going back into the marketplace at some point. On your other question, we’ve said from the very beginning of the announcement of the merger with Maersk Drilling that this was going to be a transformational merger for both companies. And I think that that has absolutely proven out to be the case. We’re extremely pleased with where we sit today. I think our 2023 results, in the midst of some of really the bulk of the integration work, really speak to the combined organization and everyone’s willingness to lean into this and create a sum that is greater than the parts.

So we just couldn’t be more pleased. We have also said that that was going to be our transformational merger and from here, we will be selective. I think it’s obvious that the combined platform could be a candidate for additional M&A. But we are going to be picky, always with a mind to our customers and our investors in what we look at.

Fredrik Stene: Thank you. That’s very helpful. Just a follow-up on the coal stacks and the reactivation thinking. I think you said in your prepared remarks over that for now at least, there’s some supply constraints or some mismatches in terms of where rigs are and where work is. That could make this a relatively balanced market, slightly trending upwards until the sideline capacity is absorbed. So both you and your peers are projecting, I think double-digit number of incremental rigs needed over the next few years. So if that market is going to be balanced and you need that kind of capacity how many — do you have any idea of how many rigs can be brought back from the sideline per year just to see is there a chance that you will have demand outpacing the incremental supply that can be brought back just because of supply constraints, long live items, et cetera. That seems to be delayed or be more difficult to procure at this point than before.

Robert Eifler: Yes, it’s a good question. I mean we’re going to see plus, I think six this year, five or six this year. And we’ve seen plus 15, I believe from the very beginning of this upturn. And so I think the numbers have come through in that kind of five, six, seven at the most per year range, if I’m remembering correctly, and that seems sustainable. It also kind of matches where we see incremental demand, excuse me, coming. I would say a lot of it depends on the specific contracts. There are a couple of more reactivations that are going to occur or contract startups from reactivations that are going to occur in 2024 than we were predicting in early 2023. And that’s partly because some of the tenders extended their start date to allow time for reactivation.

So to the extent that the programs that are out there that are two plus years that the operators of those programs decide to actively include reactivated rigs, a timeline that supports reactivated rigs, I would anticipate as we said in the script that many of the 7 to 10 additional rigs are set up to take discounts to current market. I think this trend probably continues until most of them, if not all of them, but most of them are back into the marketplace. So I could easily see, and that’s kind of why we’ve called for a balanced market over the next year or so. I could easily see the bulk of those 7 to 10 getting announced through, say, mid next year, I mean, just picking a date out of thin air. But it’s not at all impossible that we see a majority of those reactivations getting announced.

The one thing I would say is we’ve been a little bit flat on as an industry on UDW rates over the last six months or so, but the rates have also kind of picked upward even as reactivations have been announced and occurring. And I think that the flatness over the last six months is not necessarily attributable to all of these reactivations. I think it’s a confluence of factors. And all that’s to say that we still do think that there is likely to be rate appreciation through that same period, maybe not at the same slope that we saw early on in this upturn, but we do think that there will be continued rate appreciation.

Fredrik Stene: Thank you. That’s a very comprehensive and very helpful. That’s it for me. Thank you very much and have a good day.

Robert Eifler: Thank you.

Operator: Our next question comes from the line of Kurt Hallead with Benchmark. Please go ahead.

Kurt Hallead: I just wanted to maybe extend the conversation of your prior answer there, right? So we’ve heard quite a bit that there’s increasing duration, as you referenced and others have referenced, and that longer duration contract period has, I guess, also translated in terms of a longer negotiation period to finalize those contracts. So kind of taking what you said about pricing, taking what’s going on with respect to longer negotiation periods, I’m just kind of curious how much of that longer negotiation period is related to a bid app spread on pricing.

Robert Eifler: Oh, gosh. Well, actually, I think what’s happened here is in 2024, you had the dynamic I just mentioned where some programs start dates were pushed back to allow for some reactivations, and we actually thought some of those programs were going to go to existing supply. And then at the same time, I think several operators have recognized the discount in the market for longer-term contracts and decided to try to pull together their various different programs into grouped contracts, so that they can go out for more term. And so a few wells that may otherwise have been drilled in 2024, perhaps got pushed to 2025 or later in order to group here for some term. And that’s created a little bit of this white space in 2024. And also the perceived kind of longer negotiation period is a piece of that as well. I don’t know that it’s a significant bid ask as much as the dynamics that I’ve just described.

Kurt Hallead: That’s great. That’s great color. I appreciate that. My follow-up is on the synergies. I’m kind of curious where those synergies are going to land. That can be mostly OpEx or GA or some — or G&A or some combination.

Richard Barker: Yes, Kurt, it’s going to be both candidly, I’d say from a G&A perspective, most of that was probably was realized in 2023. I think going forward; we’ve obviously increased the target from $125 million to $150 million. I think you should think about those incremental synergies sitting more in OpEx.

Kurt Hallead: Okay. That’s great. And if I squeeze one more in, you mentioned supply chain bottlenecks. So, Robert, when do you see those supply chain bottlenecks easing or not getting any worse.

Robert Eifler: Well, I mean I think the same, I mentioned the numbers of reactivations that we’re going through on top of that last year and this year for the industry are peak SPS years. And it starts to slow down a little bit next year and then more substantially in 2026. So I would anticipate that we’re probably at peak bottleneck on the equipment side but there’s strikes in Europe and obviously shipping issues. And so there’s some complicating factors as well, I think that are affecting 2024 and our specific situation right now on the FECO’s [ph] Act that are out with just normal manufacturing supply chain issues.

Operator: Our next question comes from the line of David Smith with Pickering Energy Partners. Please go ahead.

David Smith: I know a decent chunk of Norwegian semi work in the past has taken place in depth that a CJ70 could address. And with all of the semis that have left Norway, I wanted to ask if you’re seeing an operator interest for programs in the next year or two that might otherwise want a semi, but will take a jackup because that’s what’s available.

Robert Eifler: Yes. Yes, there is a good question, David. There — I would characterize it as there is absolutely interest. There is no tangible demand right now. We have done a lot of work on using a CJ70 over subsea template, and we are hoping to get showcased some of that at some point soon. But it’s a little bit too early to claim success in some of the work that we’ve done right now. But for sure, we have conversations all throughout the country and there is interest in exploring that going forward. One thing I will say is that the floater tight — the harsh floater tightness has been known for quite some time. And so I think there’s been also a push by operators there not — well, to fill any white space they can with the rigs they have under contract, so as not to lose a rig to use.

So to the extent that perhaps we had an opportunity to go showcase the CJ70 in some of this transition zone, we probably missed out on a couple of those because operators wanted to make sure they didn’t lose access to preferred harsh floaters. So it’s a continuing, although kind of yet to launch story, I think for the CJ70s, but we remain hopeful.

David Smith: I appreciate that color. And the follow-up, I guess there’s been some media reports that the operator using the Noble Venture of Ghana might want to release that early. Just wanted to ask if you could tell us anything about what kind of termination fee that contract might have and whether an early release is contemplated in the guidance provided.

Robert Eifler: Sure. The customer there announced a break in their drilling plans, which is what you’re referring to. For us, it is, of course, kind of a classic story of the double edged nature of a top performing contractor because we’ve drilled ourselves out of a job, so to speak. But to be clear, despite my last statement, there’s been no contract termination announcement, of course, we would put that out. And so what I would say is it’s too early, really to give definitive answer to what the customer plans to do there. They have announced a drilling break. I can give the color that that contract was signed in a substantially lesser market than we find ourselves today. So the termination clause kind of follows with commercials there.

But on the flip side of it, the rig has performed tremendously well, which is why we kind of finished some of the plans up early. And there is — the customer, we understand does have more work. And it’s a contract signed at a different period of time. So we’ll have to really kind of wait to see what the customer decides to do there. If in fact, we find ourselves marketing that rig, the good news is that the revenue makeup would happen relatively quickly because the market is substantially higher today than the rates on that rig under firm contract, so.

Operator: Our final question comes from the line of Noel Parks with Tuohy Brothers. Go ahead, please.

Noel Parks: Hi, good morning. Just a couple of quick ones. I apologize if you touched on these already, but it was encouraging to hear about the expected improvement in gross margins on jackups. I think you said to 15% from about 10%. So just interested to hear what you think about that, where that stands as a trend going forward.

Richard Barker: Sure. Yes. In 2023, obviously, that was tough year for us, for the jackup contribution, if you will to earnings. So obviously, as we see improvements in the North Sea more broadly, that’s why the 10% increasing to 15%. I think that we’re obviously not providing anything around 2025 at this stage, but I think we would expect to see that contribution continue to increase from 15% upwards once we get into 2025.

Noel Parks: Great. And I thought there was a mention earlier in the call that that sort of a light was flashing green on all sorts of fronts, including some optimism on the supply chain. I think maybe trees were mentioned, but I think in a recent question, there was another reference to supply chain. So I just wondered if you could maybe just characterize what you’re seeing on that side. Is that lessening is a factor in your planning or still a bit of a challenge?

Robert Eifler: Sure. Yes. So the reference to supply chain in relation to the Faye Kozack and some of our other SPSs was around some delays we’ve seen, really just in the Faye Kozack, we’ve seen around procuring some of the long lead items, which is delaying our start ultimately in Brazil. And that’s a function of shipping delays and strikes and everything I’ve mentioned, as well as the number of SPSs happening globally across the jackup and deepwater fleet right now. That is separate from my reference in the script to subsea trees, which we consider one of the leading indicators, particularly well for deep — for deepwater work, where a customer typically orders trees, which is a long lead item for drilling and producing wells before they go into development projects.

So if you look at tree orders, typically you can anticipate that one, perhaps maybe closer to two years after that demand for our services would follow. And so we’re seeing the green, flashing green is around leading indicators. On the procurement side, the only one we mentioned was trees, but then also FIDs and then just straight up OpEx budgets for our customers, excuse me, CapEx budgets for our customers are all up and are all positive and supportive of a multi-year upturn here.

Operator: I would now like to turn the call over to Ian Macpherson for closing remarks.

Ian Macpherson: Thank you, everyone, for joining us today. And we look forward to speaking with you again next quarter. Have a good day.

Operator: This concludes today’s call. You may now disconnect.