Noble Corporation PLC (NE) 2021 Q2 法說會逐字稿

Thank you for standing by, and welcome to the Noble Corporation Second Quarter 2021 Results Conference Call. (Operator Instructions) Please be advised that today's conference is being recorded. (Operator Instructions)

I would now like to hand the conference over to your speaker today, Craig Muirhead. Thank you. Please go ahead, sir.

Thank you, Rebecca, and welcome, everyone, to Noble Corporation's Second Quarter 2021 Earnings Conference Call. We appreciate your continued interest in the company. You can find a copy of Noble's earnings report issued yesterday evening, along with the supporting statements and schedules on our website at noblecorp.com.

Joining me today are Robert Eifler, President and Chief Executive Officer; and Richard Barker, Senior Vice President and Chief Financial Officer. Also joining are Blake Denton, Vice President, Marketing and Contracts; and Joey Kawaja, Vice President of Operations.

For today's call, we will begin with prepared remarks followed by a question-and-answer session. 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. Please refer to our SEC filings for more information regarding our forward-looking statements, including the risks and uncertainties that could impact our future results.

Also note, we are referencing non-GAAP financial measures in the call today. You will find the required supplemental disclosure for these measures, including the most directly comparable GAAP measure and an associated reconciliation on our website.

And with that, I will now turn the call over to Robert Eifler, President and Chief Executive Officer of Noble.

Thank you, Craig, and welcome to everyone joining us on the call today. I'm proud of the Noble's team -- the Noble team's performance in the second quarter and excited to walk you through the results we released yesterday. Noble continues to deliver value to our customers and investors, all while keeping our employees and business partners safe offshore.

Last year, we had exceptional safety and operational performance, breaking a company record, and the second quarter of 2021 was even better. Thank you to all of our crews offshore and our people in our shore-based offices who have delivered such good performance in the face of the travel and logistical challenges brought about by COVID-19. We also executed on our strategic plans in the second quarter by acquiring Pacific Drilling, making substantial progress on the integration and contracting of the fleet, and relisting on the New York Stock Exchange.

We'll speak more on our strategy later, but let me begin my prepared remarks today by addressing the floater and jackup markets. Ultra-deepwater market has improved dramatically during 2021 and our newly acquired Pacific rigs are allowing Noble's marketing team to again bid into that market following a period without any drillship availability.

As I mentioned last quarter, one of the key success factors for the acquisition was finding work for the new drillships. Since we last spoke, Noble has secured 3 new contracts which address that priority. This additional work adds approximately 180 operating exercise of options and has a cumulative total contract value of over $55 million, including associated mobilization fees and customer-reimbursed rig upgrades.

The first 2 new contracts are for the Pacific Khamsin and further build out its 2021 and 2022 drilling schedule. The rig's previously announced one-well campaign for Petronas in Mexico is expected to conclude in early fourth quarter of this year. Today, we're excited to share that the Khamsin is now contracted to return to U.S. waters for approximately 80 days of work with Murphy.

Our second new contract award this quarter, which was announced in our June 22 Fleet Status Report has the Khamsin remaining in the U.S. Gulf following Murphy to drill one well for EnVen through additional follow-on work.

The other drillship we have rolling off contract in 2021 is the Pacific Santa Ana. We still expect that rig to complete its current contract with Petronas in Mauritania in August, and I'm pleased to announce a new contract award with APA Corporation in Suriname. That contract is for 1 well plus 2 1-well options and is estimated to commence in the first quarter next year. This award in Suriname is meaningful for the team here as it validates our thesis for the Pacific acquisition by deploying PACD's high-spec assets to further serve Noble's existing customer base. I'm encouraged by these new contracts, which show positive momentum in the ultra-deepwater market.

I'll now walk through our key ultra-deepwater regions with some operational and market highlights. The U.S. Gulf of Mexico is quickly tightening, and both rates and utilization for ultra-deepwater rigs have moved sharply upward over the first half of 2021. Compared to the first quarter, the industry had seen a fivefold increase in contract fixtures in the region with almost 5 rig years added in the second quarter. We are currently pursuing multiple contract opportunities in the U.S. Gulf for work starting in 2022 and beyond.

The South America deepwater region has seen several contract fixtures during the second quarter, and we continue to believe this region to have the highest growth potential in the near to medium term. In Brazil, the average 2021 fixture term stands at 2 years led by Petrobras demand. Historically, floater dayrates in Brazil lagged the rest of the world as local drilling contractors competed fiercely to keep their rigs utilized. However, with the local supply of drillships now essentially fully booked, a favorable rate trend is evident in the more recent Petrobras tenders. Noble has a considerable history in Brazil, and we continue to look for the right opportunity to reenter the country.

Further off the coast, we see activity and rates in Guyana and Suriname increasing into 2022 and remain committed to serving our customers and the local communities there. Early in the second quarter, the Noble Sam Croft began its contract in Guyana with ExxonMobil under our Commercial Enabling Agreement, or CEA. And Richard will provide a reminder on some of the mechanics of that agreement in a moment.

This brings our fleet to 4 rigs working in Guyana, and the addition of the Santa Ana early next year will bring our fleet to 5 high-spec ultra-deepwater rigs in the region. The rig crews working in Guyana are delivering outstanding performance, and I'm pleased that our customers continue to entrust us with some of their most important wells.

West African deepwater activity is beginning to rise as confidence in oil prices and global energy demand begin to normalize. Countries such as Nigeria and Ghana, which were deeply impacted by the loss of offshore drilling activity, are now seeking to improve their regulatory environment to incentivize operators to resume drilling plans. We're now seeing some of those previous projects getting sanctioned, and drillship utilization in the area has increased from 56% in the first quarter to 73% in the second. Our conversations with customers indicate that there could be new long-term projects in Angola, Nigeria and Ghana for 2022 starts as well as some short-term high-spec floater work in Gabon.

Looking at global supply for floaters, there have been 71 rigs retired since the beginning of 2018, including 15 retirements announced year-to-date. Excluding cold-stacked rigs and new builds, there are 141 floating rigs being marketed today, of which 104 or 74% are committed to contracts.

In addition, there are 17 Tier 1 drillships that are either cold-stacked or stranded in newbuild shipyards. Reactivation costs for cold-stacked rigs can vary widely depending on how long the rig has been stacked and what work is needed to bring it back into service, but can easily exceed $50 million for a stacked drillship. Bringing one of the stranded newbuild ships into service is typically even more capital intensive. The shipyards' pricing expectations are understandably higher than other options in the rig market, and new owners will then have costs associated with additional capital equipment, inventory build and recommissioning and mobilization.

While we think market dynamics and capital constraints will limit the delivery of these rigs in the near term, we recognize the shipyards are exploring creative ways to offload those now long-held assets. We believe many of these cold-stacked and stranded assets will eventually enter the market, but expect these supply additions to be spread out over several years as the market recovery develops.

Now turning to global floating rig demand, especially for UDW. We are seeing a trajectory towards further improvement in the UDW with 2022 demand possibly exceeding 2020 by over 25%. Even with recent volatility in oil prices, our customers recognize deepwater offshore oil and gas as an important part of a modern energy portfolio. Demand bottomed out in 2020 and contracting activity is now back to pre-COVID levels with a total of 19 new contracts for UDW floaters signed in the second quarter.

The U.S. Gulf of Mexico UDW market is nearing full capacity, and the pipeline of opportunities we see indicates the floater market is tightening globally. The rebalancing of supply and demand is now supporting sustainable rates with several recent fixtures in the mid-$200,000 per day range and some higher. Consistent with the early stages of past market recoveries, fixture durations are still primarily short with most tenders being well based and requesting options. But day-rates are definitively increasing, led by constraints on incremental supply posed by capital availability and cost. We expect dayrates to continue to trend higher in every region and eventually contracting terms to increase as well.

Turning now to the jackup market. Activity levels across the North Sea jackup sector remained steady. A moderate number of new fixtures and requirements continue to reach the market with new work emerging for 2022. Today, 2 of our 4 jackups in the U.K. and Danish sectors are working, with 2 rigs warm-stacked. We are pursuing new work for our idle rigs. The competition is high for the few available 2021 opportunities, and we anticipate at least one of our rigs remaining idle through the end of the year.

In Norway, the Noble Lloyd Noble is currently in the shipyard preparing for its contract with Equinor, which is scheduled to commence in early September. The rig is one of the highest-specced jackups in the world and particularly well suited for work in Norway. We're proud to have Equinor's trust as we enter that unique environment, and I'm confident the rig will remain well utilized in that market for a long time.

I'll now move to the Middle East. During the second quarter, Qatar Gas exercised a 1-year option for the Noble Mick O'Brien, which will keep the rig contracted until September 2022. More broadly across the Middle East, there was a respectable volume of contract awards during the quarter, most of which were won by incumbent rigs. We see demand gradually increasing into 2021, but do not expect much upward movement for rates in the near future.

In Trinidad and Tobago, the Noble Regina Allen is now expected to complete its work in mid-August. It is one of the more capable jackup rigs in the Americas and has follow-on opportunities in and around the region, while we anticipate -- which we anticipate could begin in the first half of 2022.

The Noble Tom Prosser in Australia began its current contract with Santos in May that will take it into early next year. The rig has performed very well, and we're happy to report today that it has been awarded an additional 3 firm wells by Santos with an estimated duration of 160 days. This new contract is subject to customers' final project sanctioning and would begin in direct continuation to the current program.

Speaking to the overall supply-and-demand balance for jackups, there have been 88 rigs retired since the beginning of 2018, including 22 retirements announced year-to-date. There are 402 jackups being marketed today, excluding stranded newbuilds and cold-stacked rigs, with 333 or 83% contracted.

Of the contracted jackups, 105 rigs are 25 years old or older. These rigs will eventually be replaced by newer rigs. But in the near term, some older units continue to find new work, and we currently see a stable market on the jackup side with rates and utilization roughly flat in the regions where we operate.

So in summary, we see positive market indicators for floaters and a stable outlook for jackups. I believe Noble is well placed, with our top-tier assets and exceptional people, to thrive in today's offshore drilling market. While we are optimistic about market conditions, the whole Noble team remains laser-focused on safety, operations and customer satisfaction. And our strategy will not stray from maintaining cost discipline and making responsible investing decisions. This is key to our value proposition today.

I'll now turn the call over to Richard to give an update on our financial results.

Thank you, Robert, and good morning all. In my remarks today, I plan to provide some brief highlights of our second quarter results, provide a progress update on the Pacific Drilling acquisition, discuss our current capital structure and round off with some comments around our outlook for the remainder of 2021.

Turning to our quarterly results. Contract drilling services revenue for the second quarter totaled $200 million versus $159 million for the combined first quarter. As a reminder, the combined first quarter of 2021 combines the results of the predecessor period from January 1 to February 5 and the successor period from February 6 through quarter end, and was a result of adopting fresh-start accounting during the quarter. More detail can be found in our Form 10-Q filed on May 7.

The quarterly increase is related to the addition of the Pacific Drilling rigs to our fleet, with the Pacific Santa Ana and the Pacific Sharav earning revenue during the quarter as well as several Noble rigs that went back to work or have significantly more operating days in the second quarter, including the Noble Hans Deul, Noble Sam Turner, Noble Roger Lewis, Noble Scott Marks and Noble Tom Prosser.

Contract drilling services revenue for the second quarter also reflects a reduction of approximately $14 million compared to $8 million recorded in the combined first quarter as a result of noncash amortization of contract intangible assets specific to the 2 Globetrotter rigs.

For similar reasons, our contract drilling costs were higher in the second quarter as we prepared rigs to go to work and absorb the cost of the newly acquired Pacific Drilling rigs. The note -- this is our fourth rig working for the same customer in the same country. Our work with ExxonMobil in Guyana is governed by the CEA, which provides unique, meaningful benefits to both our customer and to Noble, including significant operational efficiencies of having 4 extremely similar rigs operating in the same region and the security of supply.

Importantly, we experienced strong utilization over a multiyear period without realizing downtime between contracts, while Exxon benefits from having access to and being highly familiar with some of the highest-quality rigs that is supported by our infrastructure-related investments in the region. And last, both parties benefit from market-based dayrates that are reset to market March 1 and September 1 each year in a manner that reflects dayrates for a 6-month job at the time of the reset with a single-digit discount, plus potential incentives that allow us to earn back much of the limited discount. The rate renewal process takes place in the 6-month period leading up to the effective renewal date.

Guyana is one of the premier offshore plays globally and will be a critical component of the global oil supply for decades to come. The CEA is truly a win-win for both Exxon and its partners and for Noble. Taken in total, this arrangement permits us to provide high-performance, cost-effective services to a valued client while also allowing us to maximize the value of our HHI rigs.

Adjusted EBITDA for the second quarter was $10 million, down from $28 million in the combined first quarter. Capital expenditures for the second quarter were $55 million compared to $33 million in the combined first quarter, and we had contract-specific projects, most notably on the Noble Lloyd Noble.

I'd like to now provide a few financial data points related to the Pacific Drilling acquisition. Firstly, we are on track to achieve our run rate of $30 million in annual synergies by the end of the third quarter, which is ahead of schedule. Secondly, in late June, we completed the previously announced disposal of the Bora and Mistral. Together, the sales netted approximately $30 million in cash proceeds and will eliminate approximately $10 million in annual stacking costs for those rigs. Moving quickly to dispose of these rigs was the right economic decision for our shareholders.

Thirdly, we ended up receiving just over $50 million in cash from Pacific Drilling at the closing of the transaction in April. And lastly, we are actively evaluating options for reducing stacking costs for the Meltem and the Scirocco, which remains stacked in Las Palmas. Stacking costs for these rigs currently are approximately 40,000 per day for the 2 weeks combined.

Noble remains committed to capital discipline. We will not begin a reactivation of the Meltem or the Scirocco without an appropriate contract that would justify the required capital investments. In summary, we have managed to exceed our original expectations on several important Pacific Drilling-related transaction assumptions, and it serves to highlight the benefits to all parties of executing on an efficient and timely integration.

Moving to our balance sheet and capital structure. Our total liquidity at June 30 was $636 million, including $161 million of cash and $475 million of availability under our credit facility. At the end of the quarter, we had $119 million borrowed on a $675 million credit facility and $216 million outstanding on our second lien notes. While our second lien notes include a PIK toggle feature, we have submitted our election to pay cash interest at the upcoming interest payment date on August 15.

Now turning to our 2021 outlook. There were no changes to the guidance we provided in June. Our revenue estimate for the full year 2021 is between $900 million and $920 million, adjusted for the noncash amortization of contract intangible assets. And we are guiding adjusted EBITDA for the full year in a range of $120 million to $130 million. We anticipate full year capital expenditures to range between $180 million and $200 million, which includes amounts to be spent on the Noble Lloyd Noble as it prepares for work in Norway, approximately $30 million for rebillable CapEx that will be fully reimbursed by our customers as well as CapEx related to our newly acquired rigs from Pacific Drilling. While we are not providing formal capital expenditure guidance for 2022 at this stage, we do currently expect our capital expenditures to come down to a more sustaining-type level, which is approximately $120 million to $130 million for our current fleet.

From a cash flow perspective, we expect to receive a couple of onetime, tax-related cash inflows in the second half of 2021 that total just under $40 million. Firstly, we expect to receive a cash tax refund of approximately $24 million latest foreign tax credits. Secondly, we expect to receive the remaining portion of the CARES Act tax refund of approximately $15 million.

Our team is doing a great job integrating Pacific Drilling and being able to achieve the synergies without sacrificing the commitment to providing safe and efficient operations for our customers. We are also starting to get some help on the revenue side. As Robert mentioned, we are encouraged to see the pipeline of industry opportunities turn into contracts through the first part of this year. We are pleased to have signed several contracts and expect to be able to report improving financial results as we move through the remainder of this year.

In addition to these new contracts, our financial results will receive a meaning boost from the improvement in floater dayrates and the commencement of the Noble Lloyd Noble contract with Equinor. We currently expect to start generating positive free cash flow by early 2022.

That concludes my prepared remarks, and I'll now turn it back to Robert.

Thank you, Richard. We are excited about our future. Our industry does continue to face challenges, and we'll see a lot of change over the next few years. However, oil and gas will remain a major component of the world's energy mix. And since our beginnings 100 years ago, Noble has been an important part of the energy value chain, providing access to resources that power the world. Noble supports a sustainable energy future through our operational efforts to protect the environment and to safely deliver reliable and efficient drilling services.

Doing our part, we are pursuing a number of strategies to reduce our fuel consumption and emissions, such as power plant optimization and installation of selective catalytic reduction systems. We are also modifying the Noble Lloyd Noble to accept shore power as an alternative to running onboard engines.

The acquisition of Pacific Drilling has proven a great deal for Noble. And I'm pleased that we've delivered on the economic rationale by signing several new contracts on those rigs at improving dayrates, while moving expeditiously on the integration, as Richard described. Additional consolidation is essential for our industry and will not only provide meaningful cost synergies to the participants but also allow the best companies to offer a broader range of services and solutions to more customers.

We have accomplished a lot in the past several months. Our balance sheet has strengthened. Our fleet is enhanced with new high-spec assets, and our cost structure has improved. We accomplished all of this while maintaining our focus on delivering safe and efficient operations to our customers and while facing the substantial challenges posed by COVID.

Importantly, we currently expect to generate meaningful cash during calendar year 2022. But we have more work to do. We will continue to push in each of these areas to improve on where we are today, and I'm confident that our efforts will lead to many years of sustained success for Noble.

Thank you for your participation in our call today. And I'll now turn it back to the operator for Q&A.

(Operator Instructions) And your first question comes from the line of Greg Lewis with BTIG.

Robert, I was hoping you could talk a little bit about what's going on in the jackup market. It's interesting and maybe I'm dating myself, but it seems like historically, oil prices get going, the jackup market kind of leads the drilling recovery and then the floater market tends to follow. You're kind of mentioning some certain dynamics. But I guess what I would say is if traditionally, the floater market kind of follows the jackup market by 6 to 12 months, are we just looking at the reverse of that? Or really jackups are clearly important to use? So when do we think we can start to see maybe the jackups play catch up just given the fact that we're in this pretty attractive oil price environment?

Sure. Yes. It's a good question, Greg. And I agree with you. Typically, we'd expect to see improvement in the jackups first. I think part of the answer lies in the amount of volatility the industry has seen over the past few years. And so we had this extended downturn, then we had the jackups recover first as anticipated. And then in late '19 and early '20, we saw the floaters following, again, as anticipated. But then with the COVID disruption, I think it's just thrown things off a little bit from the norm.

Some of what we're seeing just on the floater side is pipeline of work that kind of built up and was delayed from COVID. So all that's working through the system right now. I think there was probably a little bit less of that on the jackup side. So you're seeing it a bit topsy-turvy going through 2021. But to kind of the broader question about when for jackups, I think we've also reached a point through the -- if you think back to 2015 and when -- in 2016 when the downturn really started, we've seen a ton of attrition on the floater side and we're seeing some attrition on the jackup side.

And so our view is that you have a -- you have so many different jackup operators, and you have a very powerful, largely NOC clients that it's a difficult -- it's a more difficult sector to rebalance. And it's cheaper to keep a jackup for option value than it is a floater. And you have a lot more players and smaller players and very importantly, some very capable regional players that are competing in that sector. And I think that as we've moved through this downturn that we've reached a point on the jackup side where all that's kind of converging, and we're seeing this somewhat flattish outlook. So we do see demand increasing gradually there, but I think the attrition story is a more difficult one on the jackup side than the floater side.

What we would anticipate and that we're hoping for here perhaps in '22 or late '22 is that we start to see the harsh sector -- the harsh jackup sector improve first. That's what we have seen in the past. We can see some tightening in the North Sea perhaps. Certainly, Norway is a unique market. But with the restricted supply there, things can move quickly.

So for me, at least, I think kind of an early sign there is when we see the kind of the most difficult jackup region start to improve and then perhaps see rates follow elsewhere from there. But for us, that's not a -- we just can't do that in 2021. And so we're calling really for things to be stable but probably not big growth drivers even going through 2022 right now.

Okay. Great. And then just one more for me. So more of a technical drilling question around -- well not even that. Around customer demand. Like, I mean, clearly, there's been some contracts that we've seen in Gulf of Mexico with managed pressure drilling. I realize the Santana Ana has dual grading and drilling. Are we -- do we -- like is there any way to kind of like split up the mix of type of drilling activity that's going on? And really, I guess my question is, is MPD really gaining momentum? And is that becoming the standard? Or is it kind of -- hey, it's happening, but it's still kind of -- it's less than more in terms of what we're seeing for like future contracts across the Golden Triangle.

It's a good question. So MPD is gaining momentum. And it's not standard kit at all. But in certain regions, it's something close to that, depending on downhole characteristics. It's a useful tool. It's not necessary or even helpful for every well out there, but there's -- there are a lot where it is helpful and it's a safe tool to have employed.

So we have -- we'll have 6 units in our fleet. Actually, we're changing the Santa Ana over from dual gradient to a more traditional MPD setup. And so most of what we have -- I guess, one came with the Pacific purchase. We bought one several years ago, which is the one that will end up going on the Santa Ana. Everything else we have in the fleet actually was customer funded. And so I think that is important in that it speaks to the value in certain applications for customers.

They're not going away and customers are willing to pay. There's a market rate for them on the dayrate side. And there's also a willingness to fund the equipment themselves for certain applications. So it's important. I recognize it creates some noise in market rates, and we see the same thing. But I think you'll continue to have a mix, some rigs with, some rigs without.

Our next question comes from the line of [Frederick Stein] with [Clarksons Ploughpo SEC].

[Frederick] here, and nice to have you back in the roster and opening up for Q&A. Really appreciate that. So I think you were thorough on your market view and kind of your thoughts about the market, which is always helpful here. But I have 2 questions or maybe 3 actually questions for you. If you start with the M&A side. Your name has come up with -- in certain news articles around Seadrill, Diamond, et cetera. And of course -- and I know you can't comment specifically on kind of rumors, et cetera. But I was wondering if anything had changed in your, call it, your take on this M&A role when it comes to what would fit into your own fleet? Or are you still going to target high-spec floaters and jackups if you would like to do more M&A? Or are you thinking kind of above and beyond that, for example, more Norway exposure? Or anything you are able to say around that would be very helpful.

Sure. So I'll start by stating the obvious that they're looking at a lot of different things, and that we'll always be focused on what's in the best interest of our shareholders. We have said and we believe -- we have an extremely high-quality fleet right now. Fleet quality matters for us. We like and think that we add a lot of value, particularly in the benign deepwater segment.

But we also like our jackups. And we think, particularly our JU3000 class in the CJ70, that's heading to Norway, compete quite well in the marketplace and provide us some important scale. So I can't say that we're ready to give anything a whole lot -- more definitive than that. We are focused, very focused on synergies. And I think that when you look at how fragmented the whole industry is today, I think that will remain a meaningful component of any analysis for quite some time. But through synergies and the associated scale, we do think there are a number of different opportunities that take -- will take different forms, but a number of different opportunities that can allow us to expand our service globally to more clients.

We're really pleased with the Pacific acquisition and the way that's gone post. And I think that demonstrates some bias towards drillships there. But outside of that, I'm not sure there's a ton more color. I guess I'll add, [Frederick], since -- Norway, we've been very open about saying that we have one rig going into Norway. And I think that could be a platform for additional growth if the right opportunity comes up. But it's not something that we're focused in or think that we have to grow.

Okay. And that's very helpful talk and understand that you can't dive into too much specific here. Just 2 other quick ones here. For the 2 rigs being -- or Pacific rigs that are stacked right now, are you bidding those into any tenders at this point? Or are they just stacked?

To answer your question there, they're just stacked right now. Well, first of all, so much has happened in the past couple of months, not only with our story but also more broadly in the industry and with rates moving so quickly, a ton of contract announcements out there. But we've only owned those rigs for a couple of months now. So some of the longer-term stuff out there, we didn't -- we couldn't have bid those.

But I will say, we've not -- we definitely haven't seen anything that piques our interest or would justify reactivation on those today. We've promised to be disciplined. And so the base case for that means that we would make our money back and make a return on our money to get those back into the marketplace. And we haven't seen anything like that. So the really short answer is that at present, we're watching, but that -- we don't anticipate that to be any sort of near-term announcement.

Okay. Perfect. And just another quick one here before I jump off. It's -- for the Exxon rigs here and the dynamic there, the rate at which -- or the rate at which -- or the rates that they set at March and September, do you benchmark that towards a specific region, such as the U.S. Gulf of Mexico, which is geographically closed? Or is it a more global approach?

Yes. So it's -- the way it's set up, it's supposed to be a rate -- then current rate that a rational drilling contractor, such as ourselves or one of our competitors, would bid for a 6-month job in Guyana. So that's intended to take into account any particulars that may develop about Guyana specifically. But I think a good proxy for Guyana right now is the U.S. Gulf of Mexico. And I recognize that there's a bit of a spread between U.S. Gulf today and rest of the world. The actual rate is not targeted at U.S. Gulf of Mexico rates specifically. It's targeted to Tier 1 drillships, so to BOPs, et cetera, like drillships. But it's technically set up to be where would we or one of our competitors bid that work for 6 months in Guyana at that moment.

(Operator Instructions) And there are no further questions at this time. I would now like to turn the conference back over to Craig Muirhead for closing remarks.

Thank you, everyone, for your participation on today's call and your continued interest in Noble. And Rebecca, we appreciate your time coordinating today's call as well. Good day, everyone.

Thank you for participating. This concludes today's conference call. You may now disconnect.