Earnings Call Transcript
Transocean Ltd. (RIG)
Earnings Call Transcript - RIG Q3 2023
Operator, Operator
Good day everyone and welcome to today’s Q3 2023 Transocean's Earnings Call. Please note this call may be recorded. It is now my pleasure to turn today’s program over to Alison Johnson, Director of Investor Relations. Please go ahead.
Alison Johnson, Director of Investor Relations
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, CEO
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 an adjusted EBITDA margin of approximately 22.5%. As released in 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. 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 its 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 the 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 the 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. The 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 eight of the twelve 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 upgrading 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 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 increased contracted terms during this period. In April of 2022, twelve of our rigs were contracted for durations greater than twelve months, six were contracted for greater than twenty-four months, and only five were contracted for more than thirty-six months. By comparison today, seventeen of our rigs are contracted for durations greater than twelve months, a 42% increase. Fifteen are contracted for greater than twenty-four months, a 150% increase; and thirteen are contracted for more than thirty-six 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 the 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 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 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 up to three years; once again demonstrating our customers' 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 the country and 9 that brought new rigs into the country. Between the open centers including more than BMC 33, 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 further call 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 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 the basin in Indonesia. ENI also has an open tender for approximately 18 months of work in multiple countries in the region. And in Malaysia, we expect PTTEP 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; largely 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 that start getting two years in the future, the broader fundamentals also support our views of a sustained industry recovery beyond the 18-month time horizon. LifeStat recently reported that oil inventories in developed countries are approximately 115 million barrels below their 5-year average. Meanwhile, the International Energy Agency reported global crude stocks have also fallen to their lowest level since 2017. The IEA forecasts increasing oil demand through 2028 while OPEC projects a steady increase till at least 2045. These predictions are supportive of population and GDP growth projections, particularly for developing nations where renewables infrastructures are emerging. We continue to believe that much of the 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 cycle of cash. 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, CFO
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 an 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 rigs 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 for recently delivered eight-generation drillships, the Deepwater Atlas, Deepwater Titan, and the seventh-generation Deepwater Aquila. Looking closely 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 the Deepwater KG2 in Brazil related to an importation issue. A recent application of the laws governing importation was contrary to the application of the laws which had been applied to all previously imported rigs. This issue in the KG2 has been resolved and is expected to commence operations later this week. We do not expect similar issues with the other rigs scheduled to enter Brazil. Operating and maintenance expense in the third quarter was $524 million. This is below our guidance, primarily due to lower than anticipated 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 personnel expenses. Turning to the cash flow and balance sheet, we ended the third quarter with total liquidity of approximately $1.4 billion, including unrestricted cash and cash equivalents of approximately $594 million, approximately $183 million of restricted cash for debt service, and $600 million from our revolving credit facility. I would like to address the significant increase in our backlog and its impact 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 of 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 until the first quarter of 2024. For reference, we expect to either defer or capitalize about 60% of these costs with the 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 various factors. 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 on 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-related fees that were not incurred as anticipated up to 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 a three-year contract with Petrobras in Brazil and $16 million for the 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 continues to move to higher day rate contracts, our corporate imperatives are unchanged. First, we will focus on the 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 deleverage 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, Director of Investor Relations
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.
Greg Lewis, Analyst
Mark, could you elaborate on next year's guidance? I may be off by a rig or two, but I see about eight rigs with available or open revenue days in 2024. Some are idle, while others may roll off in Q3 of next year. Regarding the revenue guidance you're providing, can you offer any insights about those rigs? In Jeremy's prepared remarks, you mentioned white space. I assume some rigs are better positioned than others to get to work or perhaps extend. Any general thoughts you can share on that?
Mark Mey, CFO
Thank you for the question, Greg. If we consider our guidance of about $3.8 billion, taking the midpoint of the range, roughly 90% of that consists of contracted revenue. This leaves around 20% that Roddie and Keelan are actively involved in. We examine the rigs, assess available opportunities, and evaluate their probabilities. We then determine a day rate based on our planned day rate strategy for the next five years. In some instances, we will deploy the rig at that set day rate, while in other cases, we may have to assume that the rig will remain idle for varying periods depending on its location and type. Therefore, around 10% of the revenue is speculative, and we will update these assumptions as we progress through the quarters next year.
Jeremy Thigpen, CEO
Yes. To add to that, if we exclude the scripted reading of the Fleet Status Report, we are currently considering around 8 rigs. From our internal perspective, based on ongoing discussions with customers, we believe the actual numbers could be closer to 3. We feel optimistic about our ability to address those gaps as we move forward.
Greg Lewis, Analyst
I have a question for Roddie, which Jeremy hinted at in his opening remarks. There's clearly a lot of activity and demand from customers. As we sit here on the last day of October, I’m curious about how much of this is seasonal. Are operators starting to secure rigs in preparation for winter and gearing up for spring? Are there any seasonal factors we should consider regarding the anticipated increase in activity or the uptick in fixturing or contracting that many of us are waiting for?
Roddie Mackenzie, Chief Commercial Officer
Yes. There are a couple of things to consider. First, while the total number of fixtures may appear slightly lower this year, the duration of each fixture is progressively longer year-on-year. As such, the total rig days committed for 2023 looks very promising. As we approach the end of the year, we are focused on long-term engagements, with a few short-term items but mostly significant, long-term contracts on the horizon. We're not just looking at one-year agreements; we're considering contracts that could last three, four, five, or even ten years. While the statistics on the number of fixtures are important, our priority is to secure the right projects that offer long contract durations and favorable day rates, as our decisions aim to enhance returns and shareholder value. We'll continue pursuing this strategy. Regarding seasonality, we are currently in budget season for major operators, which typically leads to increased interest in the fourth quarter as they plan for fixtures in 2024 and issue tenders. Notably, some of the larger operators are currently seeking tenders, with more anticipated, particularly for multi-year, multi-rig, and multi-country contracts. We expect to see several of these in the near future.
Jeremy Thigpen, CEO
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, Operator
And our next question comes from Eddie Kim with Barclays.
Eddie Kim, Analyst
I wanted to inquire about the progression of day rates that we observed earlier this year. It seemed likely that we would have an announcement of a term contract at $500,000 a day before the year ends. While we still have two months remaining, it increasingly appears that this expectation has shifted to early next year. Do you agree with this view based on your discussions with customers? If so, could you provide any insight into the decline in contracting activity we've noticed over the past few months that's affected the timing?
Jeremy Thigpen, CEO
Our customers are strongly against a day rate starting with a five at this time. Like you, we're disappointed that we haven't seen one. It seems that there is a prevailing sentiment among 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 at that day rate. However, I believe it will happen. I can't say if it will occur within the next two months, as there are still some opportunities we're pursuing, but it will eventually happen.
Mark Mey, CFO
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. So we're kind of like 10%, 15% higher than the average. And when you turn that to the semi-submersibles, we go from $336,000 to $392,000. 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, Analyst
Could you remind us of the cash outlays related to the Deepwater Aquila rig over the next 12 months? I believe there was a shipyard payment to take delivery of the rig earlier this month. How much was that? And what do you expect the total activation cost will be to make the rig fully drill-ready before its contract with Petrobras?
Mark Mey, CFO
So Eddie, we put 20% down when we purchased the rig about a 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, Petrobras has 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, Analyst
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, CFO
That's correct, yes.
Operator, Operator
And we have our next question from Kurt Hallead with Benchmark.
Kurt Hallead, Analyst
I always appreciate the insights. In the context of terms and conditions, it appears you mentioned several opportunities that involve contract terms of three to five years. Historically, this wouldn't typically align with setting a new high day rate. Generally, some trade-off exists between contract terms and rates. I'm curious about these dynamics and your thought process regarding them, especially as you, as a management team, aim to maximize returns and cash flow as we enter this next upcycle.
Jeremy Thigpen, CEO
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, 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 three or five-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, CFO
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, Analyst
So I guess my follow-up question is, you mentioned some earlier questions about a slowdown in new contract announcements as we move into the second half of the year. But is there also an aspect where oil companies are observing the same rig availability situation as everyone else and are now deciding to delay project start times beyond 2024 because they are unable to secure the rigs they need?
Mark Mey, CFO
I think there's likely an aspect to that. For example, if you plan to implement a Plug and Abandonment program, you would prefer to delay it until day rates are lower or until you identify the right rig with the necessary specifications at a reasonable cost. If you examine the major oil companies, even though not all information is publicly available, you'll notice several long-term fixtures being established soon, utilizing higher-spec rigs. These companies are actively working to secure the appropriate assets for their needs. It's somewhat counterintuitive that there’s an increase in direct negotiations, which you might not see reflected in the tender market. I believe there will continue to be solid long-term contracts in place. We're witnessing a steady flow of fixtures being made for multiple years. Reflecting on last year, we had only a handful of rigs with long-term contracts. Now, around 15 to 17 of our rigs have an outlook of more than two years, and by the end of the year or Q1 next year, we anticipate this number will rise to approximately 20. This transition period indicates a decrease in short-term opportunities but an increase in long-term ones, which is part of the natural ebb and flow that was mentioned.
Operator, Operator
And our next question comes from David Smith with Pickering Energy Partners.
David Smith, Analyst
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 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, CEO
Yes, David, let's take this mass offline. I don't want to go through this when we try to talk about the macro...
David Smith, Analyst
Sorry. You bet.
Jeremy Thigpen, CEO
We can reconcile this for you offline.
David Smith, Analyst
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, CEO
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. 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, Operator
And our last question comes from Scott Gruber with Citigroup.
Scott Gruber, Analyst
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, CFO
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 new builds. 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, Analyst
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, CEO
It all depends on the asset because we have 10-year contracts with these OEMs. One benefit to Transocean from these agreements is that the rig equipment remains certified continuously throughout the year. The cost benefit arises from the fact that we pay a day rate to our vendors, allowing us to perform SPSs on the drillships while the rig is actively in service during the fifth and tenth years of the contracts. We're currently past the midpoint of these contracts and will begin considering renegotiating or terminating them for the 11th year and beyond. For us, the five and ten-year agreements are not significant, especially for drillships and clients out of service. However, for semisubmersible rigs, we need to take those into dry dock for inspections of the hull, pontoons, and undercarriages, which can take about 15 to 20 days.
Operator, Operator
And our next question comes from Fredrik Stene with Clarkson Securities.
Fredrik Stene, Analyst
I wanted to revisit the market, considering both the short to medium-term and long-term outlook. I believe we share a consensus that this market is likely to experience a prolonged upward cycle. However, due to recent downward revisions in estimates for drillers for 2024 and partially for 2025, there are concerns that 2024 may be somewhat volatile. You touched on the topic of white space, and I want to confirm what's happening behind the scenes. Specifically, in relation to your remarks about longer-term projects taking more time to complete, is the white space you might expect on a few rigs in 2024 for you and your peers due more to transitional contracts and project start-ups rather than any fundamental shift in your long-term market perspective? It seems that people just need time to make decisions, and as a result, we see this white space emerge, which shouldn’t be interpreted as indicative of a weaker market. I apologize for the lengthy explanation, but I hope it makes sense.
Jeremy Thigpen, CEO
No, that makes sense. Yes. Our perspective is that, for instance, we had a situation with a rig that didn't complete. If that had moved forward, some technical issues on wells would have made them decide against it. Assuming that the hedge was in place, it would be booked now, and we would be preparing for that contract. I don't believe the white space in a couple of spots reflects the market. It's more the result of various events. For instance, in the U.S., we did not experience hurricanes this year, which typically affects activity and the duration of some rig contracts. In other cases, options were not exercised on rigs because the results were so favorable that we opted not to drill additional wells. Sometimes, there were political issues or delays that prevented options from being taken. Looking back to last year, we had a lot of white space, but much of it was filled due to fortunate circumstances with programs running longer. This year, things have either gone as planned or we've completed tasks ahead of schedule. Overall, that's a positive development since it indicates a decrease in well costs for operators, which we believe will help generate greater demand moving forward. It's a bit unfortunate that some of those rigs were on short-term contracts, but the upside is that a large part of our fleet is transitioning to long-term contracts, alleviating these issues as we approach late 2024 and 2025.
Fredrik Stene, Analyst
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 the 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, CEO
Yes, a good example is what's happening in Brazil. While I can't discuss specific future projects, there are rumors of a project winner opting to use existing assets on the market instead of bringing out two new ones from the shipyard. This makes sense as it prioritizes utilizing the active fleet over reactivating or rolling out new rigs. This illustrates the discipline among drillers, who are cautious about introducing rigs to the market when it isn't necessary. They recognize that holding back capacity and focusing on active rigs is a smarter approach. Moving forward, I anticipate similar fluctuations, but these small adjustments are logical. We are not rushing to reactivate our rigs; we will only do so when it makes economic sense and we have a contract that justifies the investment. The primary outcome of any short-term work shortages will simply be delays in rigs coming out of the yard, and we will not be reactivating them speculatively. We will continue to operate based on contracts.
Operator, Operator
And we have our final question from David Smith with Pickering Energy Partners.
David Smith, Analyst
And a little bit big picture question. Just focusing on some of these five-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 give really solid returns for a reactivation, right, or one of the new builds that were bought from a yard earlier this year. But when I look at those seven, ten rigs that are still stacked or previously stranded, I only count those that aren't owned by you. I'm not including the Libra, that new builds, 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 six incremental seven drillships absorbed, those ones not owned by you? And then what happens to the cost of incremental supply when those are gone?
Jeremy Thigpen, CEO
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 timeframe. 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 five to six 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 five-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, 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, Director of Investor Relations
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.