Thank you for standing by. My name is Eric, and I will be your conference operator today. At this time, I would like to welcome everyone to the Seadrill Fourth Quarter 2023 Earnings Release Call. I would now like to turn the call over to Lydia Mabry, Director of Investor Relations. Please go ahead.

Thank you, operator. Welcome to Seadrill's fourth quarter and full year 2023 earnings call. With me for the call today are Simon Johnson, our President and Chief Executive Officer; Grant Creed, Executive Vice President and Chief Financial Officer; Samir Ali, Executive Vice President and Chief Commercial Officer; and Marcel Wieggers, Senior Vice President of Operations. Today's call may include forward-looking statements that involve risks and uncertainty. Actual results may differ materially. No one should assume these forward-looking statements remain valid later in the quarter or year, and we assume no obligation to update them. Our latest Forms 20-F and 6-K filed with the US Securities and Exchange Commission provide a more detailed discussion of our forward-looking statements and the risk factors affecting our business. During today's call, we may also refer to non-GAAP measures. Reconciliations to the nearest corresponding GAAP measures are in the earnings release filed with the SEC and available on our website, seadrill.com/investors. Our use of the term EBITDA corresponds with the term adjusted EBITDA as defined in our earnings release. Now let me turn the call over to Simon.

Thank you. Today, I will address our recent accomplishments, near-term positioning, and future potential. Samir will then discuss our commercial activity and outlook. And Grant will review our financial results and 2024 guidance. Then we will open the call to questions. Seadrill is a leading offshore driller. We consistently execute on our stated strategy, achieving financial and operational results that allow us to deliver industry-leading total shareholder returns relative to our offshore floater peers. We were the best-performing equity in the peer group in the 2023 calendar year. We've bought back over $340 million worth of Seadrill shares through our ongoing repurchase program. Throughout the year, we continued our efforts to simplify and strengthen our business. We operated a modern floater-focused fleet concentrated primarily in the golden triangle. We achieved minimum efficient scale through our Aquadrill acquisition, adding four drillships with near-term contracting exposure. We secured leading-edge contracts for term work and are announcing two major Brazil awards, representing $1.1 billion in firm revenue at rates our peers would envy. We followed that with another announcement of a benchmark rate in late January for the US Gulf of Mexico. We have long telegraphed and prepared for headwinds in 2024, first calling attention to them on our second quarter 2023 earnings call. Our trade rivals seem to be recognizing varying degrees of emerging supply chain pressures and inflationary capital expenditure and OpEx trends in 2024. At Seadrill, we continue to manage and mitigate the impact these trends may have on our operational and financial results. We aim to secure the right contracts for the right rigs in the right place at the right rates. For example, we are moving the West Polaris to a term contract in Brazil, a growing market for the industry and a key operating region for Seadrill where we've costed rigs and benefit from economies of scale. We made early decisions to implement wage increases and retention programs, securing talent that's critical to our continued delivery of safe, efficient operations. We invest in our drilling crews’ continued development, providing high-fidelity simulator-based training programs that allow them to practice and prepare for real-life scenarios in an immersive classroom environment. We maintain an active dialogue with key vendors on supply chain requirements and realities, proactively ordering long lead time items to minimize schedule risk and improve our ability to recover from unplanned events. Lastly, to the extent we are able, we've begun performing special periodic surveys and related work on an accelerated schedule to limit the interruption to our fleet's revenue profile and coincide with a broader transition year. We're commencing a transition to a more continuous approach to required reclassification in the coming years. Going forward, we anticipate that we will see less time out of service for five-yearly surveys. For 2025, we continue to derisk our outlook and build greater earnings visibility through term contracts and optimized maintenance schedules. Our active fleet is now over 60% contracted for the year 2025, and that number will rise higher as we approach recontracting windows. Additionally, reduced maintenance obligations limit future out-of-service days and related impacts on revenue and margin. We remain steadfast in our belief in a long enduring offshore drilling upcycle as the world's population continues to grow in both size and wealth, so too will the attendant demand for hydrocarbons, which remain some of the most economic, efficient, and reliable sources of energy. Increasingly, we expect offshore will be the source of supply for rising oil and gas demand, given the size and strength of its reserves, though rig supply remains constrained as most industry participants express reluctance to reactivate the idle inventory of stacked assets until customer terms and contract economics justify the time and capital investment needed. The resulting delta between supply and demand reaffirms our view that this will be a multiyear cycle. We're not alone in this, as third-party analysts expect drillship demand to increase by nearly 20% in 2025 compared to 2023. At the firm level, we believe our ability to maintain a strong balance sheet and generate healthy cash flow allows us to withstand near-term adversity and capitalize on mid to longer-term opportunities that will develop as the cycle progresses, creating continued value for our customers and shareholders. Based on current market conditions, we believe we can deliver meaningful expansion in free cash flow generation from our existing business in 2025 and beyond. Let's elaborate on what that might look like in four simple steps using high-level estimates and round numbers. So let's begin with 2023 reported EBITDA of $495 million. First, 2023 actuals only included nine months of Aquadrill contribution; future results will benefit from the full year. Second, we're on track to deliver our stated synergies of $70 million of value per year concerning the Aquadrill transaction, largely associated with the elimination of third-party rig management fees. As many of you are aware, legacy Aquadrill was more of a rig owner than an operator, subcontracting drillers to operate rigs on their behalf. When we acquired the company, we acquired those contracts effectively paying industry competitors to perform a job we do ourselves every day. As the rigs transition to new contracts through 2024, we will eliminate those management fees and see immediate bottom line impact. Third, repricing near-term contracts to market rates supports further EBITDA expansion. The West Polaris will see meaningful EBITDA improvement when it moves from India to its new leading-edge contract in Brazil at the end of the year, despite India being a much lower cost operating environment. Finally, repricing should become particularly impactful when we mark to market our three rigs we currently operate in Brazil on long-dated legacy contracts booked in the fourth quarter of 2022. These three rigs have a current average disclosed day rate of just over $250,000 per day. Were they to secure contracts at rates similar to those awarded to the West Auriga, they would earn nearly twice as much revenue and, assuming costs remain the same, approximately $250 million more in annual EBITDA. Should the market improve as we believe it can, that number could be even higher. So bringing this together, you can see how we can materially improve from our 2023 baseline. We believe this level of EBITDA expansion and resulting cash flow generation is both reasonable and realistic. We should soon benefit from a full year's contribution from the legacy Aquadrill fleet and the elimination of third-party rig management fees, and we will continue to see the impact of near and longer-term repricing as rigs roll off existing contracts. We remain confident in the value we can create in the coming years. We actively manage our business in a way that reflects tomorrow's realities and tomorrow's opportunities, which Samir and Grant will discuss in more detail. With that, I'll turn the call to Samir.

Thank you, Simon. I'll review our recent contract awards and then walk through our fleet status, providing a Seadrill-specific market outlook. Since we last spoke during our third quarter earnings call, we have secured approximately 80 months or 6.5 years' worth of additional backlog across four drillships at an average day rate close to $475,000 per day. These awards are a testament to the strong brand and industry-leading team at Seadrill. In December of last year, as part of the busiest tender, Petrobras awarded both the West Auriga and the West Polaris multiyear contracts for offshore Brazil, representing $1.1 billion in combined contract backlog. We expect the contracts to commence in late 2024. Notably, the West Auriga represents one of the highest day rates achieved thus far in the cycle by any industry player, with an implied day rate of approximately $500,000 per day. In January, we announced another market-leading rate, this time in the US Gulf of Mexico. The West Vela secured a 150-day contract with an implied day rate of approximately $490,000 per day, excluding managed pressure drilling services. We expect the work to commence in direct continuation of the rig's existing firm term contracts, securing the rigs in the US Gulf of Mexico through the middle of next year. Lastly, the operator of West Capella exercised a priced one-well option valued at $24 million to maintain her for their current program. While we anticipate the option would carry the Capella through November, recent changes in the client's well schedule means she will only be working through August. Unlike firm term contracts, well-based agreements may move to the left or the right depending on drilling programs and schedules. As of today, our 2024 contracted utilization is a solid 80%, excluding three cold stacked rigs, which we market selectively. We currently have 39 months of uncontracted rig time across our fleet for the calendar year 2024. Scheduled maintenance should consume approximately seven months' worth of idle time, with five rigs requiring varying amounts of out-of-service time based on our current plans. Contract preparation could consume an additional 17 months, largely related to our two Brazil contract awards I mentioned earlier. We are actively looking to secure work for the remaining 15 months. The Sevan Louisiana is currently undergoing five-year maintenance through the first half of March after completing her well-based contract earlier and effectively drilling herself out of work in December of last year. The Louisiana is one of the last remaining semisubmersibles in an increasingly bifurcated US Gulf of Mexico. She competes in a smaller secondary segment focused on lower-priced and more niche applications. We continue to market her actively in the US Gulf and further abroad. While we don't have anything to announce today, we remain optimistic about her contracting potential. Turning to the two rigs that were awarded contracts in Brazil, both the West Polaris and the West Auriga require significant modifications, mobilization, and intake and acceptance by Petrobras and regulatory agencies before they begin their new contracts at year-end. So while the rigs are technically available to work now, the opportunity to slot in short-term work is limited as any delays could jeopardize the rig schedule arrival offshore Brazil. We anticipated meaningful white space was a possible outcome when we pursued these contracts. Securing fifth and sixth rigs in Brazil strengthens our already leading position in the local market and enhances our economies of scale. We expect the West Phoenix, our harsh environment semi in Norway, to finish its well-based contract in August. The rig will require a shipyard stay for upgrades and maintenance before she begins her next contract, and her destination market will influence the type and level of investment made. The Phoenix will be the first floater available in the Norwegian market. While we remain optimistic about our contracting prospects, we expect any potential future work will not start before the second quarter, as North Sea operators typically wait until spring to begin drilling programs. As previously stated, we now expect the West Capella to end its current contract in August, subject to well schedule. She is one of the few available rigs in Southeast Asia. Additionally, she is equipped with Managed Pressure Drilling. Given recent discoveries in Indonesia and elsewhere, we are confident we can secure further work for the rig soon. Lastly, we expect the West Neptune to be out of service for 45 days in the third quarter for a special periodic survey and upgrades scheduled between wells on its existing contract in the US Gulf of Mexico. That concludes my walkthrough of the Seadrill rig fleet. We expect to provide more insight on our 2025 contracting outlook the deeper we get into the year. Lead times for future contracts vary by region from six to 18 months depending on geography. In some regions, customers are initiating conversations for projects with start dates in 2026 and beyond. In others, they're not even yet discussing the fourth quarter. In either case, we believe we are well-positioned to secure the right contracts to generate the earnings potential Simon alluded to earlier. And with that, I'll pass the call to Grant.

Thanks, Samir. I'll start by reviewing our recent financial results before providing our full-year guidance. For the full year 2023, we delivered $495 million of adjusted EBITDA on $1.5 billion in revenue. This translates into an industry-leading EBITDA margin of 33%. Turning to the fourth quarter, adjusted EBITDA was $100 million, consistent with expectations as our 2023 full-year guidance implied softer fourth quarter EBITDA of $90 million to $110 million. Total operating revenues were relatively flat quarter-on-quarter at $408 million. We recognized $315 million in contract revenues, a slight decline from the prior quarter, primarily due to unplanned downtime related to well control equipment and the Sevan Louisiana finishing a well-based contract earlier than anticipated. We recognized an additional $73 million in management contract revenues, which represents income generated from the three rigs we operate as part of our Sonadrill JV. The $5 million sequential increase reflects higher reimbursable revenue relating primarily to rig maintenance that was offset by a corresponding increase in management contract expenses. Lastly, we recognized $14 million in other revenues, which includes bareboat charter income from our Gulfdrill joint venture and $6 million in reimbursables, which is offset by corresponding reimbursable expenses. Now, turning to expenses. For the fourth quarter, vessel and rig operating expenses were up $36 million sequentially, primarily composed of three components. Non-cash accruals represented $15 million, and much of the remaining $21 million was distributed relatively equally across two primary categories. The first category was planned maintenance projects and capital spares purchases, which was heavily related to timing. The second was rig personnel. Fourth quarter results include the impact of pay rises and retention programs, reflecting a tight labor market and inflationary environment. Additionally, we saw third-party managers on legacy Aquadrill rigs use temporary contract labor to fill crew vacancies. SG&A costs were $6 million higher than the prior quarter, primarily related to severance. Moving on to the balance sheet and cash flow statement. We maintained a strong balance sheet and sound capital structure. At year-end, we had total gross debt of $625 million and $697 million in unrestricted cash resulting in a net cash position of $72 million. Fourth quarter operating cash flow totaled $140 million on the back of solid earnings and supported by a reduction in working capital. Capital expenditure for the fourth quarter totaled $90 million, divided almost equally across long-term maintenance costs, which, for your awareness, are treated as operating cash flows in the cash flow statement, and capital upgrades related to contract preparation and incremental equipment spend. This was slightly higher than previously guided on our third quarter call due to the need to secure long lead items for the Auriga and Polaris projects. This yielded free cash flow of $92 million for the quarter. Now let's discuss our guidance. Our full-year guidance reflects our expectations that 2024 is a transition year. We expect total operating revenues between $1.47 billion and $1.52 billion. Guidance largely reflects firm revenues, including 92% of contract drilling revenue already secured in our backlog, as well as the fleet status and outlook that Samir reviewed earlier. We anticipate adjusted EBITDA to be $400 million to $450 million. Key points to note are extensive contract preparation and mobilization of the West Auriga and the West Polaris ahead of the Brazil contracts, and planned out-of-service time related to special periodic surveys and associated maintenance. Note that our revenue and adjusted EBITDA guidance includes amortized mobilization revenues and expenses of approximately $40 million and $45 million respectively. It also includes reimbursable revenue and expenses of approximately $70 million. And as a reminder, reimbursables are low-margin revenues. Finally, we expect CapEx of $400 million to $450 million. This reflects a spike in our SPS cycle as well as major projects for the Auriga and Polaris, which are due to commence long-term campaigns towards the end of the year. As it relates to capital allocation, we remain committed to shareholder returns; the pace at which we've bought back our own shares certainly demonstrates this. We initiated a $250 million share repurchase program in September. We completed it by November, and in December, we expanded it by an incremental $250 million. To date, we have repurchased $342 million worth of Seadrill shares at what we believe is a highly accretive price level. This represents 11% of our total share capital. We remain committed to continued value creation across the cycle. Back to you, Simon.

Before we open the call for questions, I want to thank our employees for their continued contributions to our progress. As you're aware, we are closing our corporate office in London and concentrating our headquarters in Houston, bringing together our senior leadership and broader corporate team and aligning our presence with key customers, vendors, and fleet operations. This move marks another transition this calendar year. We're excited about the energy and enthusiasm that being together will create. To our London team, thank you for your efforts to strengthen our organization during your tenure. For those who will make the move to Houston, thank you for your continued commitment to Seadrill and interest in making us one of the best in the industry. So in closing, to all of our employees, suppliers, and customers, thank you for your engagement and ideas as we consider how we can be more collaborative, efficient, and responsive in our daily operations. It's through our combined efforts that we will continue to improve. With that, we can open the call for questions.

Your first question comes from the line of Ben Nolan with Stifel.

This is Frank Galanti on for Ben. In the past, you had talked about renegotiating the existing contracts early for the couple of assets in Brazil with Petrobras. Can you provide us an update on where that stands?

I don't think we had said previously we'd renegotiate them, but we are definitely looking to recontract those rigs in Brazil. I'd say we're starting to enter that window. In the prepared remarks, we have said certain markets are nearing the six months, certain markets are 18. I'd say Brazil is probably on the upper end of that range. So we are starting to have those early conversations with Petrobras and others about recontracting those assets. But as we get deeper into 2024, you should expect that to provide some more guidance about where we are on that recontracting for those rigs. I'd also say they're all Brazil-ready and they could stay in that market, but we're not opposed to moving them to other markets if required as well.

And so I wanted to sort of follow up on the CapEx; it's a pretty meaningful step-up in '24. But can you sort of talk about what goes into that number and really to sort of get visibility on what that number looks like on a go-forward basis in '25 and going forward?

Well, let me just kick off and then I'll pass to Grant to get into the numbers. But I mean, our CapEx is meaningfully higher next year because of the SPS intensity. And that is really a function of the delivery anniversary dates when these rigs were originally constructed. So we've been talking for many quarters now that this was coming at us; it was going to be a reality, and that we are planning for it to mitigate its impact. The key thing to understand is there are going to be more revenue days in '25 and '26. We're proactively doing maintenance where we have the opportunity to do that as part of contract preparation. We expect to be on materially higher average rates across the fleet in future years, and that's going to be the benefit of the work that we're doing now. But Grant will go into detail in terms of the quantum.

I will break it down into three categories: maintenance, SPS, and customer-specific requirements. Starting with the LTM, we have consistently stated that maintenance for one of our rigs costs between $20,000 and $25,000 a day, which for our fleet amounts to approximately $100 million to $120 million annually, and this will remain the same in 2024. Regarding SPS, we mentioned before that we have seven rigs undergoing SPS, excluding the Auriga and Polaris, which I will discuss shortly. Neptune and Louisiana will complete their full SPS cycles and associated downtime days, and you can expect full SPS costs for those. The Phoenix is included in the SPS category; while it's technically regulatory compliance work, it will be completed this year and will incur downtime as we transition off the Vela contract. For the four Brazil rigs currently in operation, Jupiter, Carina, Saturn, and Tellus, they have SPS work, but we are not scheduling out-of-service days for them; they will undergo continuous classing, as previously discussed by Samir and Simon. Finally, the numbers for Auriga and Polaris are included. It’s important to note that alongside the project for these rigs, we are also taking the opportunity to perform some SPS work and long-term maintenance.

Next question comes from the line of Greg Lewis with BTIG.

Simon, thanks for the guidance. As we consider what free cash flow might look like, I'm curious about your thoughts on the buyback given that this is a transition year. We still have some capacity available and a substantial amount of cash on the balance sheet. What are your thoughts on how the buyback will be implemented as we move into 2024?

Look, I think capital return is going to be at the heart of our proposition to the market in coming years. We have a facility in place that takes us through to at least the middle of this year. I think we're very mindful that a lot of people like our stock for that visibility and that commitment to delivering value to shareholders that can't be otherwise utilized in the ordinary business of the firm. So we think it's important, and we're somewhat unique in the space. We've got only one other major peer who's able to deliver in the way that we've been delivering. And yes, we think it's a great feature. But Grant, maybe you'd like to add some color.

I think as it relates to the buyback, it's important to say that we'll always assess the buyback at the point in time that we're making the decisions. We'll always have reference to our financial policy, and we've been through that on previous calls. But then just to recap very quickly, looking at where the market is, looking at leverage and liquidity projections, looking at maintenance of the fleet, including SPS's, then we look at any growth opportunities with a focus on accretive growth opportunities. In the absence of that, with excess cash and visibility with comfortable leverage and liquidity, we'll look to return capital to shareholders.

And then I was hoping for some color. I guess it's a two-part question on the Gulfdrill jack-ups. I guess, one, how are we thinking about or how should we be thinking about the impact on the guidance around those rigs? I know we've been exploring a potential sale since at least the back half of last year? And then beyond that, what's the appetite then realizing that the market is still digesting the news out of Saudi Arabia, considering these rigs are not in Saudi Arabia? That's kind of what I'm wondering.

Look, I think first of all, it's important to say that the reaction to the Saudi news has been disproportionate. The big takeaway for us is that growth outside the Kingdom of Saudi Arabia has been undervalued by market spectators. The opportunity is in Qatar, which is the biggest potential source of jack-up demand outside of Saudi Arabia, and it's been on everyone's radar. The Qatar market has also typically lagged activity in other market segments. We have a great position there with our joint venture partner. We believe that they have a preferred status in providing supply to that market. Thinking about the future there, we're happy to stay with those rigs. It doesn't occupy a lot of management bandwidth as we said before, and we'll be patient. If we choose to conclude a sale, it's going to be at terms that will be satisfactory to our shareholders. We don't feel pressured to speed up that sale process, and we're going to wait until we get the right buyer at the right price. We're obviously transitioning out of the jack-up segment; that's no secret. But we're going to be patient and rational in the manner we do that. We continue conversations with interested potential buyers, and when we've got some firm news, we'll come back and share that with the market, Greg. But at this point, we don't see any bad read across from the Saudi news. We think there's great news to come in terms of the Qatar market and the value of those assets in that market.

Your next question comes from the line of Fredrik Stene with Clarkson Securities.

I wanted to touch a bit on your contracting strategy. And as you said in your prepared remarks, you'll provide more color, particularly on 2025 as we move along. But as you're working through the opportunities that you're currently looking at, are you inclined based on your market view to chase short-term opportunities or longer-term opportunities? Do you have any preference in how you would like to lock in rates or if you would be bold and if they go even higher? That's kind of the first question I have.

I'd say both, right? So I think it's rig-specific, geography-specific. There are certain rigs that we're not opposed to chasing short-term work, but we do have some longer-term prospects that we're also looking at. For us, it's about being balanced and making sure that we're generating cash flow in the near term for some of our open capacity, but we're trying to box smart as well. So we're also looking at and being very surgical and strategic about where we place our assets. We're not just going to chase everything. We're going to look for the right work for the right rig. So a long way of saying, yes on both accounts. I've got some assets that will take short-term contracts, and then we've got some assets that we're waiting for that right opportunity to lock in a long-term rate. As you saw with the Auriga and the Polaris, we thought there would be some turbulence in the market, so we secured those. And there are some other shorter-term contracts in the Gulf of Mexico that we pursued and obtained high day rates for. We will be strategic about how we do it.

And just one more from me. On the West Phoenix, I think you said that side of contract work needs to be done, and it will probably not work until the second quarter next year. I got that right, right?

I think that's reasonable. I mean, for us, right now, she does roll off later this year. We do have some capital investment in depending on the market she goes to, that will drive that capital investment and her contract outlook. So I think we are working on a few leads right now, but realistically speaking, probably the drilling season of '25 is when she will pick back up.

As a follow-up on that, regarding the reach opportunities you are pursuing, will you need to have something clearly defined before you invest capital, or can you perform some preliminary work that must be done regardless, and then focus on contract-specific tasks? How do you plan to ensure that you will actually see a return on the cash you invest?

I spend a lot of time on this with the team. We will not invest a significant amount of capital unless we have a clear understanding of something. We are exploring a few options, but to justify a reasonable capital request, we need to have a clear vision, if not a firm contract, towards something.

Next question comes from Hamed Khorsand with BWS Financial.

So first question I had was, what type of conversation, if any, are you having with customers at this point as far as the rigs are concerned? Are you seeing pushback on the contract day rates, or is it really just more the customers or potential customers pushing back on their own timelines?

Hamed, maybe I'll kick off and then Samir can jump in. Look, I think your reference to the fact that rates have been tracking sideways a bit. I don't think that's so much of a function of some kind of structural resistance in the market. It's really more a reflection of the market absorbing some idle capacity from a short number of our active competitors. There's a declining inventory of those idle rigs now. I think the fact that the market has been able to absorb them well in the last couple of quarters gives a good indication of the potential for further development in the future. So we're not too worried about that. What I would tell you is that we still believe that the fundamentals are strong. The medium-term outlook is great for the rig business. We're seeing steady but continuous improvement in demand across a wide range of geographies. Really, that's what is going to drive the development of rates going forward, the growth in demand interacting with a relatively elastic supply of rigs. I think we recently saw one of our major customers take a position in rig ownership. That was a great signal for the market and for the contractor in question, who has unparalleled visibility in the revenue profile. What that indicates is potential for flexibility in the commercial bargain. Customers, in their bid to maintain costs at levels they deem acceptable, are having to be more creative in how they award contracts. That might mean they will commit more money upfront to defray CapEx challenges and assist contractors in that manner, as well as potentially providing near-term relief or long-term security of supply. So I think there's lots of things happening in the market. Overall, the trend is encouraging, and we continue to be optimistic about that. One last thing I'll say is that we're nowhere near the levels of customer demand that we saw at the height of the last cycle. We're roughly halfway through that regard. So as people think about the potential for where the market might go, they should reflect on what happened last time. With that, I'll pass it to Samir.

So we definitely see 2024 as the transition year. You saw a flurry of awards in the second half of last year. I think customers are just digesting now and going through it. Historically, if you look, Q1 has always been slower as well, so nothing terribly surprising. I think we saw this coming; that's why you've seen us make the moves we have. As we look at 2025, we continue to see the progression going. For us, none of this seems terribly surprising regarding where we are in the market.

And just given the downtime you're taking this year, any estimate on what the kind of downtime you would have in '25?

We haven't provided guidance for 2025 yet, but we have indicated that it will be significantly lower. We have several rigs undergoing surveys this year, which removes them from service and affects our ability to market them. We consciously planned to do much of this work this year due to that transition. However, you should expect a significant decrease in 2025.

And last question is on the Capella. Have you already started marketing the rig? And how is the market there as far as being able to get another contract as soon as possible?

So we started marketing the day we closed on Aquadrill. We've been actively having those conversations because part of our synergy capture was bringing those back in-house. Paying a third-party manager to do something that we can do doesn't make a lot of sense. We are doing that actively. In terms of when we could get something? She's on a well-based contract. You saw it slip. So it could move to the left or the right. We do have to transition back to ourselves as well. Really, that well-based contract will make it a little difficult to nail down a start window. But I can say we are in active dialogue with that rig and hope to announce something in the near term.

Your next question comes from the line of Kurt Hallead with Benchmark.

I had a follow-up question regarding the current demand, which is not at the same level as it was in the last cycle. I'm curious about what data or indicators journalists and investors, who are not immersed in the business as you are, can rely on to gain the same level of confidence you and others in the industry have regarding the notion that demand is still increasing and hasn't stabilized. This concern overlaps with what you've already shared about pricing dynamics. Since you deal with this daily, what should external observers look for to develop a similar confidence?

I believe that the rig market data has become less transparent compared to the past due to numerous direct negotiations and extensions. Many work programs are not visible even to market participants. However, we have other indicators of activity to consider, such as wellheads and Christmas tree orders, as well as seismic programs. A notable example was the 261 lease sale in December last year, where operators spent $382 million, marking the largest Gulf of Mexico sale since 2015. While this does not immediately result in drilling activity, these data points give us confidence in future prospects. We analyze the actions of other segments in the upstream business and how they relate to the rig days available in the market and supply. Most management teams in our peer group have experienced multiple cycles, and while there is a level of muscle memory, it is guided by solid underlying data which we thoroughly examine to draw conclusions about future developments. Having been in this business for nearly 30 years, I can confidently say that the current situation is one of the best I've seen at this point in the cycle.

So maybe on a follow-up to that, right, in the context of economics. We've seen a lot of third-party data that shows that ultra-deepwater projects in multiple basins generate 30% plus returns at $70 Brent and breakeven at $40 Brent and below, again, I've heard numbers lower for Guyana and Brazil, et cetera. Another setup here is that beginning some questions around how much pushback will the offshore drillers get on pricing improvement in the context of how that impacts overall drilling economics. So can you give us a refresher as when you think about the all-in spread rate for an ultra-deepwater rig, what is the percent of project economics that the rig represents?

Look, it's a difficult question to answer concisely, Kurt. The issue is that the operators have a wide variety of projects in their portfolios, some are near-term tieback opportunities that are much more driven by rig rate. Then you're looking at big multiyear field developments where the rig rate is relatively unimportant as a proportion of the total cost. Typically, the rule of thumb we use is that the spread rate these days is typically about $1 million a day, and with rig rates tracking as they are at the moment, close to $500 a day, we represent about 50% of that total cost mix, but it varies according to the project. What is more important than the rig rate is the operators' constraints in terms of their capital allocation caused by their desire to return money to their shareholders. That really becomes the more important matter rather than any sort of ultimate rate level. They're wanting to reward their shareholders, and some of our major suppliers are in a similar boat. As you've seen with our share repurchase agreement, we're also focused on that too. I haven't seen such synchronicity through the value chain in that regard. So when we're thinking about how our rates might drive activity, will demand get pinched out at some point? Conceivably, yes. But really, we're more focused on how these project economics stack up relative to the return profile that our principal customers are offering their shareholders. So yes, I didn't quite answer the question, Kurt, but hopefully, that gives you a bit of color.

I have one more follow-up. The other dynamic here is that when an oil company evaluates its future projects, they consider which rigs are available that meet their specifications. I assume that during the budgeting process, they're not just looking back at the potential cost of a rig. It seems likely that they're considering various price ranges and what they might be willing to pay. I doubt they're approaching these projects with a mindset of only proceeding at $400,000 a day. Am I wrong about this process? Specifically, are oil company customers taking into account some price increases for rates as they evaluate these projects? Do you want to clarify any of this?

No, no. I think we all agree with you. Different technical specifications mean customers' ability to make active choices declines as the market tightens. And I think you also see less price discrimination between rigs of differing specifications in a tight market as well. So care to add anything, Samir?

I'd say the clients claim that our rig rate makes a huge difference to their project FIDs. But in reality, it does not. I mean, the projects work; it's just about making sure they can get all their other equipment put together and through the process. The return on capital is the main concern for them. To Simon's point, it's a return on capital, right? It is does this makes sense for their capital. But in terms of rates, we'll get beat over the head that it makes a huge difference, but the truth is it does not really move the needle.

Ladies and gentlemen, there are no further questions at this time. That concludes today's call. Thank you all for joining, and you may now disconnect your lines.