Transocean Ltd. [RIG] Conference call transcript for 2023 q3
2023-10-31 17:23:10
Fiscal: 2023 q3
Operator: Good day everyone and welcome to today’s Q3 2023 Transocean's Earnings Call. [Operator Instructions] Please note this call maybe recorded. It is now my pleasure to turn today’s program over to Alison Johnson, Director of Investor Relations. Please go ahead.
Alison Johnson: Thank you, Mike. Good morning and welcome to Transocean’s third quarter 2023 earnings conference call. A copy of our press release covering financial results along with supporting statements and schedules, including reconciliations and disclosures regarding non-GAAP financial measures are posted on our website at deepwater.com. Joining me on this morning’s call are Jeremy Thigpen, Chief Executive Officer; Keelan Adamson, President and Chief Operating Officer; Mark Mey, Executive Vice President and Chief Financial Officer; and Roddie Mackenzie, Executive Vice President and Chief Commercial Officer. During the course of this call, Transocean management may make certain forward-looking statements regarding various matters related to our business and company that are not historical facts. Such statements are based upon current expectations and certain assumptions and therefore are subject to certain risks and uncertainties. Many factors could cause actual results to differ materially. Please refer to our SEC filings for our forward-looking statements and for more information regarding certain risks and uncertainties that could impact future results. Also, please note that the company undertakes no duty to update or revise forward-looking statements. Following Jeremy and Mark’s prepared comments, we will conduct a question-and-answer session with our team. During this time, to give more participants an opportunity to speak, please limit yourself to one initial question and one follow-up. Thank you very much. I’ll now turn the call over to Jeremy.
Jeremy Thigpen: Thank you, Alison and welcome to our employees, customers, investors and analysts participating on today's call. As reported in yesterday's earnings release for the third quarter Transocean delivered adjusted EBITDA of $162 million on $721 million of adjusted contract drilling revenues, resulting in adjusted EBITDA margin of approximately 22.5%. As released on our October 18 fleet status report, we recently added $745 million in incremental backlog, giving us a total of $9.4 billion. Of note, this is the sixth sequential quarter increase in our backlog. Now, to our latest fixtures [ph]. In India, the Deepwater KG1 received a 60-day extension with its current customer Reliance at a rate of $348,000 per day. As well as a 21-month contract with ONGC at a rate of $347,500 per day, excluding a mobilization fee of $5 million. The rig is now committed through the end of the year, at which time it will undergo a brief period of contract preparations before it’s program with ONGC commences in February 2024. As discussed on our second quarter earnings call, an operator in the U.S. Gulf of Mexico awarded the Deepwater Invictus, a P&A well, at a rate of $440,000 per day. The program was completed in third quarter. Finally in Brazil, the new build ultra-deepwater drillship, Deepwater Aquila was awarded a three-year contract with Petrobras at a rate of $448,000 per day, excluding a mobilization fee of 90 times contract day rate. The Aquila was delivered from the shipyard earlier this month and will soon receive customer specific upgrades for its initial contract which is expected to commence in the third quarter of 2024. Contract with Petrobras was particularly important as it facilitated the acquisition of the outstanding interest in our joint venture, Aquila Ventures Limited, through which we assumed full ownership of the Deepwater Aquila. Transocean now owns and with the commencement of the Aquila’s contract, will operate 8 of the 12 globally competitive 1,400 short-term hook load dual activity ultra-deepwater drillships in the world. The acquisition of the Aquila is consistent with our strategy of continuously hydrating [ph] our fleet, a strategy which has proven very effective, particularly over the last 18 to 24 months, as we have secured market leading day rates with these high specification assets. As an example, since the fourth quarter of 2022, our ultra-deepwater fleet average day rate has increased by approximately 33% to $416,000 per day. By the third quarter of 2024 based upon current firm backlog, we expect this average rate to increase to $437,000 per day. Based upon the status of discussions with customers, we expect that the Transocean Barents will be contracted for new work starting in mid to late-2024 until initially late-2026. And the Deepwater Skiros [ph] will be similarly committed to the early to mid-2025. Details of these prospects will be forthcoming assuming execution of fully binding customer commitments. Not only do we have significant backlog over the past several quarters but we also substantially linked-in contracting term during this period. In April of 2022, 12 of our rigs were contracted for durations greater than 12 months, 6 were contracted for greater than 24 months and only 5 were contracted for more than 36 months. By comparison today, 17 of our rigs are contracted for durations greater than 12 months, a 42% increase. 15 are contracted for greater than 24 months, a 150% increase; and 13 are contracted for more than 36 months, a 160% increase. Of our 2023 contracted backlog, just over 80%, now consists of programs of more than one year in duration; another clear indication that our customers believe in the longevity of this upcycle and in the capability of Transocean. The significant increase in contracted commitments is reflected in the size of our industry-leading backlog. From the beginning of 2022 to the present, we have added approximately $6.8 billion in backlog. When building our backlog maximizing EBITDA associated margins remained our goal and these data points clearly demonstrate the effectiveness of our long-standing asset strategy and portfolio management approach to placing our assets on contracts of appropriate and meaningful value. We take decisions that make most economic sense for the company and our shareholders; it means that at times, we may seek the highest day rate possible for a specific asset or job, a consequence of which may be that we accept short periods of idle time on individual assets. In other instances, we may determine that maintaining high utilization has the ultimate long-term financial impact; meaning that we fix an asset at prevailing or otherwise acceptable market rates for a longer duration, securing high-quality backlog, meaningful EBITDA generation and longer term visibility to future cash flows. As reflected in their budget processes, our customers continue to be disciplined in their allocation of capital. The result of this behavior is exhibited in the lumpiness of the timing of contract awards we have observed over the last couple of years. We expect this trend to continue. Our sizable backlog and portfolio approach to fixing our assets minimizes our exposure to this natural ebb and flow of customer activity, while best ensuring we achieve the best margin possible. Notwithstanding the timing of announced contracting activity, our customers are securing rigs for longer and longer durations and for programs expected to commence well into the future. This is evidenced by the increase in average contract awarded lead times which have increased significantly since 2021. Drillship contracting lead times have increased by approximately 53% to 319 days and semi-submersible contracting lead times have increased approximately 38% to 284 days. The number of global floater opportunities continues to expand, reflecting very strong demand and further encouraging our view of a longer term sustainability of the cycle. Indeed, overall demand remains on the rise with 84 rig years of activity expected to be awarded for 77 discrete [ph] programs starting in 18 months. Looking closer at each region, the U.S. Gulf of Mexico continues to be defined by direct negotiations with our customers, with operators engaging contractors of choice for specific opportunities. We see a steady stream of demand for short-term programs with independent operators and it’s a solid market with a limited supply of high specification ultra-deepwater assets. Notably, we are engaged in discussions for follow-on work for the Deepwater Atlas upon completion of its current contract and are already having conversations with numerous customers regarding additional 20-K programs, many of which are not expected to start for upto three years; once again demonstrating our customer’s belief in a prolonged upcycle. The Invictus is currently competing for multiple local campaigns, including one which we believe will require a high hook load seventh-generation drillships, the available supply of which is very limited. We are also actively marketing the inspiration in various jurisdictions around the world. As you well know Brazil continues to be a source of strong demand and based upon open tenders, we expect the active rig count to continue in the next 12 months from the 29 rigs operating today. Over the past year, there have been 27 awards made in Brazil; 18 for rigs already in country and 9 that brought new rigs into country. Between the open centers including [indiscernible] more than BMC 33 [ph], there are expected to be another 8 rig awards which should require two incremental rigs from outside of Brazil. This brings the addition of non-Brazilian rigs to 11 since the upcycle began. Furthermore, it's widely expected that more tenders in 2024 will keep all of the incumbent rigs busy and pending exploration success could demand it further called on the global market to add yet more rigs to Brazil. Clearly, Brazil is set to remain a pivotal long-term consumer of ultra-deepwater rigs, with active rig count expected to reach at least 36 in 2024-2025, just by fulfilling today's known tenders. Across the Atlantic, we see an excess of 20 opportunities scattered throughout Africa and the Mediterranean commencing in the next 18 months. For the first time in nearly a decade, Nigeria following its national election is showing significant signs of revival. We expect between two and four long-term programs to be tendered over the next six months, including three from international oil companies. In Angola, Chevron, Exxon and other large operators have a mixture of short and multi-year opportunities currently expected to commence in 2024. Additionally, Namibia may require more rigs as Total Energies has confirmed future development, while Chevron and Shell have programs expected to be awarded in 2024. The Namibian Ministry of Mines and Energy recently confirmed that projects requiring as many as five rigs are set to commence in 2024. And finally, in Mozambique, we expect tenders for both Total Energies and ENI [ph] in the coming months. In Australia, regulatory requirements continue to drive demand for plug and abandonment work. Additionally, several operators have indicated interest in securing rigs for additional multi-year programs. At this point, we anticipate formal tenders will be released in 2024 and expect our two rigs currently active in the region to be competitive for these tenders following their existing programs. As such, we expect both the Transocean Endurance and Transocean Equinox to remain in country for the foreseeable future. There have also been promising developments elsewhere in the eastern hemisphere. We anticipate that ENI will soon require a rig for follow-on development for its recent discovery in [indiscernible] basin in Indonesia. ENI also have an open tender for approximately 18 months of work in multiple countries in the region. And in Malaysia, we expect PTTEP [ph] and PETRONAS will come to market in the near future for an ultra-deepwater drillship with the commencement in 2024. Finally, we expect the high specification harsh environment market to remain tight, as active supply in Norway is now fully utilized; in large part due to the departure of numerous rigs to other markets. As witnessed recently in a couple of public announcements, many incremental programs will require operators in Norway to mobilize rigs from other regions. And since many if not all of the recently departed rigs will likely continue their active utilization outside of the Norwegian market, we expect this region to remain tight for the foreseeable future. In addition to the fact that our customers are fixing contracts which start getting [ph] two years in the future, the broader fundamentals also support our views of a sustained industry recovery beyond the 18-month time horizon. LifeStat [ph] recently reported that oil inventories in developed countries are approximately 115 million barrels below their 5-year average. While the International Energy Agency reported global crude stocks have also fallen to their lowest level since 2017. Meanwhile, the IEA forecasts increasing oil demand through 2028 while OPEC projects a steady increase till at least 2045. These predictions are supportive for population and GDP growth projections, particularly for developing nations where renewables infrastructures and [indiscernible]. We continue to believe them that much of new hydrocarbon development will come from deepwater basins as these have consistently shown to yield superior investment returns and produce some of the lowest carbon intensity barrels available today. Reliable third-party analysis suggests upstream offshore CapEx will increase materially over the next several years, crossing $200 billion next year and reaching $234 billion by the end of 2027. In summary, our outlook for long offshore deepwater drilling recovery remains firm and we'll continue to manage our rig portfolio to maximize value. As always, we will continue to place paramount importance on the safe and flawless execution of our operations to minimize the conversion -- to maximize the conversion cycle of cash [ph]. In this regard our performance is truly a team effort and I extend a sincere thank you to the entire Transocean team for their commitment every day to provide safe, reliable and efficient operations. And I'll turn the call over to Mark.
Mark Mey: Thank you. Thank you, Jeremy and good day to all. During today's call, I will briefly recap our third quarter results and then provide guidance for the fourth quarter. I will conclude with our preliminary expectations for full year 2024 including our latest liquidity forecast. As is our practice, we will provide more specific guidance for 2024 and will have our 2023 year-end call in February of next year. As reported in our press release which includes additional detail on our results, for the third quarter of 2023 we reported a net loss attributable to controlling interest of $220 million or $0.28 per diluted share. After certain adjustments, we reported adjusted net loss of $280 million. During the quarter we generated adjusted EBITDA of $162 million. Operating cash flows were negative $44 million, primarily due to approximately $135 million of contract preparation and mobilization costs, affecting 7 rigs starting new contracts in late 2023 and 2024, including 2 rigs in Brazil, 2 rig that being prepared for Brazil, 2 rigs bound for Australia and 1 rig operating in the eastern Mediterranean. The negative free cash flow of $94 million in the third quarter reflects the aforementioned negative $44 million of operating cash flow and $50 million of capital expenditures. Capital expenditures for the third quarter included $30 million ready to -- recently delivered eight-generation drillships that the Deepwater Atlas and Deepwater Titan and the seventh-gen plus -- seven-plus generation, Deepwater Aquila. Looking close at our results, during the third quarter we delivered adjusted contract drilling revenues of $721 million at an average daily revenue of approximately $391,000. This is consistent with our previous quarters despite a lower than expected operating activity which is mainly due to the delayed start on [indiscernible] Deepwater KG2 in Brazil related to an importation issue. A recent application of the laws governing infiltration was contrary to the application of the laws which had been applied to all previously important rigs. This issue in the KG2 has been resolved and will be expected to commence operations later this week. We do not expect some of the issues with the other rigs schedule to enter Brazil. Operating and maintenance expense in the third quarter was $524 million. This is below our guidance, primarily due to lower than in service maintenance costs and operating activity, primarily related to the delayed start of the KG2. General and administrative expense in the third quarter was $44 million; this was also below our guidance, mainly due to lower than anticipated professional service, IT related services fees and personal expenses. Turning to the cash flow and balance sheet, we ended the third quarter with total liquidity of approximately $1.4 million, including unrestricted cash and cash equivalents of approximately $594 million, approximately $183 million of restricted cash for debt service and $600 million from our enrolment revolving credit facility. And I would like to address the impact or the significant increase in our backlog is having on our revenue and operating costs. As Jeremy mentioned, in the last 22 months, we've added approximately $6.8 billion of backlog. Many of these contracts, including those with Deepwater Mykonos, Deepwater Corcovado, Deepwater Orion, KG2, Transocean Barents, Transocean Endurance and Transocean Equinox which together comprise $2.1 billion of this backlog increase, require substantial contract preparation and mobilization which typically must be completed prior to the commencement operations. We started to include these costs in the second quarter of 2023 and expect our EBITDA margins to be adversely affected by varying amounts to the first quarter of 2024. For reference, we expect to either defer or capitalize about 60% of these costs with a balance increasing expenses and reducing EBITDA. These preparation costs are obviously temporary in nature and will translate into higher day rate revenue and operating margins in future years. We anticipate quarterly increases in contractually revenues throughout 2024. I will now provide an update on our expectations for the fourth quarter of 2023 and full year 2024 financial performance. As always, our guidance reflects only contract related reactivations and upgrades. For the fourth quarter of 2023, we expect adjusted contract drilling revenue of approximately $760 million based on an average fleet-wide revenue efficiency of 96.5%. This quarter-over-quarter increase is mainly due to higher day rates on KG1, Corcovado, Mykonos and Petrobras 10,000; more operating days than at other service periods in the third quarter and expected commencement of the KG2 contract in the fourth quarter. This is partially offset by [indiscernible]. We expect fourth quarter O&M expense to be approximately $565 million. This quarter-over-quarter increase is mainly due to the timing of in-service maintenance activities, higher operating costs incurred in relation to the commencement of operations for the KG2 in Brazil and the Transocean Barents in Cyprus and a full quarter of activity for rigs that had other service periods in the third quarter. This is partially offset by lower costs incurred and idle rigs. We expect G&A expense for the fourth quarter to be approximately $55 million. This quarter-over-quarter increase is mainly due to the high professional and IT regulated fees that were not incurred as anticipated upto that quarter. Net interest expense for the fourth quarter is forecasted to be approximately $127 million; this includes capitalized interest of approximately $6.4 million. Capital expenses for the fourth quarter are forecasted to be approximately $270 million, including approximately $210 million related to the preparation of the Deepwater Aquila for 3-year contract with Petrobras in Brazil and $16 million with a Deepwater Atlas and Deepwater Titan. Cash taxes are expected to be $24.3 million for the fourth quarter. I'd like to provide a preliminary overview of our financial expectations for 2024. We currently forecast adjusted contract revenue to be between $3.7 billion and $3.9 billion. This includes approximately $200 million of additional services and reimbursable expenses. We expect our full year O&M expense to be between $2.1 billion and $2.3 billion. Finally, we anticipate G&A cost to be around $195 million. Our preliminary projected liquidity at the end of 2024 is $1.5 billion to $1.7 billion, reflecting our revenue and cost guidance and including the $600 million capacity of our undrawn revolving credit facility and restricted cash of approximately $340 million, most of which is reserved for debt service. This liquidity forecast includes 2024 CapEx expectations of $195 million, of which approximately $105 million is related to the Deepwater Aquila and approximately $90 million for sustaining and contract preparation CapEx. In conclusion, as our risk continue to move to higher day rate contracts, our corporate imperatives are unchanged. First, we will focus on safety of our people and execution of reliable and efficient operations. We also remain committed to strengthening our balance sheet and restoring value to equity holders. As such, we will continue to manage our allocation of capital prudently and in a manner that allows us to continue to delever without compromising safety and operational execution or high return growth opportunities. This concludes my prepared comments. Now I'll turn the call over to Alison.
Alison Johnson: Thanks, Mark. Mike, we're now ready to take questions. As a reminder to the participants, please limit yourself to one initial question and one follow-up question.
Operator: [Operator Instructions] And our first question comes from Greg Lewis with BTIG.
Greg Lewis: I guess, Mark, I was hoping you could talk a little bit more about the next year's guidance and thank you for that. I may be off by rig or 2 but as I count rigs with available or open revenue days in 2024, I'm looking at about -- I think it's around 8 rigs that have -- some are idle, some maybe roll off in Q3 of next year. As I think about the revenue guidance that you're giving, any kind of color you can kind of talk to on those rigs? I mean, clearly, in Jeremy's prepared remarks, you announced white space. Is there -- I would imagine some rigs are better positioned than others to get to work or to maybe extend. Any kind of broad strokes you can give around that?
Mark Mey: So Greg, thanks for the question. Firstly, if you look at our guidance of approximately $3.8 billion, take the middle of the range, about 90% of that is contracted revenue. So there's about 20% which we -- obviously, Roddie is -- and Keelan are very much involved in that. We sit down and we look at the rigs, we look at the opportunities, we look at the probability obviously. And then we assume a day rate based upon our 5-year planned day rate deck. And in some cases, we will put that rig to work using that day rate deck. Other times we will assume that the rig sits idle for a little while, or a long while depending on where it is and what type of rig it is. So there is an element, approximately 10% in that which is spec revenue and we update that as we go through the quarters next year.
Jeremy Thigpen: Yes. I'll add a little bit to that. If you take out the -- I guess, the script reading of the Fleet Status Report, then we are -- currently look at about 8 rigs. In our internal view, I mean, obviously, we can revolt [ph] all the conversations we have with customers. But we think that numbers may be closer to 3% [ph]. So we're pretty optimistic about being able to fill those gaps as we go forward.
Greg Lewis: And then for Roddie [ph] chiming in, I did have a question and Jeremy alluded to it in his prepared remarks. I mean, clearly, there's a lot of activity going on and a lot of demand from customers. As we sit here, I guess, I talk to the last day of October -- Happy Halloween, everybody. I guess what I'm wondering is, how much of it is like -- is part of this seasonal, i.e., we're heading in the winter and maybe we see kind of operators starting to lock up some of these rigs as we move -- as they're starting to get ready for spring time? Any kind of seasonal factors maybe we could be thinking about in terms of that eventual activity, or not even activity, fixturing or contracting pickup that I think a lot of us are waiting for?
Roddie Mackenzie: Yes. I think -- so a couple of things to unpack there. So first of all, it may look like the absolute number of fixtures is slightly lower this year but the truth is the length of each one of those fixtures is progressively longer year-on-year. So the actual number of rig days committee is looking really, really good for '23 already. So as we enter like the last couple of months of the year, the things that we're actively engaged in just now are all long-term in nature. There's 1 or 2 short-term things but the majority of the stuff, especially the headlines that you're going to see over the next couple of 3 months is all for long-term stuff. And we're not just talking about 1-year deals. We're talking about like 3, 4, 5, maybe even 10-year deals. So there's a lot of stuff in terms of the stats on the number of fixtures made. But what we're looking at is kind of, Jeremy said, is that making sure we're picking up the right pieces of work that give us that length of contract but also at really good day rates, because the decisions we make are all about generating returns and value to the shareholders. So we're going to continue pushing down that track. And in terms of seasonality, I think you're basically right in budget season right now for the major operators, so they're kind of going through that churn. And typically, what we see is a lot of interest in the fourth quarter where people start thinking about what other fixtures they'll make in '24 and start putting out tenders. So you may or may not be aware but there's -- some of the big operators are out for tenders just now and there's more expected for kind of multiyear, multi-rig, multi-country head of tenders [ph]. So we expect to see several of those in the near term.
Jeremy Thigpen: Yes. The other thing I'd say to that is they're making bigger commitments now for longer periods of time and they just take more time to process that decision and execute. And so I wouldn't read anything else into it other than that.
Operator: And our next question comes from Eddie Kim with Barclays.
Eddie Kim: Just wanted to ask about the day rate progression that we saw earlier this year. It seemed almost like a foregone conclusion, that we've seen announcement of a term contract at $500,000 a day before year-end. And I know we still have 2 months left but it increasingly feels like that expectation has shifted to early next year instead. Would you agree with that based on your conversations with customers today? And if so, any particular reason for the -- kind of the air pocket of contracting activity that we've been seeing the past few months that's pushed the timing out of it?
Jeremy Thigpen: I would say our customers are violently opposed to a day rate that starts with a 5 at this point in time. And like you, we've been disappointed that we haven't seen one. I do feel like there is -- that's kind of become the new feeling for our customers that they don't want to see any of us push through that number and they certainly don't want to be the first to agree to a contract of that day rate but it's going to happen, Eddie. I don't know if it's going to happen over the next 2 months. There's still some opportunities out there that we're pushing but it will happen.
Mark Mey: Yes. I'd also add on that, as you look at the -- kind of the average drillship fixture across the market of all the '23 so far, that's about $367,000 a day. Transocean's average across the '23 fixtures for us is $415,000 [ph]. So we're kind of like 10%, 15% higher than the average. And when you turn that to the semisubmersibles, we go from $336,000 to $392,000 [ph]. So we're 17% higher on the semis in terms of our fixtures. So look, it's certainly not us as holding that back. But as Jeremy said, the customers obviously are looking to exercise as much capital discipline as they can which we totally respect. But certainly for us, scoring day rates in the high 400s is good business any day of the week.
Eddie Kim: It sure is. Just my follow-up is on the Deepwater Aquila. Could you just remind us of the cash outlays related to this rig over the next 12 to 18 -- 12 months, I should say? I believe there's a shipyard payment to take delivery of the rig earlier this month. How much was that? And what do you expect to be the -- kind of the all-in activation cost for the rig to make it completely drill ready before its contract with Petrobras?
Mark Mey: So Eddie, we put 20% down when we purchased the rig about 1 year ago. So the final payment which we made in early October was the remaining 80%, $160 million. As I said in my prepared comments, we intend to spend about $200 million on preparing the rig for Brazil. As you know, Petro set [ph] some stringent requirements around what the rig has to be able to do, what equipment they want, including NPD. And we will be taking the rig into Brazil sometime in June, July, August of next year.
Eddie Kim: Sorry, Mark, the $210 million related to the Aquila, that's CapEx guidance for fourth quarter, right? And then I thought I heard an additional $105 million of CapEx for next year. Did I hear that correct?
Mark Mey: That's correct, yes.
Operator: And we have our next question from Kurt Hallead with Benchmark.
Kurt Hallead: I always appreciate the color. So in the -- just in the context of terms and conditions and it looks like you have -- you referenced a number of opportunities where you're going to see a 3 to 5-year kind of contract terms. Again, that kind of historically wouldn't necessarily jive with a landmark new high day rate, right? Usually, you're trading some term for rate. So just kind of curious as to those dynamics and kind of how you're thinking about them? And again, in the context of you as a management team trying to maximize returns and maximize cash flow as we go into this next up cycle?
Jeremy Thigpen: Yes. I would say we covered it a bit in the prepared remarks and I think a bit last quarter, too, Kurt but I mean the -- we sit as a team and really evaluate each rig and each opportunity. And there are times with certain rigs where you say, you know what, we don't want to fix this rig to a longer-term contract that we believe is going to be a discount to market by the end of that contract. And there are other rigs, we want to keep that rig and kind of test the market on short-term or continue to push day rates as much as we possibly can. Now the risk in that is you get some idle time every now and then, you get some white space, as we do right now with the Invictus. But that is the rig that we have continually used to push rates and got us to where we are today. So with some of our rigs, we will continue to take that strategy. With other rigs, we'd like to lock them up into 3 or 5-year contracts at what might be a discount towards the tail end of that contract because it gives us that firm backlog and that visibility to future cash flows. So it's really this portfolio management approach that we've talked about on previous calls and we continue to do that with each opportunity.
Mark Mey: Yes. I think I'd just add, we also are very specific about what we target in terms of the specification of the rig matching up with the requirements of the tender or the program. So I'm kind of a little bit counter to previous cycles where all the best rigs got fixed first at the lowest day rate. We've been quite purposeful in trying to keep a couple of them available so that later in the cycle the operators can still get their hands on high-specification top spec rigs. And of course, that might come with a little extra cash.
Kurt Hallead: So I guess my follow-up question here is, you kind of referenced or you addressed some of the questions earlier on about -- a little bit of a lull in new contract announcements as we kind of progress through the second half of the year. But is there also an element of -- are you seeing an element where the oil companies are kind of looking at the same rig availability profile that everybody else kind of sees and basically now at a point where they are making decisions to push off project start times beyond 2024 because they just can't get the rigs that they want?
Mark Mey: I think there's probably an element of that, that if you -- for example, if you're going to do a P&A program, then obviously, you would prefer to be able to push that to a point that you think day rates will be lower or you find the right rig or the specification rig that can do the work and you can get it at a reasonable rate. I think, if you look at what's going on with the majors -- and I realize that not all of the information is public but if you look at what's going on with the majors, you're going to see several fixtures made in the next short while that are for multiple years and they're on higher-spec rigs. So these guys are in the market today, kind of working diligently towards placing the right assets where they need them. So I kind of think it's a little counterintuitive that you see that there's a lot more direct negotiation stuff going on today that you don't necessarily see in the tender market as such. And I just think you're going to continue to see -- I wouldn't even say it was a debt; it's just good in terms of long-term contracts. You're going to continue to see steady fixtures being made for multiple years. And if you think about where we were like just 1 year ago, we were looking at an activity chart that literally had a couple of handfuls of rigs that had the longer-term stuff on it. Now we're talking about somewhere in the region of, kind of, 15 to 17 of our rigs have got more than 2 years' outlook on them. And of course, by the end of the year or in Q1 next year, we expect that to get up to 20 or so. So I mean, I just think this is the transition period because you just have fewer short-term opportunities but longer and larger number of long-term opportunities. So this is just the -- kind of the natural ebb and flow that Jeremy was talking about.
Operator: And our next question comes from David Smith with Pickering Energy Partners.
David Smith: So this is actually a question about cost. So please bear with me a second. But the average reported ultra-deepwater rate in Q3, $406,500 [ph] a day. I know that doesn't include reimbursables or contract termination. But multiplying that rate times the in-service days reported suggests about a $44 million difference versus the reported ultra-deepwater revenue of $516 million. The delta for the ultra-deepwater fleet have been averaging around $20 million the last several quarters. I just want to verify if Q3 was just a big step up in the reimbursable revenues with a likely similar amount of cost?
Jeremy Thigpen: Yes, David, let's take this mass offline [ph]. I don't want to go through this when we try to talk about the macro...
David Smith: Sorry. You bet.
Jeremy Thigpen: We can reconcile this for you offline.
David Smith: Then a quick follow-up, if I may, the support cost, $67 million, was that a little step-up versus the prior run rate? Was there anything anomalous? Or is this a good run rate to use?
Jeremy Thigpen: Well, we do have higher reimbursables, no question about that and we've seen more and more customers requesting that we buy things, perform services on their behalf. It's so much easier for them. So as an example, if you look at the Petrobras contracts signed 2 or 3 years ago, very low in reimbursables. And you look at the ones, now much, much higher. So yes, there is a higher run rate of reimbursables. But like I said, we can give this to you offline and give you the math.
Operator: And our last question comes from Scott Gruber with Citigroup.
Scott Gruber: I had a question on CapEx for next year. Mark, the base maintenance spend for next year at around $90 million sounds rather benign. Are you just not seeing much inflation in service costs? Or is this really a reflection of the initiatives around how you guys manage maintenance spend that's keeping the lid on spending?
Mark Mey: So a couple of things there. Scott, one, that $90 million includes some contract prep of about $10 million. So the rest is about $80 million. It was actually a little bit lighter than you would think it is. We have seen some inflation, no question about that. But as you know, we do have what we refer to as care agreements with most of our OEMs. And part of the care agreement is a cap on the inflation each year and that cap range is around 2%. So even if inflation is 4% or 5% which it clearly is at the moment, we're not experiencing all of that with a lot of our spend. So next year is also a lighter year when it comes to SPSs for rigs that are older. So you're not going to see a lot of money being spent on that. And we've also maintained our rigs fairly well throughout the down cycle. So we're not going to have a catch-up in '23, '24, '25 and beyond. So I think this is what you can expect from us going forward. Our CapEx has been very high because of newbuilds. But on a sustaining basis, we've been saying this for a long time and don't expect to see very big numbers from us going forward.
Scott Gruber: And just a quick follow-up on the SPS side. You will have a few more, it looks like in '25 and '26. And I know you're not spending as much on the 10-year SPS this cycle as you did last cycle but just kind of ballpark what would a 10-year SPS run you now?
Jeremy Thigpen: It all depends on the asset because with these agreements -- we have 10-year contracts with these OEMs. So part of the benefit to Transocean with regard to these agreements is that the rig equipment stays certified 24/7, 365. So the cost benefit -- because we pay a day rate to our vendors, the cost benefit is that we can do -- for the drillships we can do the SPSs while the rig is working in-service for the 5-year and 10-year. Obviously, we're just past halfway with these contracts. We'll start to look at renegotiating this or terminating this or whatever we decide to do with regard to those agreements for the years 11 through 15 or beyond. But clearly, for us, the 5 and 10-year is not a big number and most importantly, for the drillships and other out-of-service clients. For the semis [ph], however, we do have to take those rigs into the dry rock because we have to inspect the hull, the pontoons and under carriers of the rigs and that can be 15 to 20 days.
Operator: And our next question comes from Fredrik Stene with Clarkson Securities.
Fredrik Stene: I wanted to circle a bit back to the market here and weighing short to medium term versus long-term outlook. And I think we're pretty much aligned in what we think about this market that it's going to be a highly sustained long upcycle. But based upon how estimates for drillers in general has been revised a bit downwards now for '24 and partially '25 over the last few months, there seems to be some concerns that at least '24 will be, call it a bit volatile. And then you partially touched upon it with white space and all that. But I just wanted to confirm that what's happening behind the scenes or underlying? And then, maybe particularly in relation to your comments about longer-term work taking longer to finalize. Is the white space that we're -- you might see on a few rigs in '24 for you and peers more like a result of, call it, what can we say, arbitrary contracts and start-ups are not really a result of anything changing in how you look at this market in the long run. It's just people need time to decide and the consequence of that is a bit of white space, although it shouldn't be taken at a time of a weaker market. Sorry, for all those words but hopefully [ph].
Jeremy Thigpen: No, that makes sense. Yes. So really, that's exactly our view is that -- for example, we talked about a couple of rigs. So if we take the [indiscernible] actually was a winner in one of the tenders that just did not get consummated. So she would have -- assuming that had gone ahead, there was some technical issues on wells that they decided not to do. But assuming that got a hedge, she would be booked now and then we'd be busy getting ready for that contract. So, I really don't think the fact that you have a couple of spots of white space are indicative of the market. I think it's more indicative of just confluence of events. So for example, in the U.S. we really had no hurricanes this year offsetting any activity which is great, right? But normally, that does have an impact on the length of term for some of these rigs. And likewise, in some of the other places we had instances where options were perhaps not taken on rigs, in one case, actually, because the results were so good that we decided not to drill the extra wells. So that's kind of like a victim of your own success. But other instances where either some political stuff happens or there's some delay on trees or something like that -- and options weren't taken. So I think like, if we think back to where we were last year, we had tons of white space and a lot of it got filled because we "got lucky" in terms of programs running longer. This year things have not run longer. They've really gone either 2 plan or we've delivered ahead of time. So on a macro view, that's actually a really positive thing because it means that the well cost for the operators are coming down again. And we think that's positive for building larger demand as we go forward. It's just slightly unfortunate because some of those rigs were on the short-term contracts that we talked about. But the really good upside with a substantial portion of our fleet migrating to the long-term contracts, those things are not going to be an issue anymore as we step into -- later in '24 and '25.
Fredrik Stene: And just a follow-up on that. Now that we're seeing some of this white space in '24 for these various reasons, do you think, all else equal, that this has delayed the pace at which capacity will be reactivated, either from cold stacks or from yard, both kind of for the market as a whole but also on your own now? I think you're controlling most of that cold stack.
Jeremy Thigpen: Yes. So like a good example might be what's happened in Brazil. So obviously, I can't really talk about fixtures that have yet to be made but there's rumours that there was a switch by a winner of a particular project that they decided to put forward assets that are already on the market rather than bringing out 2 assets from the shipyard. So that would be a consequence of -- well, it makes sense to place your active fleet ahead of reactivating or standing up newbuild rigs. So that's probably the best example to date that there is still plenty of discipline there amongst the drillers that they're not bringing out rigs at all costs. They're basically saying hang on a minute, this makes sense for us to keep that capacity off the market and to place our active rigs. So I think you'll see that kind of ebb and flow as we go forward. But yes, for the most part, that probably -- little adjustments like that make a lot of sense. And certainly, our position has always been -- we are not in a hurry to reactivate the rigs. We are only going to do it when it makes economic sense when we have the contract that generally justifies spending the money to do that. So again, I think the only real consequence of any shortness of work in the near term is that those rigs will be delayed from coming out of the yard. And certainly, we will not be reactivating speculatively. So we'll still work to contract on that.
Operator: And we have our final question from David Smith with Pickering Energy Partners.
David Smith: And a little bit big picture question. Just focusing on some of these 5-year plus programs that operators are looking to build. I expect they're looking for a discount to leading edge rates. And maybe they could get those discounts with rigs that gives really solid returns for a reactivation, right, or one of the newbuilds that were bought from a yard earlier this year. But when I look at those 7, 10 rigs that are still stacked or previously stranded, I only count that aren't owned by you. I'm not including the Libra, that newbuilds, I think those are going to cost a lot more. My question to you is, just given your view of demand, when do you think we see these last 6 incremental 7 [ph] drillships absorbed, those ones not owned by you? And then what happens to the cost of incremental supply when those are gone?
Jeremy Thigpen: So don't take my word for it. But I think Westwood Energy had an article out recently that they expect utilization to reach 100% in the kind of late '24, '25 time frame. And then the following year in '26, they were projecting 104% or 105% utilization. So what that tells you is that's the time frame in which you would expect to see all of those rigs reactivated. So in their projection you've basically got all of the stranded assets being brought out of the yard, put to work and there's a call on 5 to 6 additional cold stacked assets in that timeframe. So again, my crystal ball is a little biased but I would say, if you follow some of the comments today elsewhere, you'll probably point to the '25 time frame as being completely sold out of active rigs. Most all of the stranded assets, either being deployed or about to be contracted for future deployment and then we'll start thinking about when is the right opportunity to bring out the stacked assets. I would also say the first part of your question, to address the multiyear tenders, that's clearly the case is that operators are looking to secure capacity at a day rate that they feel is acceptable and works for the projects. And there are some compromises in that. One of the compromises being, it's a lot easier to do a lower day rate if you have the surety of a long-term contract. But also, I would not count that as being seventh gen rigs only. I think you're going to see that the sixth gen rigs are quite attractive for those. So if you see what happened in Brazil, basically, a lot of the sixth gens went to work for long periods of time in Brazil because they're perfectly adequate for those campaigns. I think you're going to see the same thing on some of these long-term 5-year deals. It's not necessarily the top spec rigs that are going to do it. They're going to be fit for purpose rigs because, again, that's how you get the right day rate for that asset for a long period of time.
Operator: And we have now reached the allotted time for our Q&A session. I will now turn the call back over to Alison Johnson for closing remarks.
Alison Johnson: Thank you, Mike and thank you, everyone, for your participation on today's call. We look forward to talking with you again when we report our fourth quarter 2023 results. Have a good day. This does conclude today's program. Thank you for your participation. You may now disconnect.
