Seadrill Limited

If you would like to withdraw your question, again, press the star one. Thank you. I'd now like to turn the call over to Lydia Mabry, Director of Investor Relations. You may begin.

Thank you, Operator. Welcome to FEDRAL's second quarter 2024 earnings call. Today's call will feature prepared remarks from Simon Johnson, our President and Chief Executive Officer, Sameer Ali, Executive Vice President and Chief Commercial Officer, and Grant Creed, Executive Vice President and Chief Financial Officer. Also joining is Marcel Wiegers, Senior Vice President of Operations. Today's call includes 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. Our latest forms 20F and 6K filed with the U.S. Securities and Exchange Commission provide a more detailed discussion of our forward-looking statements and the risk factors affecting our business. During the call, we will also refer to non-GAAP measures. Our earnings release filed with the SEC and available on our website includes reconciliations to the nearest corresponding GAAP measures. Our use of the term EBITDA on today's call corresponds with the term adjusted EBITDA as defined in our earnings release. Now, let me turn the call to Simon.

Thank you for joining us on today's call. The second quarter CEDRIL delivered EBITDA of $133 million. on $375 million of total operating revenues for an EBITDA margin of 35.5%. Cedral had a strong first half of the year with a combined $257 million in EBITDA. However, we are lowering our second half expectations based on revised estimates for contract start dates for the two rigs we're moving to Brazil and uncommitted near-term availability on other rigs within our fleet. We entered 2024 knowing it will be a transition year. We've operated fewer rigs while preparing units for long-term contracts and performing necessary calendar-based maintenance on several others. We've acknowledged our willingness to incur idle time early in the cycle as we sought to reprice, relocate and reintegrate rigs. This was exemplified by the West Polaris, which we moved from a third-party managed contract in India, where it operated alone, to a market rate term contract in Brazil, where we operate at scale. Like our peers, we've encountered white space for some of our units with near-term availability, specifically the Savan, Louisiana, West Phoenix, and West Capella. We're seeing indications of limited contracting options and intensifying competition that will impact on these rigs and possibly others into 2025. The emergence of more volatility inherent in the oil field services subsector further enforces the importance of three-cycle resiliency. to achieve durable earnings and cash flow across cycles. One, scale matters. Two, balance sheet strength matters. Three, management discipline matters. And four, most importantly, safe, efficient, responsible drilling operations matter. At Seagrill, we achieve basin scale by concentrating a highly standardized rig fleet in advantage geographies, primarily across the Golden Triangle. We maintain a prudent balance sheet that allows us to invest in maximizing useful life competitiveness and performance of the rigs across our fleet when attractive economics justify doing so we consistently demonstrate discipline by doing what we say we will do acting as strong stewards of capital we maximize the earnings potential of our contracted rig fleet by staying focused on maximizing one of the most important operational metrics uptime when downtime events do occur we learn from them first identifying the root cause then reshaping our efforts and behaviour to deliver intended outcomes. We are seeing results. During the quarter, five of our rigs achieved nearly 100% uptime. Every year, I visit every rig in our fleet. The level of operational performance and commitment to continuous improvement that I've personally seen across our rig sites will drive our success through the cycle. I most recently returned from Angola, where our rigs continue to set examples with superior safety performance across our fleet, across all metrics. Elsewhere in the fleet, the Phoenix recently celebrated nine years without a lost time incident and the West sat in six years without an LTI. Looking at the market, we remain confident in the long-term position of the deep water drilling industry. We still believe burgeoning broad-based demand will bolster what's largely been a supplier-side driven recovery. However, major discoveries in places like Namibia, Cote d'Ivoire and Indonesia have yet to convert into material rig activity. we expect the slower conversion of demand to contract awards will persist into 2025. Importantly, we've seen no indication that day rate development is curtailing demand. Rather, there are more likely paradoxes at play. Firstly, E&P customers are out consolidating contractors. When two becomes one, it can change the timing of tenders as projects that would have occurred consecutively often get deferred. Second, E&Ps continue to prioritize returning capital shareholders rather than spending on the drill bit. Even small independents appear to prioritise buybacks, dividends and debt retirement over new contracts. Third, EMPs appear largely unwilling to commit to long-dated projects. Broader uncertainty related to demand for the underlying commodity and shifting socio-political situations in certain countries appear to be shortening our customers' actionable time horizons. Asymmetry between partner expectations at the JV level can also prevent projects from proceeding. In a less liquid market, characterized by a smaller inventory of available rigs and contracts, it can be difficult to align supply and demand perfectly, contributing to idle time. We believe that this is transitry. Yes, EMPs are showing some discretion on near-term projects, but by definition, they are responsible for producing a consumable resource. What we're seeing is demand delay, not demand destruction. A positive view of the deep water drilling market's longer-term outlook remains unaltered. As frustrating as lack of visibility and short-term congestion may be, we're satisfied with the ongoing development of the market and our relative position within it. However, there will be volatility. As an industry, we seem to be experiencing micro-cycles where the amplitudes may be greater, the periods shorter, and the spread of day rates potentially wider. That means that now, as ever, scale, balance sheets, management teams, and operations matter. As we look to the horizon, I'm convinced CEDRAL will be a competitive player. I'm confident in our team's performance, potential, and progress. Thank you to our employees for your continued commitment to the competitive, collaborative, and cost-conscious behaviors that will carry us forward. With that, I'll pass the call to Samir.

Thanks, Simon. Trying to anticipate what our clients are going to do when is becoming more difficult. For example, Global Floater Contract Awards through the first half of this year or half of what they were over the same period last year, adjusting for an unusual 10-year contract. Then, in late July, an IOC and an NOC launched multi-rig tenders within what seemed like hours of each other. Though the market balance supports continued rate progression, uncertainty on the timing of demand and the competitive response to that follows can contribute to idle time and day rate dispersion. Drilling contractors are card players that never really get to deal. We can only play the hand in front of us. More challenging still is we are not alone at the table. We must anticipate and, where appropriate, respond with what other players may do with the cards they have. Certain markets feel different than others right now. Let's walk around the world reviewing the demand and outlook in contracting activity within each, starting with our primary focus area, the Golden Triangle. Brazil remains the single most important deepwater market. Expect the number of floating rigs there to remain flat around 30. So operators in the region appear to have expansionary ambitions that could yield incremental additions over time. About seven rigs will roll off in the next 18 months, and there are two open tenders for up to seven units of varying specification that would keep the market in balance. As industry participants are aware, We have three rigs contracted with Petrobras through 2025, so these new tenders line up well with our scheduled completion dates. We've begun dialogue on these rigs for future work both in and outside of Brazil, and we anticipate being able to provide an update on contracting later this year. The U.S. Gulf of Mexico remains an active market with generally high specification threshold that often drives day rate development. Recent contract awards here have been as short as one month and as high as three years, and the variability in demand can create for a larger fan of outcomes compared to other long-term drilling markets. We operate three rigs in the Gulf of Mexico. The West Vela is committed through mid-2025, and the West Neptune through January 2026. The Savan, Louisiana remains a shorter-term rig. She completed a well intervention campaign in May, then transitioned to traditional drilling work that should finish later this month, though it could extend. The RIGS contracting outlook for the remainder of the year changes week to week. We continue to explore opportunities with multiple customers for both drilling and intervention work to fill its remaining white space. West Africa remains a source of incremental demand for the industry in 2026 and beyond, driven by key geographies like Namibia and Nigeria, where we have extensive operating experience. Currently, we have three RIGS on contract in Angola through our solid role joint venture through mid-2025, and we're in active conversation with clients that should keep them contracted in the region in 2026 and beyond. Outside of the Golden Triangle, Southeast Asia remains active with programs across various countries that could be of interest. We continue to believe the West Capella is well positioned as one of two drill ships in the region equipped with managed pressure drilling, but acknowledge dispersed demand can contribute to idle time between campaigns. Norway remains precariously balanced, being either one rig oversupplied or one rig undersupplied. When the Phoenix concludes its contract with VAR Energy later this month, we will stack the rig in the absence of a contract that justifies the over $100 million investment required to continue operating in Norway, reducing costs and mitigating the impact of firm-level EBITDA. Based on the current outlook, the soonest opportunity for the rig to work will be in the second half of 2025. Across our fleet, we work hard for the rigs we earn. As we book new contracts, we aim to protect the margins and the terms and conditions to ensure we get the benefit of the bargain and maximize each rig's earnings and cash flow. And now, I'll hand it over to Grant.

Thanks, Tamir. Before I begin, I want to review some administrative items. Following the recent consolidation of our corporate office in Houston, we have transitioned from a foreign private issuer to a domestic issuer, like all the other major international offshore drilling contractors. That means we'll be filing 10 Ks and 10 Qs from 2025 onward, which should be welcomed by our investor base. We're also voluntarily ending our secondary listing on the Oslo Stock Exchange. The last day of the trading will be on Monday, September 9th, and from then on, we'll trade exclusively on the New York Stock Exchange, consistent with efforts to simplify our business. Now let's turn to second quarter performance before moving on to our full year outlook. Second quarter contract drilling revenues were $267 million, $8 million lower than the first quarter. We received no contributions from the Polaris and Auriga in the second quarter as they underwent preparation for upcoming contracts in Brazil, compared to the first quarter when they respectively contributed 25 and 60 revenue earning days. This was partially offset by contributions from the Savan, Louisiana, which returned to work in April, completing a short well-intervention contract before transitioning to a more traditional drilling contract. Reimbursable revenues were $15 million, with a $5 million sequential decline accompanied by a corresponding decline in reimbursable expenses. Updates to our Sonodrill joint venture, through which we operate three rigs in Angola, affected both management contract and leasing revenues. First, we received an inflationary increase on the daily management fee we earned for operating the Sonodrill rigs. retroactively applied to January 1st. This appears on the P&L as management contract revenues and was $65 million in the second quarter. Second, we now own a Bebo charter rate in the West Gemini, which we charter to the joint venture beyond the nominal $1 a day, as the JV begins paying out earnings to its partners proportional to their rig contributions. Second quarter leasing revenues of $26 million include two quarters of BBC income, as well as revenue associated with the Qatar jack-up rigs we leased into the Gulf Coast Joint Venture. Vessel and rig operating expense was $165 million compared to $180 million in the prior quarter, a delta of $15 million, or 8%. The change was primarily attributable to the Polaris and Auriga as they undergo contract preparation and incur minimal effects until they commence operations later this year. Additionally, we no longer pay third-party rig managers on those units as we transition them to CEDRAL management after they completed their previous contracts. Management contract expense increased $3 million sequentially to $41 million, reflecting timing of repair and maintenance expense on the CEDRAL rigs. SG&A was $24 million and included $2 million of costs related to our move of corporate headquarters from London to Houston, which we consider an adjusting item to EBITDA. We also recognize $203 million gain on sale of the Gulf Trail Joint Venture and Qatar Jackups, which closed on June 25th, representing the difference between the sale proceeds of $338 million and the net book value of the disposed assets. This translated into a strong quarter in terms of EBITDA performance of $133 million at a margin of 35.5%. We maintain a strong balance sheet with the biggest change this quarter being the proceeds from the jack up sale, partially offset by cash spent on our ongoing share of purchase program. At quarter end, we had gross principal debts of $625 million and $862 million in cash from net cash position of $237 million. We continue to deploy capital consistent with our capital allocation policy, using it to maintain a healthy balance sheet and liquidity profile invest in the maintenance and competitiveness of our existing fleet, evaluate potential growth opportunities, and return capital to shareholders. We are always looking to invest our capital in value-accretive activities. We continue to award our shareholders with a robust capital return program. Late in the second quarter, we completed our previous $500 million buyback facility, and announced another $500 million program that we began executing in late June. Since initiating our repurchase program in September 2023, we have reduced the issued share count by over 15%. Cash flow from operations was $79 million for the quarter, including $60 million of long-term maintenance capex. Capital upgrades captured in investing cash flows were $43 million for the quarter, resulting in free cash flow of $36 million. Now let's review our full-year outlook. Completion of the Goldfield sale on June 25th means we will not benefit from the $30 million of bare-boat charter revenue related to those assets that would otherwise have been earned in the second half of this year and that was previously included in our guided results. Adjusting our guidance to reflect its completion would move the midpoint of the previously disclosed EBITDA range to $395 million. We are further adjusting guidance to reflect updated expectations for ARRIGA and VLARA start dates that move EBITDA recognition into future periods and a softer outlook for speculative RIG contracting on the Savan, Louisiana and the Phoenix for the remainder of 2024. We now expect fully EBITDA between $315 to $365 million, a range that reflects real risks and opportunities on either side. The changes in the rig and Polaris start dates reflect the realities of unexpected scope related to previous owners and managers' differing approaches to rig repair and maintenance, exasperated by vendor and weather delays that disrupted our shipyard schedules. Despite these challenges, we have hit major milestones on both rigs. The rigs are departing shipyards and will soon set sail for Brazil, where they will begin customer and regulatory acceptance testing. Both rigs should still begin their contracts by year end. To the extent that Savan Louisiana secures additional work in 2024 beyond its current contract, it represents upside to the midpoint of EBITDA guidance. For revenue, we expect $1.355 to $1.405 billion. Our CapEx guidance remains the same at 400 to 450 million. Our adjusted guidance does not detract from our belief in the market's strong underlying market fundamentals. It reflects shifting schedules that delay EBITDA into future periods and transitory software outlook for lower specification assets for at least the remainder of the year. It also reinforces the importance of the theme Simon addressed earlier. executing on our strategy of operating a highly standardized flow to fleet in markets that matter, harnessing the strength of our balance sheet to create value for shareholders, demonstrating discipline in our pursuit of cash flow generation and value accretion, and delivering safe, efficient, reliable operations. With that, we'll open the call for questions.

Thank you. We will now begin the question and answer session. If you would like to ask a question, please press star one on your telephone keypad to raise your hand and join the queue. If you would like to withdraw your question, simply press star one again. We ask that you please limit yourself to one question and one follow-up. Your first question comes from a line of Scott Gruber from Citi. Your line is open.

Yes, good morning. Good morning, Scott. I wanted to ask just on the market, you know, it seems that 710 rates are really strong here, and those will sustain through this soft patch here based on recent awards and the demand uplift that's coming together for late 25 and 26. How do you think about rate resiliency on the 6th Gen fleet? Obviously, there could be some discounts taken for shorter-term work, but I'm really thinking about the term work for 6th Gen rigs. you know, is impacted by, you know, rates that could be taken on the shorter-term work? Or do you think the seventh-gen strength, you know, helps to hold up the sixth-gen rates on term work?

Yeah, so this is Samir. I'd say, you know, on the sixth-gen rates, at least on our sixth-gen drill trips, we've been pretty conscious in where they're placed. So we've got one in Brazil on a long-term contract. We've got one in Southeast Asia that's, you know, one of two rigs in the market with MPD. So we think we can capitalize on that and continue to push you know, keep rates at good levels. And then one is in our JV venture in Angola where, you know, having that protective mode is helpful. So for us, when we look at the rates for those rigs, we've been pretty conscious of how we place them around the world to maintain, to ensure that we can still maximize the rate on those rigs.

Got it. And just on the West Phoenix, appreciate the color. And you mentioned that the next opportunity could arise late in 25. Did I hear that correct? And you're essentially going to kind of wait for the next opportunity in Norway, I assume. That rig probably is not going to be bid outside of the region. Or would you look outside?

Yeah, no. So, you know, we're focused on Norway, but we'd obviously look at other markets. For us, it's really making sure we can justify the capex investment that's required in the rig. We are looking at opportunities in the middle of 25. But there are other opportunities outside of Norway. But I think, you know, I'd stress the key for us is if we're going to invest over $100 million in the rig, making sure that we've got a return on that capital.

Appreciate it. I'll turn it back. Thanks, Scott.

Your next question comes from a line of Ben Nolan from Stiefel. Your line is open.

Yeah, I appreciate it. So... I guess my first question relates to just the competitive landscape. I mean, obviously, a smaller competitor is about to be gone, and now that means that you guys are the little train that could here. So does that change at all how you think about the competitive landscape, how you're positioned, the consolidation that is happening? Just curious, Simon, if things are the same as they were before or not, if you think about sort of the word a little bit differently now.

Yeah, no, Ben, I don't think our posture is changed by that recent announcement. You know, we were charged by the board with being agnostic between presenting ourselves as an attractive target for consolidation and at the same time doing what we can to maximize growth opportunities for the company. So we have an attractive fleet, we've got a clean balance sheet, good backlog, So we're definitely a potential acquisition target for a larger peer. But we also believe that we've created a very strong platform for growth. And CEDAW today is a very well-run business, and this is reflecting our earnings results today. We're also disciplined. So when we look at those opportunities for growth, there are certain metrics and thresholds that the opportunities need to meet or exceed. So we have one eye on what we've got and one eye on what we're trying to build.

Gotcha. And then for my second question, Grant, you mentioned it a little bit, but could you maybe go into a little bit more color on what is driving some of the delays on the timing of the Auriga and the Polaris?

Well, yeah, it's really the supply chain issues, and I guess, Simon, we can go into more detail there.

Yeah, I mean, essentially what you're dealing with there is the The rigs have, you know, there's some uncertainty in terms of our peers' performance in terms of rig acceptance. So we're really changing our outlook to recognise the fact that there may be a longer period for the customer acceptance process. The rigs have now left the quayside. We've exited the shipyard and we're doing loadouts and some sea trials in preparation for the voyage down to Brazil. So most of the major project milestones are behind us. Really now, the sole risk that's outstanding and the main reason that we've changed our outlook relates to what's been a substantial growth in that customer acceptance process.

Gotcha. All right. Appreciate it. Thank you. Thanks, Ben.

Your next question comes from a line of Frederick Steen from Clarkson Securities. Your line is open.

Hey Simon and team, hope you are well. I have a couple of questions and first I wanted to touch a bit on the guidance. I think clearly the reduced guidance today will impact estimates for the second half of this year. I think all over the market is taking it relatively okay given the magnitude of it, but I'm interested to kind of hear a bit more color about if we should you know read anything into 2025 based on your reduced guidance for 2024 or do you think I guess for the Polaris and Auriga it's fine right because they start their contract in 24 they'll still work through 2025 but versus the last quarter and your previous guidance have anything kind of changed in terms of of the opportunities, possible startups, et cetera, for all your rigs that are not yet contracted through 2025?

Well, hey, Fredrik, it's Grant, and I'll start, and maybe the others can add anything. But on the guidance, Yeah, the majority of that was the rig activity plus then the Auriga Polaris. And like you say, Auriga Polaris is really just a timing thing, and that EBITDA then just pushes out into future periods and will not impact or should not impact 2025 and beyond. I think you'll see that Louisiana is a rig that we look at. It is lower spec. You see that we are assuming that she's warm-sacked during the fourth quarter, which means that we have got confidence in her commercial opportunities going forward. But like Samira said, white space and air pockets may continue to be a theme, so we can't discount that if you're looking at 2025. Beyond that, we look at Phoenix, and we talked about contracting opportunities for her come middle of next year. And then what I would say beyond those rigs, the rest of our contracting profile actually looks very good. We're approximately 67% contract covered, which on a relative basis is very strong. But maybe I...

David Wiltshire- handover to some if it's a project i'd also add, you know we're 67% contracted through 2025 and, if you look at our rollover profile next year it's our rigs in angola where, again, we have a. David Wiltshire- Strong jv which we feel pretty confident in and then we've got an asset in the Gulf of Mexico and the second half of next year. David Wiltshire- The Gulf of Mexico continues to be a strong market for a dual activity do bop rig like the Bella. And then we've got some, you know, you've got the Savon, Louisiana and the Phoenix. And we spoke to the Phoenix that it'd probably be second half of next year at the earliest. And then with the Savon, you know, she's the little engine that could, so she always ends up finding work here and there. We are still continuing to be optimistic that we think we can secure work, you know, into next year for that rig. But that will be a shorter contracting cycle as it's always been.

Yeah, well, that's very helpful. uh second uh on your uh fleet you you were able to close the sale of the jv uh i think you know slightly earlier than i expected so some nice kind of cash boost getting into the too few numbers there um with the phoenix uh now potentially being uh out of work for for some time and a substantial investment needed to to take that uh into play again uh how do you view you know the aquarius the eclipse in terms of taking order uh prospero as well you know if you have any comments but but have your attitude towards your cold stack rigs changed uh that is you know are you more likely to try to sell them scrap them etc now that you're you still have some some gaps to fill on your active link

I'd say the Phoenix is still the top priority out of those rigs, and we continue to actively market it. So we are in active dialogue for work for that rig. So we may have to stack it in the near term, but for us, we're not giving up on that rig just yet. In terms of asset sales, I'll leave it to Simon to comment on that.

I think we've been pretty clear through time, Frederick, in terms of reactivation opportunities for the cold-stacked units. We're looking for a material contribution to the cost of reactivation from a potential client and we want a good outlook on the contracting side for that unit and a good foundation initial contract. So at the moment, the focus is on the existing working fleet and getting some term behind some of those units. So I don't think you're gonna see anything change. There really hasn't been a change in our attitude as to how we might approach opportunities for those units. other than certainly the West Prospero is, you know, clearly a non-core asset now that we're pivoting to, you know, our flow to focus. So I think, you know, that was probably, you know, a more likely sale candidate than the others.

And that's very helpful. And just final on the queries and the clips, do you have any current reactivation cost estimates that you can share?

No, we haven't scrubbed them for some time, which I think underlines my confidence in that, you know, we're, We're at an unchanged position there. Yep.

Perfect. Thank you so much, guys. I'll leave it to the next one. Have a good day. Thanks, Frederick. Thank you.

Your next question is from the line of Hamid Khorsan from BWF Financial. Your line is open.

Hi. I just wanted to follow up on that question about the consolidation. Do you think that is playing a role here as far as the contract tenders go? Because last quarter and two quarters, the commentary was that day rates aren't causing any harm on the tender process, but now we have these push-outs that you and your peers are talking about.

I'd say consolidation with our client base. One plus one doesn't equal two. What ends up happening is parallel programs become sequential programs for us. as an industry. I think the consolidation that we've seen with our customer base has pushed out some demand. Again, it's not a demand destruction. It's a reshaping of the demand, and it's just pushing it further out.

Do you think, given the timing of the Phoenix being in Norway, is there enough time to generate revenue next year after you complete your maintenance process?

We definitely do, and I'd say for us, until we feel closer to a contract, we're not going to spend a significant amount of capital on that maintenance and those upgrades. But if we're targeting programs in the middle of next year, we have enough time to complete the upgrades and be ready for them.

Okay. Thank you.

Your next question comes from the line of Greg Lewis from BTIG. Your line is open.

Hey, guys, thanks. You know, just, you know, I guess my question around the Phoenix is a little bit different. You know, I know that the base case is that, you know, maybe the Phoenix can hopefully work in the back half of 25 if it can work in Norway. You know, it seems like the, you know, the high end North Sea floater markets kind of been, you know, it seems like it's a plus or minus rig there. Um, so just as, as we think about that and potential opportunities and, you know, regions where some of its sister rigs have worked in like Namibia, um, have we kind of cost out what it would take to kind of, you know, you mentioned this hundred plus million dollar number to stay in Norway. Obviously that's a high end gold plated market. have we kind of costed out what it would cost to go through the survey and have the rig in a position to work in Namibia? And obviously, we're actively bidding the Phoenix, but are we actually looking outside of North Sea or is it just all roads lead to Norway?

Yeah, we are actively looking outside of Norway as well. And we have looked at the costs. And I think Our threshold is the same. It's kind of, you know, the further you get from Norway, candidly, the cheaper it gets for the Phoenix, but in terms of capital required to maintain her. But at the end of the day, we keep coming back to we need to find a program that justifies that investment. And if that's in Namibia, that's fine, and that works for us. If it's in Norway, that's also fine. But, you know, for us, it is that focus on we do have a large CapEx investment, and we need to be able to cover that cost.

Yeah, no, 100%. And then just, you know, as we think about Southeast Asia, I mean, I pay a lot more attention to the Golden Triangle than I do there. As we think about, you know, those opportunities, you know, I guess the rigs rolling off in early Q1, any kind of broad strokes around the type of work, i.e., you know, are there one plus year tenders in that market or is it, hey, you know, if I wanted to be conservative thinking about, you know, opportunities for the Capella, you know, there is going to be work, but there's also going to be pockets of idle time.

So there are some long-term programs. There are some short-term programs in that market. I think the unique thing about the Capella in that market is she's equipped with MPD. She's one of two assets in that market that have MPD. So we are targeting both of those. Obviously, a longer-term program is preferable if we can secure it for the right return profile. But you are seeing a good mix of multi-year tenders plus some smaller one-off wealth opportunities.

Okay. Thank you very much. Thanks, Greg.

Again, if you'd like to ask a question, press star 1 on your telephone keypad. Your next question comes from the line of Noel Parks from Tuohy Brothers. Your line is open.

Hi, good morning. You know, a question I had, when we see continued capital discipline by operators, I'm just wondering, has that changed the willingness at this point in the cycle or the reluctance for operators to involve more partners in development? I'm just curious whether as they look at making fewer investments in general, whether you're seeing any impact on the tendency to go at more alone or to try to spread out the risk.

Yeah, so you're seeing in certain markets where we've got clients that are trying to farm down a little bit of their exposure, make more bets but smaller bets across the space, which can make it challenging to actually get approvals. I don't think, you know, we're not seeing a ton of the opposite where clients are saying, hey, we want more of it. But you're definitely, at least in the Gulf of Mexico, seeing, you know, where clients are wanting to farm down a little bit of their exposure and spread their bets around, which has made it a little more challenging to kind of secure rigs or secure contracts for us.

Great, thanks. And I'm just curious, to the degree that it is, Are there any customers you come across in discussions that are maybe particularly price insensitive at this point? Year over year, it's been a big increase. It doesn't seem like we're vaulting forward in day rate pricing right at the moment. I'm just wondering if there is a subset of clients out there where the discussion is really not so much about the price. I don't know if it availability, scheduling, logistics, or what have you, but any thoughts there?

Yeah, so it's a mix, but I wouldn't say there's any client that's super, you know, every client's price sensitive at some point, but I'd say the opposite of we're not seeing demand destruction because of the rates we're asking, right? Clients aren't saying, oh, we're just going to turn that program off because the rates are too high. There's other factors out there that are driving their decision. The day rate is a small piece of it, but It truly comes down to can they get partners or can they get long lead equipment and some other items, not really driven by the day rate itself.

Great. Thanks a lot. Thank you.

And your final question comes from the line of Josh Jane from Daniel Energy Partners. Your line is open.

Thanks. Good morning. I just wanted to follow up on the last line of questioning. I think it was Simon in his prepared remarks talked about characterizing the market as frustrated but satisfied when talking about where we are today. I was hoping you could discuss what ultimately you think is going to get the ball rolling further from a contracting standpoint. You just talked about rate and how customers aren't that rate sensitive. That's not really the big sticking point, but Um, how much is it project timing? How much is it rate? Um, you'd mentioned long lead time items. I was just hoping you could go through all of those factors and just talk about, you know, where we are today and what's ultimately going to get the ball rolling from a contracting standpoint.

Yeah. So this is Samara, you know, I'd say, you know, Simon mentioned in his prepared remarks, you know, by definition, these guys are producing a consumable resource. that can only last for so long, right? You can only defer demand for so long. We are starting to see that already happening. There's strong conversations happening for, you know, second half of next year and into 2026. So we are starting to see that. And part of it too, as I mentioned, the long lead time equipment, that's starting to loosen itself. Supply chains are starting to come back and clients are being able to get equipment that they need to start bringing some of that demand back. And, you know, you're seeing it in wellhead data. You're seeing in some other places that would be leading indicators for clients wanting to continue drilling? I don't know if you want to add.

Yeah, I think what I would add is that ullage is increasingly becoming an issue in some of the deep water production hubs. That's certainly a factor that we look at. So while traditionally people have been concerned about reserve replacement ratios, I think just the outlook of the customer base is a lot more short-term these days. So ullage in facilities I think is an important and often a little discussed factor. But, you know, really it gets back to this capital discipline. Our customers are satisfying their shareholders first rather than their own sort of first for production. And it's coming to the market in a somewhat staccato fashion.

Thanks. And then just one shorter-term question on Louisiana. You alluded to it earlier in the year. It did some intervention work and then some drilling work. Are there options to sort of stack back-to-back intervention projects for that rig over the next 12 to 24 months. And I'm just curious how you're thinking about that versus using it primarily for drilling work and what the opportunities are there.

So, you know, our focus is always drilling work. I mean, it's more profitable for us, but we're absolutely looking at intervention work as gap fill as well. We're in active dialogue on both, both inside and outside the Gulf of Mexico. So we are looking at opportunities. I'd say with the intervention work, it tends to pop up faster. even faster than the drilling work for the Louisiana, but we are pursuing both in the near term and into 2025.

I think you do make a good point there, though, inasmuch as the important element with that intervention work is that we have some discretion in the timing, and it needs to come to market in a volume that's interesting. We can prosecute that type of work most effectively when we have a campaign rather than just one or two worlds here and there.

Okay, thanks very much.

Thanks very much, Josh.

And this concludes today's conference call. Thank you for your participation. You may now disconnect.