Noble Corporation (NYSE:NE) Q1 2024 Earnings Call Transcript

Noble Corporation (NYSE:NE) Q1 2024 Earnings Call Transcript May 7, 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: Good morning, and thank you for standing by. My name is Abby, and I’ll be your conference operator today. At this time, I would like to welcome everyone to the Noble Corporation First Quarter 2024 Earnings Call. [Operator Instructions] Thank you. And I would now like to turn the conference over to Ian McPherson, Vice President of Investor Relations. You may begin.

Ian MacPherson: 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 any 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 filed with the SEC. Now I’ll 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 opening remarks on our first quarter results and recent commercial activity, a brief word on the market, 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 1 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 Faye 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 Faye Kozak has arrived in Brazil and has also commenced acceptance testing ahead of its 2.5 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 $0.40 dividend for the second quarter of 2024, consistent with last quarter. This will bring the 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 drillship dayrates have approached and eclipsed $500,000 at the high end, and significant multiyear contract terms designed to hedge against these higher dayrates 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 3 firm wells with Prime Energy in the Philippines at a dayrate of $499,000, excluding additional fees for MPD services, mobilization, and demobilization.

This contract also features 1 additional option well at $549,000 that would keep the rig booked through most of 2025. Next, Petronas 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 3-well contract with Trident Energy in Equatorial Guinea for an estimated 150 days, and then next on to Namibia for a 2-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 the very relevant context behind these new fixtures looking somewhat lower than other leading-edge dayrates for 7g drill ships, which, as previously mentioned, are now in the high $400,000s to low $500,000s. On the jackup side, the Noble Innovator had an additional option exercised by BP in the U.K. 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 pictures, 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 Tullow 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 a very healthy 2021 to 2023 trendline. We also continued 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 derisk their capital planning. Over the near term, we still have some whitespace to fill on 3 of our 6th-gen rigs, both Globetrotter drillships and the semi Noble Developer. These 3 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 we’ll update their future status as it progresses. With the 6th-gen floaters comprising the lion’s share of open capacity industry-wide over the near term, we expect the utilization and dayrate 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 7 marketable warm or hot rigs without contracts, all 7 of which are 6th-gen units, including 2 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 9 additional units, 5 of which are 6th-gen.

The steady rise in 7th-gen dayrates combined with this 6th-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 jackup market, while also in the mid-90 percent 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 dayrate softness resulting from rigs leaving the Kingdom for alternative work, we haven’t seen nor do we anticipate any impact to market balances or dayrates in the harsh and ultra-harsh segments where our jackup fleet is predominantly focused.

This is mostly a matter of rig specs. Dayrates in the non-Norway North Sea are still in the $130,000 to $150,000 range, or above this range for instances requiring more premium rig specs such as the CJ70. In Norway, the most recently observed CJ70 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.

Richard Barker: 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 for 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. Our 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. Our 13 marketed jackups were utilized 67% in the first quarter, up from 61% in the fourth quarter. Average earned dayrate in Q1 were $434,000 per day for floaters and $144,000 per day for jackups. As summarized on Page 5 of the earnings presentation slides, our total backlog as of May 6 stands at $4.4 billion.

We have $1.7 billion that is scheduled for revenue conversion in Q2 through Q 420 24. As a reminder, this backlog does not include reimbursable revenue or revenue from ancillary services. Referring to Page 9 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, of between $400 million and $440 million. We expect the key drivers for this year’s earnings outcome rests with the 3 6th-gen floaters, Noble Globetrotters 1 and 2, and the Noble Developer, as well as successful contract startups for the 3 rigs previously mentioned.

We believe that these major projects have progressed through solid execution, and we are optimistic about getting through acceptance testing in a 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 share 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.

Robert Eifler: 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. And 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 jackup 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 4-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 representation 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.

See also 30 Most Fun Cities in the US in 2024 and 15 Best Places to Retire in Florida That You’ve Never Heard Of.

Q&A Session

Operator: [Operator Instructions] And your first question comes from Kurt Hallead with Benchmark.

Kurt Hallead: I appreciate the updates. So, I guess, let me start just with the guidance dynamics and your commentary. Very helpful commentary there, by the way, about how things would need to shake out. But I’m assuming, or should we assume is a better question, that given the range of EBITDA guidance, 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 3 idle 6g assets?

Robert Eifler: No, I’m not sure that’s the right assumption. I guess, a way to put it is we’re somewhere around 97% contracted fleetwide 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 6g’s 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 still is pretty early. And there are a number of different paths up to the top half of guidance, including 6g is one of them.

Kurt Hallead: Okay. I appreciate that. And so, then, in the context of the outlook for the 6g market, whether it’s your rigs or the market in general, again, it didn’t seem like there was a high degree conviction that there was enough demand to get those rigs and generating revenue for this year. But what kind of opportunities do you see and what 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.

Robert Eifler: Sure. There’s, I guess, 7 rigs available now, as we said in the script, and another handful, 5 or 6 rigs coming available this year in the 6g world. There are opportunities. We’re chasing opportunities behind every single one of our 6g’s. We just announced a side extension on 1 of them from Shell, which really is just the same contract taking a little longer to close out. We had a couple that were very, very close that slipped away for various reasons, which is life in the contracting world. We do think that the number of total 6g open rigs capacity does correct itself. I think we’ll see some things that happen 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, 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.

Operator: And we will take our next question from Eddie Kim with Barclays.

Eddie Kim: Just sticking with the 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.

Robert Eifler: Sure. It’s a great question. It’s more the latter. The 7th-generation rigs, and particularly the rigs that have 2 BOPs, are just more efficient assets than the 6g rigs. And I think through the downturn, we saw customers effectively get 7th-generation rigs for no premium compared to what else might be available. And obviously the market’s shifted from there. But the efficiency stands. In a short, let’s call it a 1-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 7th-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, no surprise. But those are the best and most efficient assets, and that’s where customers’ preferences lie.

Eddie Kim: Got it. That makes sense. Just my follow-up is on the bifurcation that you mentioned last quarter about — the bifurcation between top tier rigs that are working versus rigs that are being reactivated from the sidelines into multiyear 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 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.

Robert Eifler: Sure. There’s a variety of different owners of sideline rigs. Right now, we’re 1 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? It’s going to vary. And I think, 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 dayrate started, even if it requires a slightly higher discount than perhaps we face in our own situation.

Operator: And we will take our next question from Greg Lewis with BTIG.

Greg Lewis: I had a question about the contracts with Exxon in Guyana, realizing it’s not until the price reset is not until September, but just had a couple of questions around that, and 1 being, it seems like, and maybe it’s always been through the cycles, and it just was not as evident with extra equipment, but it seems like this cycle, everyone’s MPD, and MPD is not included in the dayrate, but it’s an extra, 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, 2 things: 1 is, is it a headline dayrate? 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 dayrate, is that something that’s in play for Noble to get as you renegotiate the next rate?

Robert Eifler: Yes. So, the rate, 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, mobe and demobe have to come out. And then the rest of the other services, we spend time trying to understand what those might be in some of the fixtures that are out there. The rate is supposed to be a global market rate for a tier 1, a 2-BOP, all the bells-and-whistles rig for a 6-month job. And that filters out a variety of different rates out there. And we spend time trying to understand and guess at what the fixtures actually represent. And so, it’s work every 6 months, always takes several meetings, and as we’ve said before, often includes a third party to offer a third opinion, but I think has worked extremely well so far…

Greg Lewis: Oh, yes. No doubt.

Robert Eifler: And we’re at a good rate. Yes.

Greg Lewis: And I think you answered it in saying I wasn’t sure about the duration. It sounds like anything over 6 months. So, there was a 1-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.

Robert Eifler: Yes. Without getting into a very specific example like that, I would say that generally excluded are the longer contracts, 2 years and over, and included are globally the rest of the contracts. And 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 they all require some adjustments. And it’s not uncomplicated trying to put the basket together, as I mentioned.

Operator: And we will take our next question from David Smith with Pickering Energy Partners.

David Smith: So, I appreciate the commentary in the prepared remarks referencing the open demand for floaters from tenders and pre-tenders that sit at 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.

Robert Eifler: 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. Sorry, go ahead, Blake.

Blake Denton: Yes. 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 though it’s a small number this year, it’s 75% year to date.

David Smith: Perfect. Appreciate that color. 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 wanted to ask, in your experience, these forecasts for active hurricane seasons have any notable impact on operator interests to contract for well intervention or P&A work in the July through November periods?

Robert Eifler: It’s a good question. I wouldn’t say that there’s seasonality in the shorter-term demand in the U.S. that we’ve noticed. The intervention market, which I think we’ve said, hinted at before, there is some possible application of the Globetrotters into that market. It is a very short-term in a callout market, it’s a different market than drilling. And 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.

Operator: And we will take our next question from Doug Becker with Capital One.

Doug Becker: 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 have starting up over the next couple of quarters. Just any high-level comments on the trajectory for operating expense and CapEx over the coming quarters?

Richard Barker: 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.

Doug Becker: Should we expect it down in 2Q versus 1Q?

Richard Barker: The CapEx can be very lumpy, right. So, from a CapEx perspective, quarter to quarter, it can be very lumpy. I think that obviously we’ve maintained guidance for the full year from a CapEx perspective. So, I think, obviously Q1 was elevated, and so if you took the average of the remaining 3 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.

Doug Becker: Yes, 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.

Richard Barker: Yes, it’s a very good and a very fair question. Obviously, it’s still early in the year. We feel very good about our range. There’s various moving parts about that. So, midpoint that’s a great number for sure, but 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 3 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.

Operator: [Operator Instructions] And we will take our next question from Noel Parks with Tuohy Brothers.

Noel Parks: 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 wondering just in terms of contract terms, I guess, just a basic question, when you’re talking multiyear terms, are these essentially all flat for the 3 years? Are there options for escalation throughout them? Is that something that customers are receptive to?

Blake Denton: Yes, 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, generally, obviously, negotiations in contract terms run in line with dayrates. 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 that 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 dayrates for the contractors.

I think it’s a very healthy market. And so, if you extrapolate from that color into the nature of the negotiations, it’s in line. There’s different push points in different negotiations.

Noel Parks: That’s a really helpful characterization. And to the degree that, of course, everything is in process, if you were going to point to 1 thing for whatever timeframe, 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, in theory, drive things higher from here, would you say?

Blake Denton: Yes, it’s a good question. We waited for a very long time for a $500,000 rate to be announced, and that’s happened now. So, that’s a threshold. On average, I think, the average rates are still below $500,000, but I think you’ll, of course, continue to see rates in that range being announced. I think probably 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 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 — through this year and next year.

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

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

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