Noble Corporation

followed by the number 1 on your telephone keypad. If you would like to withdraw your question, press star 1 a second time. Thank you. And I would now like to turn the conference over to Ian McPherson, Vice President of Investor Relations. You may begin.

Thank you, Operator, and welcome everyone to Noble Corporation's first quarter 2024 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 the obligation to update these statements. Also note that 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 with the SEC. Now I'll turn the call 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 opening remarks on our first quarter results in recent commercial activity. A brief word on the markets. and then hand it over to Richard to cover the financials. As usual, following our prepared remarks, we look forward to taking your questions. Our first quarter adjusted EBITDA of $183 million was up 32% year on year and reflected solid operational uptime during the quarter and a slight sequential increase in marketed utilization. While costs were up from last quarter, this was primarily timing related. and resulted in a modest sequential decrease in EBITDA. As we mentioned last quarter, we do expect quarter one to represent just a starting point for EBITDA this year, followed by progressive improvement throughout the year. Importantly, all of our major projects and contract preparation activities are progressing well, with timing consistent with what we provided last quarter. Thus, we are excited to be commencing significant new contracts for several RIGs over the next few months. including the Noble Discoverer, the Noble Fay Kozak, and the Noble Regina Allen, all of which will underpin this earnings ramp. The Discoverer has completed its SPS and contract prep and is undergoing acceptance testing for its Petrobras contract in Colombia. The Fay Kozak has arrived in Brazil and has also commenced acceptance testing ahead of its two-and-a-half-year Petrobras contract. And lastly, the Regina Allen has also completed its shipyard stay and has arrived in Argentina ready to commence its contract with Total in the next few weeks. While there's still work to be done, some of which is out of our control, we're tracking well against the completion timeline for those major projects which are critical to our earnings ramp this year. The Board of Directors declared a 40-cent dividend for the second quarter of 2024, consistent with last quarter. This will bring cumulative total capital return to shareholders since our Q4 2022 merger to $400 million. As we outlined on last quarter's call, we expect full year free cash flow to increase in 2024 versus 2023 and to be materially back half-weighted. With this progression, we plan to continue to deliver on returning the significant majority of free cash flow via dividends and buybacks as cash flow inflects to a higher plane later this year and especially into next year. The market outlook for offshore drilling remains encouraging, both from a top-down macro perspective, as well as from the steady drumbeat of positive contract signings and indications of open demand from our customers, all of which point to enduring tightness and healthy commercial opportunities over the foreseeable horizon. Leading-edge drill ship day rates have approached and eclipsed $500,000 at the high end, and significant multi-year contract terms designed to hedge against these higher day rates have also arrived. We view both of these complementary developments as positive for the visibility of our business. We've had several nice contract signings since our last report at the end of February. First, the Noble Viking was awarded a contract for three firm wells with prime energy in the Philippines at a day rate of $499,000, excluding additional fees for MPD services mobilization, and demobilization. This contract also features one additional option well at $549,000 that would keep the rig booked through most of 2025. Next, Petronoff exercised an option for an additional 60-day well with the Noble Voyager in Suriname at $470,000 per day, which extends this campaign into mid-August and keeps the Voyager well-positioned for additional future opportunities in this exciting growth region. where Noble has established a very strong presence. And then finally, within the UDW fleet, we've been happy to announce a couple of new engagements recently for the Noble Venturer in West Africa, which have effectively eliminated the potential downside arising from Tullow's early release of the rig, which, as a reminder, resulted in part from the rig's outstanding drilling efficiency. We now expect Tullow to finish with the rig in Ghana within the next several weeks, at which time we will mobilize for a three-well contract with Trident Energy in Equatorial Guinea for an estimated 150 days. And then next on to Namibia for a two-well contract plus options with Rhino Resources. The Trident contract is effectively a derivative of the Legacy Tullow contract that was signed several years ago in a very different market. And then, as some of you may recall from trade press coverage several months ago, The Rhino contract priced at $410,000 derived from an LOI that actually originated from the 6G semi-Noble developer. And then it became more efficient and attractive for both Noble and Rhino to assign this job to the Venturer after its availability status changed. So that's a very relevant context behind these new fixtures looking somewhat lower than other leading-edge day rates for 7G drill ships. which, as previously mentioned, are now in the high 400s to low 500s. On the Jackup side, the Noble Innovator had an additional option exercised by BP in the UK North Sea at $145,000 per day, extending from December 2024 into April 2025. Not yet reflected on our fleet status or in our backlog is an additional scope of work for the Jackup Noble Resolve, which is pending contract execution within the next few days. We will update the market with this news as soon as we get it over the finish line. Collectively, these recent fixtures, excluding the pending contract for the resolve, contribute an additional firm backlog value of approximately $210 million, excluding mobilization, MPD revenue, and option periods. With these bookings and net of the shortened TOLO backlog for the Noble Venturer, our total backlog currently stands at $4.4 billion. From a higher-level industry perspective, both contracting momentum and open demand remain constructive. UDW utilization remains around 95% on the marketed fleet. And after a short-term lull in the fourth quarter last year, the first quarter of 2024 saw 26 rig years of UDW capacity contracted, which was back on par with the very healthy 2021 to 2023 trend lines. We also continue to observe open demand for floaters exceeding 100 rig years in the pool of public tenders and pre-tenders, which represents a decade high and provides a strong basis of visibility for additional contracting strength in the months and years ahead. There's clearly an ongoing transition back toward longer-term planning and procurement strategy amongst some of the biggest IOC and NOC customers. as evidenced both by some of the long-term deals that have recently been signed, as well as many others still in the commercial pipeline. The execution of these longer-term commitments represents a threshold backlog catalyst for our industry, as well as an opportunity for customers to lock in acceptable long-term rig pricing to de-risk their capital planning. Over the near term, we still have some white space to fill on three of our sixth-gen rigs, both Globetrotter drill ships and the semi-noble developer. These three units remain a commercial priority and also account for most of the sensitivity range between the high and low ends of our EBITDA guidance for this year. We're continuing to pursue work for these rigs and will update their future status as it progresses. With the six-gen floaters comprising the lion's share of open capacity industry-wide over the near term, we expect the utilization and day rate bifurcation for these units to continue for some time. And just to zoom in a little bit on that dynamic, if you look at total utilization of UDW floaters today with 7,500 feet or greater water depth ratings, there are currently 104 rigs with contracts and seven marketable warm or hot rigs without contracts, all seven of which are 6GIN units, including two of ours. And then, looking at the UDW rigs that are scheduled to roll off contract over the balance of this year without follow-on contracts as of today, there are nine additional units, five of which are 6-gen. The steady rise in 7-gen day rates combined with this 6-gen utilization profile clearly underlines the swing supply nature of the lower-tier assets, which is reflective of a firm and orderly market rather than a scarcity situation. And there certainly is work coming for most of these lower-tier rigs, but it's just more likely to be more patchwork than seamless, at least over the near term. That's the main point. The jack-up market, while also in the mid-90s percents in terms of marketed utilization, is obviously digesting the effects of the Saudi reset, which has impacted 22 rigs or 5% of global demand. Despite some recent evidence of day rate softness resulting from rigs leaving the kingdom for alternative work, we haven't seen nor do we anticipate any impact to market balances or day rates in the harsh and ultra-harsh segments where our jacked-up fleet is predominantly focused. This is mostly a matter of rig specs. Day rates in the non-Norway North Sea are still in the $130,000 to $150,000 range. Or above this range, for instance, is requiring more premium rig specs such as the CJ-70. In Norway, the most recently observed CJ-70 fixture was in the $240,000 to $250,000 range. For both of our jackups rolling off contracts later this year in the Southern North Sea, the Noble Resilient and the Noble Resolve, we are tracking opportunities for follow-on work, albeit potentially with some gaps between work in the second half of this year. So I'll pause here and pass the call to Richard to cover the financials.

Thank you, Robert, and good morning or good afternoon all. In my remarks today, I will briefly review the highlights of our first quarter and then touch on the outlook for the remainder of the year. Contract drilling services revenue for the first quarter totaled $612 million, up slightly from $609 million in the fourth quarter. Adjusted EBITDA was $183 million in Q1, down from $201 million in Q4. Our adjusted EBITDA margin in Q1 was 29%. Cash flow from operations was $129 million, capital expenditures were $167 million, and free cash flow was negative $38 million. First quarter results were impacted across the revenue, OPEX, and CAPEX lines from several rigs that were idle and preparing for contract startups. These contract startups, with the Noble Discoverer, Noble Faye Kozak, and Noble Regina Allen, are all expected to take place during the second quarter or early third quarter. Accordingly, the commencement of these rigs' next contracts is expected to drive improved revenue, EBITDA, and cash flow over the remainder of the year. At 16 marketed floaters were 76% utilized in Q1, up from 75% in the fourth quarter, with 15 out of 16 rigs, or 95% of the marketed fleet, contracted for current and or future work. At 13 marketed floaters, Jackups will utilize 67% in the first quarter, up from 61% in the fourth quarter. Average earned day rates in Q1 were $434,000 per day for floaters and $144,000 per day for jackups. As summarized on page five of the earnings presentation slides, our total backlog as of May 6th stands at $4.4 billion. We have $1.7 billion that is scheduled for revenue conversion in Q2 through Q4 2024. As a reminder, this backlog does not include reimbursable revenue or revenue from ancillary services. Referring to page nine of the earnings slides, we are maintaining full year 2024 guidance as follows. Total revenue within a range of 2.55 billion to 2.7 billion, which includes approximately 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, are between $400 and $440 million. We expect the key drivers for this year's earnings outcome rests with the three six-gen floaters, Noble Glow Trotters 1 and 2, and the Noble Developer, as well as successful contract startups for the three rigs previously mentioned. We believe that these major projects have progressed through solid execution, and we are optimistic about getting through acceptance testing in the timely manner. Assuming contract startups that are in line with our fleet status report and recognizing that there are many other factors that could materially impact our financial performance, then we don't need much incremental work at all to be squarely in the lower half of our guidance range. There are absolutely pathways to getting above the midpoint, but we would likely need a decent chunk of incremental work, probably on the 6G rigs, to reach the upper half of that 2024 EBITDA guidance range. Lastly, on cash flow, Q1 was obviously a heavy quarter for CapEx, as well as being impacted by a working capital build. Our cash balance was also reduced by approximately $50 million related to taxes withheld or effectively a net shift settlement on vesting equity awards related to one-time Chapter 11 emergence grants. With improved EBITDA and moderating CapEx over the balance of the year, we continue to expect our free cash flow for the year to be very much weighted to the second half. With that, I'll turn the call back over to Robert.

Thanks, Richard. Before we turn the call over for Q&A, I'd like to take a quick moment to highlight our recently published sustainability report, which we put out last month and can be found on our website. Our team did a terrific job of delivering a framework, a vision, and a report that are ambitious yet grounded, and in the end, worthy of our first choice offshore mantra. As part of defining our role in the sustainable energy future, we've taken a 360-degree approach to decarbonization that's focused on technology, operations, and collaboration opportunities with customers and partners. Reducing CO2 intensity requires us to invest and optimize our assets and to partner with customers who share our attitude and commitment toward environmental goals. The sustainable energy pillar of our framework encompasses the digital energy efficiency insights monitoring system, which we have now rolled out across our entire fleet. We're also working on a suite of opportunities with alternative fuel and power sources, which although not accessible on a fleet-wide basis, can still bring meaningful emissions benefits in specific applications. This includes renewable fuels, which can reduce CO2 emissions by up to 95% compared to regular diesel, as well as shore-based power for a jack-up rig offshore Norway. And of course, we've spoken before about our leadership position in offshore CCS. These are just a few of the highlights that fall under the sustainable energy mantle. Equally important at Noble are the numerous areas in which we strive to provide the best possible workplace for our employees. This means a relentless focus on safety as well as diversity and investment in the local communities where we work. Including, for example, both our drill crew development program in Guyana as well as a four year maritime scholarship program that we've been proud to sponsor for a number of Guyanese students. There's a tremendous amount of valuable information in this 64 page sustainability report, so please have a look. I think it's a very compelling of who we are and where we are, as well as where we're heading as a company. Wrapping up, over the near term, again, we remain excited about both the state of the business as well as the execution status of our 2024 major projects, which should enable a progressive step up in earnings and cash flow over the balance of this year. With this ramp up, especially in the second half of this year, we will look to expand our capital returns to shareholders. With that, operator, we're ready now to open the call for questions.

Thank you. And we will now begin the question and answer session. If you have dialed in and would like to ask a question, please press star 1 on your telephone keypad to raise your hand and join the queue. If you would like to withdraw your question, simply press star 1 a second time. If you are called upon to ask your question and are listening via speakerphone on your device, Please pick up your handset and ensure that your phone is not on mute when asking your question. We ask that you do please limit yourself to one question and one follow-up. Again, press star 1 if you would like to join the queue. And your first question comes from Kurt Holley with Benchmark. Your line is open.

Hey, good morning, everybody. Good morning, Kurt. I appreciate the updates. So let me, I guess, let me start just with the guidance dynamics and your commentary, very helpful commentary there, by the way, about, you know, what things, how things we need to shake out. But I'm assuming, or should we assume, is a better question, that given the range of EBITDA guidance and the fact that you affirm that EBITDA guidance, that there's I don't know, a better than 50% probability that you're going to get work for those three idle 6G assets?

No, I'm not sure that's the right assumption. I mean, I guess a way to put it is we're somewhere around 97% contracted fleet-wide this year, and for where we need to be at the low end of the guidance, And so we feel extremely good about our currently contracted revenue at the low end of the guidance range. And then contribution from 6Gs, project execution very principally, and then maintaining or, I guess, watching our costs all contribute to paths upward from bottom half of guidance so it's it still is pretty early and um there are a number of different paths up to the top half of guidance including 6g is one of them okay okay i appreciate that and um so then in the context of the outlook for the 6g market whether it's your rigs or the market in general um

again, it didn't seem like there was a high degree conviction, right, that there was enough demand to get those rigs and generating revenue for this year. But, you know, what kind of opportunities, you know, do you see? And, you know, what kind of market areas? And you don't have to get too specific if it's a very competitive situation. I understand that. But just give a broader idea in terms of regions and where these assets might have opportunities. Sure.

Yeah, there's, you know, there's, There's, I guess, seven rigs available now, as you said in the script, and another handful, five or six rigs coming available this year in the 6G world. You know, there are opportunities. We're chasing opportunities behind every single one of our 6Gs. We just announced a slight extension on one of them from Shell, which really is just the same contract taking a little longer to close out. We've had a couple... that were very very close that slipped away for various reasons which is is life uh in the contracting world uh we do think that that this uh the the the number of total 6g open rigs capacity does correct itself and i think we'll see some some things that that happen in late this year but i think a lot of it's going to take place next year as well on an industry-wide basis And so, you know, we're just trying to do our best to see what's out there and where a good fit could be. Globally, we're bidding the rigs mostly in the Western Hemisphere, but we're open to work effectively anywhere that makes sense from a cash flow basis.

Okay. I appreciate that, Keller. Thank you.

And we will take our next question from Eddie Kim with Barclays. Your line is open.

Hi, good morning. Just sticking with the kind of 7G, 6G theme. Rob, just wanted to get your thoughts on what in your mind is driving that difference between those asset classes. Is the open capacity in the 6G market more a function of specific customers who normally take 6G rigs, that those customers are delaying their programs? Or is it more a reflection of customers broadly, even those who used to take 6G rigs, now looking to secure 7G rigs instead? Just any thoughts around that would be great.

Sure. Yeah, that's a great question. It's more the latter. The seventh generation rigs, and particularly the rigs that have two BOPs, are just more efficient assets than the 6G rigs. And I think... Through the downturn, we saw customers effectively get seventh generation rigs for no premium compared to what else might be available. And obviously, the markets shifted from there. But the efficiency stands. In a short, you know, let's call it a one well job, probably the difference is less pronounced. However, when you're talking about longer term work, either multiple wells, but even more so a longer development project, the seventh generation rigs really start to make a big difference in terms of efficiency. And so I think you're just seeing that dynamic play. I think you've seen it play out over the last couple of years, and it's continuing today. So, you know, no surprise, but those are the best and most efficient assets, and that's where where customers' preferences lie.

Got it. Got it. That makes sense. Just my follow-up is on the bifurcation that you mentioned last quarter about the bifurcation between kind of top-tier rigs that are working versus rigs that are being reactivated from the sidelines into multi-year contracts. Roughly, how much of a discount would you expect for one of those sideline rigs versus a hot rig? One of your peers last week seemed to almost set the floor at around $450,000 a day, even for these sideline rigs. Would you be in agreement with that, just your updated expectations there? Sure.

There's a variety of different owners of sideline rigs right now. We're one with the Meltem. We've said that... We're going to be fairly conservative in how we think about reactivating that rig, which translates into probably less of a discount to market. But we have always said that we think all of those rigs will come out at a discount to market. I think that's likely what would be required by a customer who's willing to contract one of those rigs. How much is going to vary, and I think there are, among the different owners out there, there are different economic incentives to drive the potential discount. Of course, I don't know how other people are thinking, but I do think that in certain instances, there's probably more motivation to go ahead and find a contract and get get day rates started, even if it requires a slightly higher discount than perhaps we face in our own situation. Got it. Got it. That makes sense.

Thanks. That's very helpful. I'll turn it back. Thanks, Annie.

And we will take our next question from Greg Lewis with BTIG. Your line is open.

Hey, thank you, and good morning, everybody, and thanks for taking my questions.

Good morning.

Hey, Robert. Um, I had a question, um, you know, about the, um, you know, the contracts, um, you know, with Exxon and Guyana, um, realizing it's not until, um, the price resets, not until September, but, but just had a couple of questions around that. And, and, and one being, um, you know, it seems like, you know, and maybe it's always been through the cycles and it just was not as evident, um, you know, with extra equipment, but it seems like, you know, this cycle, you know, everyone's MPD and MPD is not included in the day rate, but it's an extra, you know, pick a number, $30,000 to $40,000 on some of these term jobs. And really what I'm trying to understand is in those negotiations, two things. One is, is it a headline day rate that, and I imagine Noble's fighting for more and Exxon's fighting for less. But as these other services, which I assume we're doing in Guyana as well, are part of the contract but maybe not in the scope of the day rate, is that something that's in play for Noble to get as you renegotiate the next rate?

Yeah. So the rate is in – It's always hard to decode. It's hard for us to decode, just like it is for you guys on when you get total contract value, and there's a lot of different other services and rates right now, just as you said. We try to deconstruct rates and really understand the various components. Clearly, MOB and DMOB have to come out, and then the rest of the other services, you know, we always spend time trying to to understand what those might be in some of the fixtures that are out there. The rate, you know, is supposed to be a market, a global market rate for a tier one, you know, a two BOP, all the bells and whistles rig for a six month job. And that filters out a variety of different rates out there. And, you know, it's, you know, we spend time trying to understand and guess at what the fixtures actually represent. And so that's, you know, it's work every six months, always takes several meetings. But, and as we've said before, often includes a third party to kind of offer a third opinion. But I think it's worked extremely well so far.

Oh, yeah, no doubt. No doubt.

We're at a good rate, yeah.

And I think you answered it in saying I wasn't sure about the duration. It sounds like anything over six months. So there was a one-year contract in the Gulf of Mexico over $500,000. Not that we should expect the rate to go to $500,000, but a contract like that, even though it was an extension, would most likely be included in the updated price setting?

Yeah. Without getting into a very specific example like that, I would say that generally excluded are the longer contracts, two years and over. Okay. And included are globally the rest of the contracts and you know, for every leading edge U.S. Gulf of Mexico fixture, there's generally another fixture out there that's very relevant that's generally a little bit below the U.S. right now. And so the rate is a basket of all of the relevant fixtures globally and requires, you know, they all require some adjustments. And it's not uncomplicated trying to trying to put the basket together, as I mentioned.

Okay, great. Super helpful. Thank you for the thoughts.

Sure. Thank you.

And we will take our next question from David Smith with Pickering Energy Partners. Your line is open.

Hey, good morning. Thank you for taking my question.

Hi, Dave.

So I appreciate the commentary and the prepared remarks referencing the open demand for floaters from tenders and pre-tenders that are a decade high. I wanted to ask about the demand that doesn't go through the tender process. If you can give us any color on the interest you're seeing from direct negotiations, if you're having more of those or if really most new opportunities are going through the tender phase.

No, I'd say that the direct negotiations, the level of direct negotiations have increased relatively steadily through time. It's easier to quote open tenders. I think it's probably a slightly more objective measure. But for sure, a lot of what's out there and a lot of what we're predicting will drive demand growth is actually direct negotiation. So if you remember last quarter, we thought we'd see about plus 10 rigs, perhaps a few more going through next year. on total floater demand. And while we see a tremendous number of open tenders, and I think that's a really positive story, the total demand growth is going to include some healthy direct negotiations as well. And sorry, go ahead, Blake.

Yeah, to provide a little bit, just some numerical context of that, when you look at our fixtures over the course of 2023, 54% of those were direct negotiations. And And though it's a small number this year, it's 75% year-to-date.

Perfect. Appreciate that, Collar. And if I could slip in a follow-up. Just thinking about the little bit of U.S. Gulf deepwater demand for well intervention and P&A, I know those contracts can come with very short lead times. And I wanted to ask, in your experience, deep forecasts, for active hurricane seasons have any notable impact on operator interest to contract for the well intervention or P&A work in the, you know, July through November period?

It's a good question. I don't think, I don't, I wouldn't say that there's seasonality in the shorter term demand in the US that we've noticed. The intervention market, which I think we've said, kind of hinted at before, is there's some possible application of the globetrotters into that market. It is a very short-term and a call-out market. It's a different market than drilling. And I don't I can't say I'm 100%. It's a good question, Dave, but I don't think there's a lot of seasonality that really drives those dynamics. Look, in the U.S. Gulf, obviously hurricanes are very impactful, but you get winter storms in the U.S. as well that can be pretty disruptive to actual rig operations, obviously less destructive. But anyway, I don't think there's a tremendous amount of seasonality.

I do appreciate it. Thank you.

And we will take our next question from Doug Becker with Capital One. Your line is open.

Thank you. Robert, you mentioned that costs were up from last quarter because of contract prep, mobilization, which makes a lot of sense given the contracts we had starting up over the next couple quarters. Just any high-level comments on the trajectory for operating expense and CapEx over the coming quarters?

Sure. It's a very good question. Look, I think from an inflation perspective, we're obviously being impacted by that. I think it's obviously part of our guidance, if you will. So we're seeing inflationary pressure across our entire cost base somewhere between, call it, 4% to 6%. But those numbers are absolutely part of our guidance, both on the OpEx and on the CapEx side as well. Obviously, CapEx was higher in Q1, really down to these key contract startups. And we expect CapEx obviously to moderate in the second half of the year.

Should we expect it down in 2Q versus 1Q?

I think CapEx, I mean, it can be very lumpy, right? So from a CapEx perspective, quarter to quarter, it can be very lumpy. You know, I think that obviously we've maintained guidance for the full year from a CapEx perspective. You know, so I think obviously Q1 was elevated. And so if you took the average of the remaining three quarters, obviously that's down from where we were in Q1. So we're not going to provide specific guidance, if you will, for Q2, except for the fact that we've maintained full year guidance on the CapEx side.

Fair enough. And Richard, maybe speaking about the guidance, is it a fair way to characterize that the midpoint is still the most likely outcome? Or is it shading one way or the other? I understand there's a lot of different paths to get to the upper end or lower end.

Yeah, it's a, it's a very good and a very fair question. Um, you know, obviously it's still early in the year. We feel very good about our range. Um, there's various moving parts about that. So, um, you know, mid points a great number for sure. Um, but but there's, there's various drivers. that could impact guidance, both positive and on the other side of the equation as well. So we're obviously focused on trying to bring these three new contracts or startups online as soon as we can. And obviously that will have a nice impact on the full year financial performance as well.

Understood. Thank you.

And as a reminder, press star 1 if you would like to ask a question. And we will take our next question from Noel Parks with Tui Brothers. Your line is open.

Hi, good morning. Just had a couple. Just thinking about the negotiation process, I'm just wondering how you're seeing the tenor of the negotiations at this point. In particular, I'm sort of wondering just in terms of contract terms, I guess just a basic question. When you're talking multi-year terms, are these essentially all flat for The three years, are there options for escalation throughout them? Is that something that customers are receptive to?

Yeah, I think it varies. We have, I think, some instances where locking in a low headline rate is a really important driver for certain customers. And we have others where locking in a very specific rig spec and letting the market dictate works as well. And so I think it varies. I think, you know, generally this, you know, obviously negotiations and contract terms kind of run in line with day rates. They're all very highly correlated. And I mentioned last quarter, and I guess I would repeat that, We see this as a balanced market going forward. It's not really a feel of scarcity. I know some have called it that day is coming very soon. Perhaps that's correct. We see it probably more as a balanced market through next year. It's one where when a customer needs a rig, generally a customer can get a rig. But it's also one that's supportive of high utilization and gradually rising day rates for the contractors. You know, I think it's a very healthy market. And so if you extrapolate from that color into the nature of the negotiations, it's kind of in line. There's, you know, different push points in different negotiations.

Great, thanks. That's a really helpful characterization. And to the degree that, of course, everything is sort of in process, if you were going to point to one thing for whatever time frame, either before the end of next year or looking beyond that, is there any particular lever where you think you might have the best opportunity to pull it, whether it is the rate, the term, the equipment? So, in other words, what could be the next piece of the puzzle that could, you know, in theory sort of drive things higher from here, would you say?

It's a good question. You know, we waited for a very long time for a $500,000 rate to be announced.

Sure.

And that's happened now. So, that's, you know, a threshold, you know, on average, I think. the average rates are still below 500 but i think you'll you'll of course continue to see uh rates in that range being announced i think probably the the perhaps faster moving dynamic over the next year to 18 months is going to be term where i think you're going to see average term continue to increase and i think the the average term of the open public tenders is representative of that. And of course, you've heard us and our competitors talk about all of the direct negotiations that are out there. And there's a number of those that carry significant term as well. And so I think probably we see improvement in both rate and term over the next over the next through this year and next year.

Great, thanks a lot. Thanks.

And there are no further questions at this time, so I would now like to turn the conference back to Mr. Ian McPherson for any additional or closing remarks.

Thanks, everyone, for joining the call today. Have a great day, and we'll look forward to speaking with you again next quarter. Goodbye.

Ladies and gentlemen, this concludes today's call, and we thank you for your participation. You may now disconnect.