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© transcript Emily Beynon . . . . . .

Thank you for your continued patience. Your meeting will begin shortly. If you need assistance at any time, please press star zero. A member of our team will be happy to help you.

© BF-WATCH TV 2021 © transcript Emily Beynon © transcript Emily Beynon

Thank you for your continued patience. Your meeting will begin shortly. If you need assistance at any time, please press star zero and a member of our team will be happy to help you. © transcript Emily Beynon

. . . . . . © BF-WATCH TV 2021 Please stand by, your meeting is about to begin.

Hello and welcome everyone joining today's Q3 2026 Transocean earnings call. At this time all participants are in a listen only mode. Later you will have an opportunity to ask questions during the question and answer session. To register to ask a question at any time please press star 1 on your telephone keypad. Please note this call is being recorded and we are standing by should you need any assistance. It is now my pleasure to turn the meeting over to David Kennington, Vice President, Treasurer. Please go ahead.

Thank you, Brittany, and welcome everyone to Transocean's third quarter earnings call. Today's call will be led by Transocean's President and Chief Executive Officer Keelan Adamson. Keelan will be joined by Chief Financial Officer Thad Veda and Chief Commercial Officer Roddy Mackenzie. In addition to the comments that will be shared on today's call, we'd like to direct you to our earnings release, fleet status report, and 8Ks that contain additional information, all of which is available on Transocean's website at www.deepwater.com. After our prepared remarks, we will open the conference line for questions. I'd like to remind everyone that today's call will include forward-looking statements, which are subject to risks and uncertainties that could cause actual results to differ materially. With that, I'll hand it over to Keelan Adamson.

Good morning, everyone, and thanks for joining us. Today, we'll address four key topics. I will begin with an update on the Volaris acquisition. Next, I'll share some perspectives on the deepwater and harsh environment drilling markets, after which I will review recent contracts and incremental opportunities around the world. And lastly, we'll summarize our third quarter operational and financial performance, provide updated guidance for the remainder of 2026, and some preliminary 2027 guidance All be it for Transocean standalone. Starting with the Valeris acquisition, we have now received all necessary regulatory approvals required for closing. Most recently, the US Department of Justice and CAGE, the Brazilian Competition Authority, each approved the deal with no conditions. I wish to thank the amazing team, internal and external, that successfully supported us through the various governmental reviews over the last several months. TransOcean and Valeris filed the definitive proxy statement on October 14th, and shareholder votes for both companies are scheduled for November 24th. We encourage shareholders to approve the transaction and associated resolutions for this exceptional value-creating combination. After successful shareholder votes, we expect the Bermuda Court to approve the deal on November 26th, and closing will occur on December 1st. We are now in the final stages of integration planning. Upon closing, we will quickly commence the process of delivering the estimated $200 million in annual synergies. We intend to provide 2027 guidance for the combined company in February next year, along with our year end results. Now onto some market observations. Consistent with third party reports, we believe that global market conditions and energy supply and demand trends are very constructive for our business. Even though the outlook for oil prices remains supportive due to the long lead time nature of this business, all our customers remain disciplined in allocating investment capital to exploration and development opportunities. Even so, while our discussions with customers and industry observers suggest that this budget season will result in increases in deep water and harsh environment spending, IOCs particularly still seem most likely to contract rigs for durations As the market continues to tighten, however, we expect these customers to make longer-term commitments as needed to ensure access to preferred assets. While national oil companies are also financially disciplined, their long-term interest in the exploration and development of domestic hydrocarbon resources reflects their government's economic growth or energy security agendas, the latter being emphasized by recent supply chain challenges. The significant year-over-year increase in contracting activity has been led primarily by NLCs and skewed to longer-term contracts as they secure rig capacity to pursue their broader agendas, which is reflected in the appreciable percentage of the total backlog year-to-date that has been awarded to us at roughly 60%. In contrast, we have observed certain independent operators act opportunistically in securing drilling capacity. taking advantage of favorable economic conditions to perform additional work. According to Fernley Offshore, active fleet utilization now stands at or above 90% for drill ships with demand for sixth and seventh generation drill ships still expected to exceed 95% by the end of 2027. Drill ship backlog is now 237 rig years, an average of roughly two and a half years per unit, the highest in over a decade. In the near term, we expect rig utilization to tighten further with incremental investments in exploration and development projects. We also expect contracting lead times to lengthen as longer duration contracts reduce fleet white space and build forward-looking backlog visibility. In the context of tighter utilization and improving visibility, drillers should carefully consider the many and various strategic, tactical, and economic trade-offs. Moving to recent contracts and prospects. We continue to carefully manage our rigged portfolio to ensure that we maximize cash flow. You should expect us to seek an optimal deployment of assets through a continued, disciplined, centralized management of our fleet once the transaction closes. While all of our contract awards are covered in our fleet status report, let me share a few recent highlights that support our very constructive outlook. The Deepwater Proteus was awarded a 10-well contract in direct continuation with our current customer in the U.S. Gulf, adding about $325 million of backlog. The Deepwater Conqueror was awarded two new contracts in direct continuation with her current customer for a total award of $305 million. The Duraby Deepwater KG2 was fixed with ONGC in India on a $300 million commitment. In Norway, The Transocean Norgay was awarded work with Shell worth approximately $62 million. In Australia, a single well option was exercised for the Transocean Equinox for about $24 million. In total, we added nearly $2 billion of backlog, including $1 billion associated with the formal approval of an award for the placement of three Cat D rigs with Equinor announced in late June, namely the Enabler, Encourage and Endurance. These recent commitments have effectively sold out our active fleet for the remainder of 2026. Our 2027 contract coverage has improved from 81% to nearly 95%, and 2028 coverage is already around 65%. In fact, the Deepwater Mykonos is the only drill ship we have available to commence a term contract in the next 12 months. Even though we have already experienced a substantial amount of contracting activity this year, There is still a very healthy pipeline of outstanding opportunities around the world. According to S&P Petro data, approximately 124 rig years have been awarded year-to-date, while operators are currently evaluating roughly 35 open tenders, representing a further 45 rig years of potential demand. In the US Gulf, our recent contract awards reinforce our view that long-term demand fundamentals remain compelling in this key region. However, as we have noted on previous calls, we are also observing growing international demand for capable assets, particularly from West Africa. We expect several rigs in the US Gulf that are not on long-term contracts to leave and satisfy this demand. This likely temporary migration will keep the Gulf's fit-for-purpose asset base in a healthy supply-demand balance. Brazil will remain one of the world's most attractive deep-water markets, Thank you for joining us today. Mozambique, Namibia, and Nigeria. In the Mediterranean, several new discoveries requiring appraisal and development drilling should drive an expansion in that regional fleet of approximately two to three units over the coming years. In Southeast Asia and India, recent awards represent encouraging signs of what will become a broader regional growth cycle. In Southeast Asia alone, we see potential for seven to nine rig years of demand from four to five opportunities in a market that currently has only one active deepwater rig. In India, as a result of the government's pursuit of their Samudra Manthan mission to find and grow offshore production, a multi-rig multi-year program could commence with a near-term activity increase of as many as four drill ships in the next two years with Indian NOCs. Turning to Norway, Utilization of high-specification harsh environment semi-submersibles remains exceptionally strong through 2028, supported by recent awards from Equinor, Harbor, VAR Energy, Shell, and Accra BP. The Spitsbergen and Equinox are Transocean's only harsh environment semi-submersibles available before 2029. We are encouraged by the many inquiries on these rigs and are confident that they will secure work soon. Additionally, potential programs in Canada for Equinor and Synovus could further tighten harsh environment supply from 2028 onward. In summary, while the timing and scope of individual opportunities will inevitably evolve, the broader market trends driven by new sanctioned developments, increasing exploration investment, and a growing inventory of recent discoveries remain highly constructive. Against a backdrop of limited fleet growth, more forward contracting visibility, and a steadily tightening supply-demand balance, we continue to see favorable conditions for strong fleet utilization and improving business economics. Finally, before I pass the call to Thad, a brief comment on third quarter results. During the quarter and year to date, our fleet uptime was an exceptional 98%, in line with the best performance ever delivered by the company, with average daily revenue approximating $463,000 per day. Both revenues and operating and maintenance costs were in line with our guidance range. Adjusted EBITDA of $313 million and the associated margin of 33% was consistent with the prior quarter. We continued to improve our capital structure by fully redeeming the Deepwater Aquila secured notes in October and also finalizing an amendment to our revolving credit facility that will become effective at the closing of the Volaris acquisition. Over the past two years, we have focused on debt reduction and the simplification of our balance sheet. In the last 24 months, we have retired over $2 billion of debt, and you should expect us to continue to pursue this objective. I'll now hand the call over to Thad for additional comments on Q3 financial results and to provide guidance.

Thad? Thank you, Keelan, and good day, everyone. As Keelan highlighted, our third quarter financial results were consistent with our expectations and, importantly, the guidance we provided to you in August. I have just a couple of comments on our results. At $590 million, O&M expense continued to trend a bit below our forecast. This is due in part to success in reducing costs for both in-service and out-of-service projects and reflects the continued scrutiny of our spending requirements, which will continue. At $62 million, G&A exceeded the upper end of our guidance range due to $10 million of costs associated with the pending Volaris acquisition. Adjusting for these costs, we spent about $52 million for G&A expense, generally in line with our quarterly run rate over the past year. Free cash flow of $131 million with a margin of about 14% was lower versus last quarter due primarily to the timing of collections as well as an annual fleet insurance premium payment of approximately $20 million. Our trailing 12-month net debt to EBITDA ratio, inclusive of restricted cash reserved primarily for debt repayment, is now 2.9 times, generally consistent with where we ended the second quarter and one full turn lower than a year ago. We finished the quarter with about $500 million in unrestricted cash, roughly in line with the prior quarter. Our total liquidity, inclusive of the undrawn revolving credit facility, was approximately $1.3 billion. We expect that we will end the year in about the same place. On October 1, including a nearly concurrent $35 million amortization payment, we retired the full principal balance of about $200 million of the 8% Deepwater Aquila Senior Notes. The payment, which included a call premium and accrued interest, was settled using cash on hand and a $48 million of restricted cash from the associated debt service reserve account. This debt retirement saves approximately $22 million in interest expense through maturity. Subsequent to this retirement, the reserve account, which makes up the bulk of our restricted cash, contains about $230 million, almost all of which is associated with our remaining $763 million of 8.75 secured tailwinds notes, which we expect to address in 2027. These actions reflect continued execution of our strategic objective to reduce leverage and simplify the balance sheet. On October 15th, we completed an amendment to our revolving credit facility to expand its total capacity to $750 million, improve terms, and extend its scheduled maturity date by three years to late 2031. The amended facility was substantially oversubscribed during syndication, with several new banks joining. The facility will become effective when the acquisition of Valeris closes, expected on December 1st. Now for a few thoughts on our outlook for the balance of the year and into 2027. Our 2026 revenue guidance has been narrowed by $25 million, reflecting the diminishing likelihood of additional gap filler work materializing for the next couple of months. Indeed, our remaining contract coverage already approximates 100%. We have also increased the lower end of our full year cost guidance by $25 million, moving the midpoint slightly higher to reflect incremental activity. Our G&A guidance range is $185 to $190 million for the full year, including increased employee benefit costs. This range excludes transaction related expenses which would typically be excluded from adjusted EBITDA. I will also note that our full year interest expense guidance of approximately $500 million consists of results through Q3 that include the effect of the bifurcated exchange feature in our 2029 exchangeable bonds plus our forecast for Q4 interest expense approximating $107 million. This figure excludes any potential derivative effects of these bonds. On a standalone basis, we expect to end 2026 with less than $4.8 billion of gross debt, and as previously mentioned, forecast our total liquidity to be around $1.3 billion. This liquidity estimate includes our existing undrawn $510 million revolving credit facility. Our latest earnings release provides preliminary guidance for full year 2027 for Transocean on a standalone basis. As Keelan mentioned, our fleet is already 95% committed in 2027. This is about 10 percentage points better than where we were for 2026 at a similar point in 2025. Year over year, O&M costs are expected to increase by approximately $60 million. A large portion of this cost relates to the repositioning of rigs for new contracts, periodic surveys, and recertifications for our fleet, and includes required overhauls of spare equipment. Finally, we're observing some inflationary pressure, mainly in logistics and fuel, but also some increases in the cost of manufactured goods, the result of increased input costs including raw materials, energy, and logistics. Notwithstanding, we expect cost inflation to remain in the low single digits in 2027 and have considered this friction in our guidance range. This concludes my prepared remarks. Keelan?

Thank you, Thad. Year-to-date, we have added over $4 billion of contract awards, bringing our standalone backlog to approximately $8 billion. We remain focused on converting as much of every backlog dollar to cash flow as possible. We look forward to closing the Valeras transaction in early December, combining two great companies committed to operating best-in-class assets, delivering exceptional performance that surpasses customer expectations, and utilizing an industry-leading pro forma backlog of approximately $12.7 billion to drive shareholder value. We'll now open the line for questions.

Thank you. If you'd like to ask a question, press star 1 on your keypad. To leave the queue at any time, press star 2. Once again, that is star and 1 to ask a question. We'll take our first question from Joe Latch with Morgan Stanley. Please go ahead. Your line is open.

Hey, good morning team, and thanks for taking our questions. So I just wanted to ask on the preliminary 2027 guide, could you just talk to how you're thinking about the upside and downside scenarios here? With contract coverage at 95% next year, what could push you to the upper or lower end of the guidance range? And if you could talk about both revenue and O&M, that would be helpful as well. Thank you.

Thanks for the question. So as observed, it's a pretty good situation we're in from a contract coverage perspective. But if you notice from our performance this year, our initial guidance reflected our best guess of how the year was going to go. Our operational performance is very good. There is a very limited amount of opportunity here for sort of fill-in work, but I think that there is enough variability in that that we have some upside potential. When it comes to the costs, we're going to continue with our scrutiny of every expenditure as we've done. So in that context, you know, we feel that the guidance that we've given you is pretty much straight down the fairway. But again, in the context of the acquisition, plus the standalone efforts that we're making to reduce costs, we think that there is some room for improvement there.

Great. Thank you. That's helpful. And then maybe just on the macro, can you talk a little bit about where you see the progression of day rates? You've announced several sizable awards over the last couple of months, and it seems like day rates are in the $450,000 to $500,000 per day type of range. Could you just talk to where you're seeing leading-edge day rates today? Maybe how much additional pricing opportunity there could be as utilization titans. Thank you.

Yeah. Hey, this is Roddy and look far for it from us to speculate where that's going to go. So you've seen a few of the announcements that we've made recently. We as we think about, you know, as Thad and Keelan pointed out, we're really in a great position backlog wise and with limited availability and So everyone's now focusing on 28, 29, and 30. And what's interesting about that is we're observing at the moment 100% utilization, but there's still time available as time goes out. The visibility on that is going to change, and I think that's going to be the inflection point. When the operators are now beginning to see that they don't have the visibility to rigs in the timeframe they need, that's probably the trigger that's going to help change that dynamic.

Yeah, maybe Joe, I'll just jump in on the back of Roddy's comments. I think the point that we need to remember is that utilization, we talk about a prompt utilization typically at 95% or rates will move at a certain point in that utilization. But clearly, we always need to make sure that there's a good backlog of utilization in the out years. And what Roddy is speaking to is the fact that the opportunities that we're looking at now are in the out years of 29, 30, 31. And so as that develops and as we see more of those opportunities coming through, we're going to see the lead time for contracting awards is going to have to come forward. And as that takes place, the visibility improves, the utilization stacks, and at that point, we should be seeing better economics on these deals as we go forward.

Great. Thank you. That's helpful.

Thanks.

Thank you. We'll take our next question from Keith Beckham with Pickering Energy Partners. Please go ahead. Your line is open.

Hey, good morning. Thanks for taking my question. I just wanted to hit on, you know, the Gulf seems like it's going to be down a little bit next year, right, with several rigs heading over to West Africa. You know, maybe looking forward a little bit further, do you expect that to be somewhat of a new normal where the Gulf is, or do you think we're going to see more of a return potentially in 2028 within the region and Either way, I mean, what do you think is driving that mix?

Yeah, so I'll take that one. There are a couple of rigs that are already booked to leave, right? So it's interesting. The utilization in the Gulf for us certainly was 100% this year. We had a few opportunistic fill-in wells, which was great. That helped top up the rig that had a little bit of availability on it. So yes, we've announced there's two of ours that are going to be leaving. We know that there's at least one of our competitor rigs going to be leaving. And this is because places like West Africa and the Mediterranean and potentially Asia are really heating up. So they're a significant draw on these rigs. So if there is any idle time on these rigs going forward, I think it gets snapped up real quick. I think basically what happens is These mobile units move where the work is and at the moment the urgency for the work is perhaps not in the Gulf of Mexico or Gulf of America right now, but we do think that the fundamentals of the basin are solid. There's been a number of kind of developments kicked off and we do expect that a lot of the big guys especially are looking for longer-term development work in the Gulf. It's just a question of Does that transpire into a contract and a timeline that keeps the rigs here, or do they go elsewhere first and then perhaps come back a bit later as the availability tightens up?

Yeah, Keith, I also think, to Warwadi's point, the long term for the US Gulf is strong. When we look at the prospects our customers are focusing on for the next decade, 2030 and beyond, it's clearly the payload and the assets that are required to drill those prospects are clearly the high spec ends of what we own. So while you might see some of these high spec units leave for the work that Roddy is talking about, as our customers start improving, increasing their exploration spend, and there's a lot of conversations happening about that today, where our majors are are looking at near prospects, looking to see if they can tie back into existing production hubs, and then obviously addressing future potential. You know, we see the basin being very strong for many years to come.

Okay, awesome. That's really helpful. And then my follow up, I just kind of wanted to check back in on energy security and how you guys are thinking about that now with customers, but You know, following, you know, kind of the KG2 contract that you guys had, right? I mean, are you guys seeing NOCs start to try to move faster towards FID, given energy security risk right now, or maybe any urgency within those projects, given everything going on? Just any thoughts around that, Southeast Asia, but also more broadly anywhere else that we should be thinking about as well.

Yeah, yeah, very much so. I mean, so look, last year and beginning of this year, you saw, you know, The Petrobrasys of the world moving quickly, really awarding a tremendous volume of work, deciding on their long-term plans and getting after it. This year, we're seeing the same thing in other places. A good example is India, for example. There's $9 billion has been earmarked for funding for and many others. Basically, large-scale exploration and development of their resources. Again, it is all linked to domestic production. The issues that we've seen in the Gulf of Hormuz, the other places around the world, particularly Ukraine conflict, is really bringing into focus the concept of domestic production and being self-reliant. With that said, we definitely are observing the NOCs getting after it. We actually would say that in India, ONGC moved very quickly from when they got the bids finalized for that tender to actually making the award, recognizing the scarcity of the rigs available. We think there's going to be a lot more of that. We think basically those that move quickest are the ones that are going to secure the assets, and those that don't are going to be disappointed.

Yeah, and I think we're also seeing some NOCs learning how to scale up, right? And so the, you know, the Petrobras of the world, the Equinor's of the world, they are used to, you know, building volume, pursuing long term objectives in a steady fashion. And I think some of the other NOCs around the world are governed by their procurement processes. And of course, that Thanks, guys.

Thank you. We'll take our next question from Eddie Kim with Barclays. Please go ahead. Your line is open.

Hi, good morning. So one of your peers recently indicated that the deep water market is firming up despite very limited demand uplift so far this year from higher commodity prices. Would you agree with that? And if so, when would you expect operators to really start stepping up their Red contracting activities given the elevated commodity price environment.

Yeah, so look, the elevated commodity prices are, you know, they're either based on a macro trend or movement or temporary global issues. And, you know, I think what we've observed, and I think if you talk to any of our customers, they are very focused on being disciplined in terms of matching their contracting activity to their approved development activities. And that's important because they are not using the current commodity price to justify projects. They are grounded in a very realistic long-term outlook, which is actually great for our business. It would be interesting that our business would uptake heavily because of this recent oil prices, but it's not particularly useful in the long term. What we're looking for, especially in this market, is long term stable contracts at attractive economics that just make sense. And that's basically where the operators are today. They are not kind of doing the knee jerk reaction. There are one or two that have taken some opportunistic wells to increase near term production, which is, you know, commendable. But for the most part, everybody is viewing their big commitments on a long term and others. We think that's extremely encouraging for our business because it means that the uptick in contracting that you've seen now, which is actually a banner year, best year for us in 10 years, is going to be the way going forward. This is the normal that they're working to and they're justifying this on breakevens that are $50 and below. They are not talking about justifying things at 80 or 90 bucks a barrel. We actually think that's extremely positive.

Yeah, I think, Eddie, it's a lot about reserve replacement conversations right now. It's about energy security. It's about, you know, how are we able to supply the energy to the world's demand as opposed to the spot market pricing, right? Our business is very long lead and our customers have been very, very disciplined in allocating that capital and they will continue to do so, albeit that probably upstream and particularly deepwater is going to attract more of that investment as we move forward.

Got it, understood.

My follow-up is just on your cold stacked assets. I think you had previously talked about reactivation of one of your cold stacked assets probably not being a 27 event but more likely a 28 or 29 event. Just curious if your thoughts there have changed at all. I mean just with your recent fleet update, it doesn't look like you have much availability really at all in 2027 besides the Mykonos. So just curious if thoughts on timing has changed even in the past three months or so.

Yeah, I would say, you know, first and foremost, we're not going to reactivate one of those coal stack ships, speculatively. It's going, you know, if the demand in the market requires more capacity, then, you know, clearly we will see utilization building in the out years, like we've talked about, where we see, you know, really tightened visibility in the out years of 29 and beyond. As we think about cold stack reactivations, we think about the lead time to get them restarted and available to work. You know, that's 12 to 15 months. So I think we're still in the same mindset. One, it's not going to happen unless there's a contract and we're going to recover that investment. And two, it's probably not happening in the next 12 months anyhow.

Yeah, I'll just add to that. We are not in the habit and we will not be creating the habit of plundering hundreds of millions of dollars into reactivations on questionable economics. As Keelan points out, we are going to be very disciplined in this approach. We are only going to do it when it makes sense and the returns are guaranteed. So don't expect to see us do it just yet. We will wait for the right moment.

Understood. Great to hear. Thanks for that call. I'll turn it back.

Thank you. We'll take our next question from Greg Lewis with BTIG. Please go ahead. Your line is open.

Yeah, I thank you and good morning and good afternoon, everybody. Yeah, Rod, Keelan, I was hoping you could talk a little bit more about what you're seeing in the North Sea. You mentioned you have a couple rigs that have, you know, are rolling off contract, you know, in a year. It just seems like the other day you were moving rigs to Australia because the North Sea was kind of softening. I guess just kind of curious as we're hearing that the North Sea is selling out, what type of durability or duration are we seeing in the North Sea in terms of longer-term opportunities to put work rigs? I know we don't want to talk too much about pricing, but in a market that's sold out, it's

I'll deal with Norway first. We're basically operating at near full capacity for the high spec rigs. What we're seeing is there's basically an increasing number of direct negotiations and long-term partnership deals being struck. You have seen several announcements from ourselves and our competitors over the last We have a little bit of availability left but we've already announced that two of our rigs that had previously left Norway to go overseas are coming back so I mean that's kind of the beauty of this class of fleet that we have and the mobile nature of our units is that when it isn't working out they can go elsewhere and when it is then they'll come back so we're excited to bring them back we're excited to expand our footprint in Norway again and we're excited at what other opportunities are there Real quickly, on the UK side of the North Sea, there is a glimmer of hope. The government has not been particularly helpful over the last several years, but the Jackdaw sanctioning and then, of course, the conference that people are building and the Rosebank decision means that the UK has a pretty good chance of adding some capacity there. It's just going to be a question of whether there's rigs for it. That market is in good shape as we switch from the concept of utilization to forward availability.

Okay, great. And I realize the Velaris transaction is not yet closed. Are you guys entertaining questions on jackups or should I ask something else?

Yeah, obviously we're operating as individual companies until we close. Greg, but happy to take any questions on the jack up at a future point.

Sure. Okay. So then, you know, Rodney, maybe this question is for you. Clearly, we're hearing a lot more about the opportunity for exploration drilling as we look out into 27 and 28. You know, I guess I'm kind of curious what your views are, you know, if we I know this is hard to pinpoint because rigs go back and forth, but as we think about the global fleet, do we have any sense for how much of the fleet is kind of operating in exploration and then realizing that drilling a well in West Africa is different than drilling a well in the U.S. Gulf of Mexico? Is there any kind of way to think about How much longer an exploration well takes than, say, a development well? Is it 20%? Is it 30%? Any kind of color around that? Because it does seem like we're going to see a lot more exploration here over the next couple of years. Thanks.

Yeah, that's very true. So we are seeing that, right? There are several of the rigs are moving to that kind of mode. And a lot of the new things that have been sanctioned are going to be So, for example, the work in India, you know, a lot of the stuff that's happening in West Africa is additional exploration work. So, yes, a new location and you're exploring the nature of it. It has a chance of running longer, has a chance of being more difficult. But when you go into the development mode, you're also completing well. So there's an element of that that kind of balances out. Very, very difficult to say if there's a difference in duration, but it really depends on locations and also what well programs look like in terms of development stuff. Of course, development stuff you do over and over again, so you get better at it. Typically, you understand the conditions more, so you're maybe perhaps a bit more efficient. But yeah, I think that's a hard one.

Yeah, it's a great question, Greg. It's basin by basin, as you rightly point out. Obviously, exploration well designs are more conservative as opposed to development wells, which obviously they have the ability, the operators have the ability to drive a lot more efficiency as they understand more about the reservoir. So on conservative wells, they typically will take a little bit longer depending on the basin. But of course, you know, on the successful exploration wells, then there's logging programs and potentially testing programs. And so that obviously extends the duration as well. So It's why it's difficult to really talk about how long an exploration well can go because it really depends on the success and whether the geological targets are what they expected to see. But I think it's fair to say they typically go longer.

Okay, super helpful.

Thank you very much. Thanks, Greg.

Thank you. We'll take our next question from Frederick Stein with Clarkson Securities. Please go ahead. Your line is open.

Hey, Keelan and Roderick. First, congratulations on getting all the paperwork done in relation to all the different antitrust processes. I'm sure you're looking forward to some actual integration instead, so I'll be eagerly watching the post and completion towards the end of the month. But for my questions, I wanted to be a bit specific on rigs. As you pointed out in your prepared remarks, you have very good coverage on 27 already. There's some, I would say, you know, a gap on the Deepwater Atlas between the 27 program and 28. And you also mentioned the Mykonos as the only rig of being available over the next 12 months that is potentially set for a term program or have the opportunity to do a term program. So any color that you could give on those rigs in terms of the chance of filling that Atlas gap? Or for the Mykonos, should we expect the gap before a new contract on that as well? Or do you feel like you have line of sight to opportunities that would be closer to direct continuation? Thanks.

Yep. Hey, there are no shortage of opportunities for both rigs. So the likelihood of gaps is very low. It's just a question of what the right opportunities are. But yeah, the Atlas specifically, the gap is real small. We've got plenty of interest to fill that gap. And it's really just a timing thing. It's on a well-based contract just now, and it moves to a term-based contract a little bit later on. But there's possibilities for all of those things to move. So that's dynamic, but likelihood of a gap is pretty small. Thinking about the Mykonos, she actually has options on her. So those have not been struck yet. So we wait to see what happens there. But again, we think as one of the few rigs active and working well and available, there's pretty low risk of gaps on her. If they were, it would perhaps be just for changing operator type gaps rather than a significant idle period. So feeling pretty good about that.

Yeah, Frederick, I would say you're talking about Atlas being one of the highest spec rigs in the world, the highest spec rig in the world, right? So any time that she might have available, that she might have available, I think we've demonstrated this year that the high spec rigs in the US Gulf, we can get them busy. And in opportunities in particularly the US Gulf, and if you think about Brazil and the conversations we're having with activity in both of those areas, We're not concerned about any significant gaps that could develop on those rigs.

Very happy to hear that and as a follow-up to the rig specific and maybe I'm just trying to be too clever in a way here but I think you said though the next 12 months Mykomos was the only one with availability for a termed program as I mentioned but I guess technically the Pontus will end in October next year. Should we interpret that as A new program already being in line for her? Or again, I'm just trying to read too much into the details here.

I think you try to read too much in the details. She's actually more likely to be right towards the end of the year. But yeah, that's just semantics.

All right, thanks. And if I may, just one percent as well. You are targeting around $200 million of synergies from the integration with Valaris. But are you able to give some specifics on potential integration costs? I'm sure there will be some costs there, one-off in nature, as you do the integration work. So if you have scope, that would be very interesting to hear. And also if that is in any way reflected in the standalone guidance of some sort that you've given.

Last question first. It's not reflected in our guidance, but if you've noticed over the past three quarters, we've called it out discreetly. As we approach an opportunity here to provide more fulsome guidance on the combination, we'll consider advising what the integration costs are going to comprise.

All right.

Appreciate all the color on everything. Thank you very much. Have a good day. Thanks, Frederick.

Thank you. We'll take our next question from Noel Parks with Tui Brothers. Please go ahead. Your line is now open.

Hi, good morning. You know, thinking back over what has been a very eventful years in the oil markets geopolitically, and yet sort of the strict behavior has been a little bit unexpected, at least for me. So I'm just wondering, It's kind of with the benefit of hindsight. In terms of the energy security motivation with the NOx, do you have a sense of when maybe they sort of really got religion on that? I'm kind of looking at the back end of the 24-month strip where it's looking finally more solid. Robert Thaddeus Vayda, Jason Pack Mgt.,

If we're brutally honest, a lot of the other energy ventures have not panned out, initially with very heavy government subsidies and not able to turn a decent margin at that point. And then, of course, when some of those subsidies dry up, then the economics look even worse. So I think there's just been a gradual movement back towards oil and gas and in particular domestic production and you know the recent events you know certainly the last 12 months have brought that into a much sharper focus so I would say that it's it's we've commented on it a lot you know our our customers have commented on it a lot I would say probably about 18 months ago there was there was really a big shift back towards hydrocarbons and that has only accelerated in the in the recent round of um you know Energy Capital Days and Budget Updates from the majors. So, yeah, very welcome, very overdue, but it's logical and it's based in reality now whereas before it was perhaps a little bit aspirational, if you would, rather than realistic.

Yeah, I think the conflicts serve to amplify the situation. I think we've all seen coming with reserve replacement percentages being at Robert Thaddeus Vayda, Jason Pack Mgt.

It's helpful because there are just enough various moving parts in kind of the equation of how the fundamentals play out that it's helpful to sort of get that perspective on the earlier roots of the uptrend. And, yeah, and turn to Valeris again. I'm just wondering, you know, beyond sort of the market dynamics you've discussed already, I just wondered are there and so forth. So, any metrics you're keeping an eye on that help validate to you, yeah, Valeris is going to prove ultimately to definitely be a bargain. In other words, just anything that you've seen as you've had more and more time to look at the assets that you're particularly excited about with the combinations.

Valaris have recently announced a few very strong contracts, which are great, particularly in the jack-up market. Somebody had asked about that earlier. We're not really in a position to comment on the details of that, but we're excited about the combination for a number of reasons on the Florida side, but also on the jack-up side, that market appears to basically have bottomed out last year, earlier this year. We're very encouraged by the contracts that they signed. So kudos to the team. They've done great there, but we don't really have all the details on that.

Yeah, I think the fundamentals for our decision to want to move ahead with this combination were based on a constructive view, our constructive view of the market and what we felt it was going to be in the coming years. When we looked at Valeris and the assets that they own and operate and their ability to work across very different geographies and customers, we knew we were putting together a top tier asset based company that was going to be focused on delivering outstanding performance for our customers and finding solutions for what they needed in the go forward. So, you know, if you think about the metrics that we'll be looking at, obviously, we're looking at utilization and the visibility of the utilization stacking over time. And being, you know, Valeris fleet is largely contracted next year, and they've done a very good job of preparing to get their full fleet in operation from early Early 27, in fact, I think most of their rigs now and their floating fleet is working now at the end of this year. So we believe that we've positioned the transaction timing at an ideal point where they're going to have some contract backlog through 27, as are we, and then we'll be rolling rigs going forward into a very constructive cycle. That's probably, as I think about the transaction, I think it's playing out exactly the way we expected it to.

Terrific. Thanks a lot.

Thank you. We'll take our next question from Jeff LeBlanc with TPH Research. Please go ahead. Your line is open.

Good morning, Keelan and team. Thanks for taking my question. I wanted to see if you could provide some more color on the sequential rise in non-allocated O&M costs and how should we expect this bucket to trend in the subsequent quarters, given the commentary on inflation?

Most of that cost is associated with the increased activity we're seeing next year. roughly two-thirds of it is associated with fleet spares and then the balance is associated with some BOP recertifications and maintenance. So it's all associated with the activity levels. And as I mentioned, we've been pretty good about keeping our costs in check. We'll continue to scrutinize all of the expenditures. As I mentioned, this is sort of straight down the middle of the fairway, but there's really nothing untoward about the increase given the assets that are going back to work.

Okay, thank you very much. I'll hand the call back to the operator.

Thank you. We'll take our next question from Doug Becker with Capital One. Please go ahead. Your line is now open.

Thank you. Keelan, Roddy, I really wanted to circle back to your expectations for longer duration contracts. When we take a look at contracts this year, the average duration for drill ships is still meaningfully below 2024 and certainly 2014 if we go back that far. So I really wanted to get a better sense. Are you seeing these longer durations in formal tenders? Is it more based on conversations today? Or is it just anticipatory right now given the logical extension of the tight market we see today?

Yeah, well, I mean, so year on year, we're basically like last year, we were 245, I think was the average duration. This year, we're already 380 as the number of days on the average duration of contracts. So that's a meaningful increase for sure. Your comparison to the previous upcycle, the previous upcycle was very different because at the tail end of that upcycle, The durations had to be very, very long because it was a new build cycle. So nobody was building rigs to bring them out speculatively initially. And then once few of the speculative bills did come into the market, they were still always talking about, you know, three, four, five year terms. So the comparison to 2014, we're definitely a long way from a new build cycle. So that's not what we expect to see. But if you just go year on year, we're already up, you know, 50 plus percent than we were last year. We do see a pipeline that has several very long contracts in them. So by that we're talking two, three years, some even more than that. So in our current dynamic, we consider two, three years to be solid long term contracts. The dynamic to 2014 is not really a comparison in this environment.

Yeah, it's a very different cycle we're in and obviously the capital discipline being employed by our customers is poles apart from when it was in 2014. And so what we're seeing and why we're constructive is obviously the activity is growing, the demand for assets for developments and exploration is driving utilization. The utilization is starting to get booked now for out years in 28, 29, 30. And as we start to see that, then the lead time I think is an important metric to look at and how that will increase as opposed to the number of years associated with the contract. So I think you're going to see longer term contracts come through and I think you're going to see us contract them earlier for longer. in this particular growth cycle.

Now that's really helpful context. So reasonable to be thinking about two, three-year contracts becoming more normal, but don't hold out hope for a five-year plus contracts at this stage.

I'd probably go to the former rather than the latter. I think the discipline that we're seeing from our customers is they're contracting for their drilling programs, for their FIDs. and I don't think they're ready to make any sort of commitment on that sort of scale at this time.

No, makes sense. And maybe just a little more color on the outlook for the 20K completions market going forward.

Yes, solid. So there's more and more demand for that, certainly. With the increased exploration wells in certain basins, we expect that to continue up. The Gulf of Mexico, sorry, the Gulf of America has got plenty of opportunities there. There's not very many assets that can do it. And then we are seeing an interest from some overseas locations, depending on what the The anticipated pressures are going to be, so there's a few of them are kind of in the balance, but that's a relatively healthy position to be in.

Yeah, I think when you think about 20K completions, I mean, obviously a lot of our customers that are in that arena are talking about the 2030s in the US Gulf as the major source of production from those deep reservoirs. So building the exploration programs and commencing the development programs for those prospects will start in the latter part of this decade and obviously into the 2030s. So that's probably where the main 20K completion activity will really fire off.

Thank you. Thanks.

Thank you. This brings us to the end of today's meeting. We appreciate your time and participation. You may now disconnect.