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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Thank you for standing by, and welcome to the Noble Corporation Second Quarter 2021 Results Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. [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'll 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 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 and also, keeping our employees and business partners’ safe offshore.
Last year, we had exceptional safety and operational performance breaking the 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 have 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 will speak more on our strategy later, but let me begin my prepared remarks today by addressing the floater in jackup markets. The 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 three new contracts which address that priority. This additional work adds approximately a 180 operating days to the fleet prior to any exercise of options and has a cumulative total contract value of over $55 million, including associated mobilization fees and customer reimbursed rig upgrades.
First two new contracts are for the Pacific Khamsin and further build-out its 2021 and 2022 drilling schedule. The rigs previously announced one-well campaign for Petronas in Mexico is expected to conclude in early fourth quarter of this year. Today, we are excited to share that the Khamsin is now contracted to return to the 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 as the Khamsin remaining in the U.S. Gulf following Murphy to drill one well for EnVen, who has three subsequent price options for 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 and Mauritania in August, and I'm pleased to announce the new contract award with APA Corporation in Suriname. That contract is for one well plus two one well options and it 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 back these high-spec assets to further serve Noble's existing customer base. I am 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 has seen a five-fold increase in contract fixtures in the region with almost five 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 two 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, the 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 up the coast, we see activity in 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 four rigs working in Guyana and the addition of the Santa Ana early next year, will bring our fleet to five 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 Guyana, 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 are 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 Guyana for 2022 starts as well as some short-term high-spec floater work in Guban.
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 newbuilds, 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 rig commissioning in mobilization. While we think market dynamics and capital constraints will limit the delivery of these rigs in the near-term, we recognized 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. 2021 has been strong, especially for UDW and 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 recognized 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 the 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 in 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 early stages of past market recoveries, fixture durations are still primarily short with most tenders being well-based and requesting options, but dayrates are definitively increasing driven by constraints on the incremental supply posed by capital availability and cost. We expect dayrates to continue to trend higher in every region and eventually contracting term to increase as well.
Turning now to the jackup market. Activity levels across the North Sea jackup sector remained steady and moderate number of new fixtures and requirements continue to reach the market with new work emerging for 2022. Today, two of our four jackups in the UK and Dana sectors are working with two 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-spec jackups in the world and particularly well suited for work in Norway. We are proud to have Equinor's trust as we enter that unique environment and I am 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 one-year option for the Noble Mick O’Brien, which will keep the rig contracted into September 2022. More broadly across the Middle East, there was a respectable volume of contract award 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, 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 are happy to report today that it has been awarded an additional three 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 on May 7.
The quarterly increase is related to the addition of the Pacific Drilling rigs to our fleets 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 will 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 non-cash amortization of contract intangible assets specific to the two Globetrotter rigs. For similar reasons, our contract drilling costs were higher in the second quarter as we prepared rigs to go to work and absorbed the cost of the newly acquired Pacific Drilling rigs.
The Noble Lloyd Noble experienced an increase in operating expenses during the quarter, as we readied the rigs for entry into Norway and its upcoming contract with Equinor. Additionally, as Robert mentioned, we mobilized the Noble Sam Croft during the second quarter from its previous contract in Suriname to its current drilling location in Guyana. This is our fourth rig working for the same customer in the same country.
Our work with ExxonMobil in Guyana, it governs by the CEA, which provides unique, meaningful benefits to both our customer and to Noble, including significant operational efficiencies of having four extremely similar rigs operating in the same region and the security of supply.
Importantly, we experienced strong utilization over a multi-year period without realizing downtime between contracts, while Exxon benefits from having access to 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 will reset the market March 1 and September 1 each year in a manner that reflects dayrates for a six-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 six-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 as 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 the stacking costs for the Meltem and Scirocco, which remained stacked in Las Palmas. Stacking costs for these rigs currently are approximately 40,000 per day for the two rigs combined. Noble remains committed to capital discipline. We will not begin the reactivation of the Meltem and Scirocco without an appropriate contract that would justify the required capital investment.
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 our $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 with the guidance we provided in June. Our revenue estimate for the full-year 2021 is between $900 million and $920 million adjusted for the non-cash 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 available CapEx that we fully reimbursed by our customers as well as CapEx related to our newly acquired rigs in 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 for more sustaining tight level, which is approximately $120 million to $130 million for accounting.
From a cash flow perspective, we expect to receive a couple of one-time 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 related to 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 of 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 meaningful boost from the improvement in floated 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, a 100 years ago, Noble has been an important part of the energy value chain, providing access to resources, the power of 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 is 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 am confident that our efforts will lead to many years of sustained success from 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.
Yes. Thank you, and good morning, everybody.
Good morning, Greg.
Hey, 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 the oil prices get going. The jackup market kind of leads the drilling recovery and then the floater market tends to follow. I mean, you've kind of mentioned some certain dynamics. But I guess what I would say is if traditionally the floater market at time that follows the jackup market by six to 12 months. Are we just looking at the reverse of that? Or really jackups are clearly important to you? So when do we think we can start to see maybe the jackups might 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 an 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 2019 and early 2020, we saw the floaters following again as anticipated. But then with the COVID disruption, I think it's just certain things off a little bit from the norm. Some of what we're seeing just on the floater side is a 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 that – if you think back to 2015 and 2016 when downturn really started, we've seen a ton of attrition on the floater side and we've seen 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. 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 whether 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 2022 or late 2022, is that we start to see the harsh sector – the harsh jackup sector improved 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 in a – kind of an early sign there is when we see the kind of the most difficult jackup regions start to improve and then perhaps see rates follow elsewhere from there. But for us that's not a 20 – we just can't see 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. Certainly, more of a technical drilling question around or not even around customer demand. Like, I mean, clearly, there's been some contracts that we've seen involved in Mexico with managed pressure drilling. I realized that the Santa Ana has dual gradient drilling. Is there any way to kind of 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 it’s kind of – hey, it's happening, but it's still kind of – it's a 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 downhaul characteristics. It's a useful tool. It's not necessary or even helpful for every well out there. But there are a lot where it is helpful and it's a safe tool to have employed. So we'll have six units in our fleet, actually we're changing the Santa Ana over from dual gradient to a more traditional MPD setup. And the most of what we have – so I guess one came with 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 and it speaks to the value and certain application 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.
Okay. We’ll start to push [indiscernible]. Hey, thank you very much for the time.
Very good. Thanks, Greg.
Your next question comes from the line of Fredrik Stene with Clarksons Platou Sec.
Hey guys. Fredrik here, and nice to have you back in the roster on the opening up for Q&A. Really appreciate that. So I think you were thorough on your market view and on kind of your thoughts about the market, which is always helpful here. But I have two questions or maybe three extra 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 then, of course, and I know you can't comment specifically on the kind of rumors, et cetera.
But I was wondering if anything had changed in 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 narrowly exposure or anything you are able to say around that would be very helpful.
Sure. So I'll start by stating obvious that they're looking at a lot of different things and that will always be focused on what's in the best interest of our shareholders. We have said and we believe, we have 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 that we're ready to give anything a whole lot more definitive than that. We are 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 will take different forms, but a number of different opportunities that can allow us to expand our service globally to more clients.
And we're really pleased with the Pacific acquisition and in 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 Fredrik, Norway, we've been very open about saying that we'll 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 and think that we have to grow.
Okay. And that's very helpful [indiscernible] into too much specific here. Just two other quick ones here, for two rigs being more specific rigs that’s a spec right now, are you building those into any tenders at this point? Or are they just specs?
That's a good question. 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 already owned those rigs for a couple months now. So some of the longer term stuff out there, we couldn't have had bid those. But I will say, we definitely haven't seen anything that peaks 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 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. For the Exxon rigs here and the dynamic there, the rate at which or the rate that they set at March and September, do you benchmark that towards a specific region such as the U.S. Gulf of Mexico, which geographically close? Or is it the more global approach?
Yes. So the way it's set up, it supposed to be a rate then the current rate that a rational drilling contractor such as ourselves or one of our competitors would bid for six months 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 [indiscernible] et cetera, like drillships. But it's technically set up to be where would we or one of our competitors bid that work for six months in Guyana at that moment.
Okay. That's very helpful. Thanks, guys. That's all for me at this time. Have a good day.
Very good. Thank you.
[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. 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.