Transocean - Q3 2023

Transcript

Operator (participant)

Good day, everyone, and welcome to today's Q3 2023 Transocean earnings call. At this time, all participants are in a listen-only mode. Later, you will have an opportunity to ask questions during the question-and-answer session. You may register to ask a question at any time by pressing star one on your telephone keypad. Please note this call is being recorded. It is now my pleasure to turn today's call over to Alison Johnson, Director, Investor Relations.

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 adjusted EBITDA margin of approximately 22.5%. As released on our October 18th 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 preparation 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 drill ship. 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, Liquila 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 ton hook load, dual activity, ultra-deepwater drill ships in the world.

The acquisition of the Aquila is consistent with our strategy of continuously high-grading our fleet, a strategy which has proven very effective, particularly over the last 18-24 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 Skyros will be similarly committed until 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 lengthened contracting term during this period. In April 2022, 12 of our rigs were contracted for durations greater than 12 months. Six were contracted for greater than 24 months, and only five 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've added approximately $6.8 billion in backlog.

When building our backlog, maximizing EBITDA and associated margins remains 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. This 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 optimal 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 award 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 this cycle.

Indeed, overall demand remains on the rise, with 84 rig years of activity expected to be awarded for 77 discrete programs starting in the next 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 amidst 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 20K 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 drillship, 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 over 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 nine that brought new rigs into country. Between the open tenders, including Buzios, Sepia, [inaudible], and BM-C-33, there are expected to be another eight 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 a 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 or 2025, just by fulfilling today's known tenders. Across the Atlantic, we see in 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 TotalEnergies 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 TotalEnergies 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 Kutai Basin in Indonesia. ENI also has an open tender for approximately 18 months of work in multiple countries in the region. In Malaysia, we expect PTTEP and Petronas will come to market in the near future for an ultra-deepwater drillship with a 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. 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 with start dates two years in the future, the broader fundamentals also support our views of a sustained industry recovery beyond the 18-month time horizon. Rystad 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 through at least 2045. These predictions are supported by population and GDP growth projections, particularly for developing nations, where renewables infrastructure is in its infancy. We continue to believe 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 a prolonged offshore deepwater drilling recovery remains firm, and we will 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 of operations. In this regard, our performance is truly a team effort, and I extend a sincere thank you to the entire transition team for their commitment every day to provide safe, reliable, and efficient operations. I'll now turn the call over to Mark.

Mark Mey (EVP & CFO)

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 when we 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 seven rigs starting new contracts in late 2023 and 2024, including two rigs in Brazil, two rigs being prepared for Brazil, two rigs bound for Australia, and one 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 related to two recently delivered 8th-generation drillships, the Deepwater Atlas and Deepwater Titan, and the 7th-gen-plus, 7-plus-generation new-build Deepwater KG2.

Looking closer at our results, during the third quarter, we delivered adjusted contract drilling revenues of $721 million and an average daily revenue of approximately $391,000. This is consistent with our previous guidance, despite the lower-than-expected operating activity, which is mainly due to the late start on a 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 have been applied to all previously imported rigs. This issue on the KG2 has been resolved, and the rig 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 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 is 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 undrawn revolving credit facility. Now, I would like to address the impact of 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 of operations. We started to incur these costs in the second quarter of 2023 and expect our EBITDA margins to be adversely affected by varying amounts through 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 contractual 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 upon an average fleet-wide revenue efficiency of 96.5%. This quarter-over-quarter increase is mainly due to higher day rates on the KG1, Corcovado, Mykonos, and Petrobras 10000. More operating days than had other service periods in the third quarter and expected commencement of the KG2 contract in the fourth quarter. This is partially offset by idle periods and several rigs. 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 out-of-service periods in the third quarter. This is partially offset by lower costs incurred on idle rigs. We expect general 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 in the third quarter. Net, 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 its 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 costs to be around $195 million.

Our preliminary projected liquidity at the end of 2024 is $1.5 billion-$1.7 billion, reflecting our revenue on 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 are related to the Deepwater Aquila and approximately $90 million for sustaining and contract preparation CapEx. In conclusion, as our rigs continue to move to higher day rate contracts, our corporate imperatives are unchanged. First, we'll 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 in a manner that allows us to continue to deliver without compromising safety and operational execution or high-value growth opportunities. This concludes my prepared comments. Now I 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.

Operator (participant)

Thank you. At this time, if you would like to ask a question, please press star one on your telephone keypad. You may remove yourself from the queue at any time by pressing star two. Once again, that is star one if you'd like to ask a question. Our first question comes from Greg Lewis with BTIG.

Gregory Lewis (Managing Director of Energy and Infrastructure)

Well, hey, thank you and good morning, and thanks for taking my questions, everybody. You know, I guess, Mark, I was hoping you could talk a little bit more about the next year's guidance, and thank you for that. You know, I may be off by a rig or two, but as I count rigs with available or open revenue days in 2024, I'm looking at about eight... I think it's around eight rigs that have, you know, 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 kinda talk to on those rigs, I mean, clearly in Jeremy's prepared remarks, he announced white space.

Is there? You know, I would imagine some rigs are better positioned than others to get to work or to maybe extend. Any kinda broad strokes you can give around that?

Mark Mey (EVP & CFO)

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 10%, which we obviously, Roddie’s and Keelan’s 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 five-year plan day rate deck. And in some cases, we will put that rig to work using that day rate deck. Other times, we'll assume that the rig sits idle for a little while, or a long while, depending on where it is and, you know, 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.

Roddie Mackenzie (EVP & Chief Commercial Officer)

... Yeah, I'll add a little bit to that. You know, if you take the strict reading of the fleet status report, then we are currently looking at about eight rigs. In our internal view, I mean, obviously, we can't divulge all the conversations we have with customers, but we think that number is maybe closer to three. So, we're pretty optimistic about being able to fill those gaps as we go forward.

Gregory Lewis (Managing Director of Energy and Infrastructure)

Okay, that's great to hear. And then, you know, Roddie, since you're chiming in, you know, I did have a question, right? I mean, and more—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. You know, as we sit here, I guess, oh, it's October—the last day of October. Happy Halloween, everybody.

You know,[crosstalk] I guess what I'm wondering is: how much of it is, you know, part of this seasonal, i.e., we're heading in the winter and maybe we see, you know, kind of, operators start to lock up some of these rigs as we move, you know, as they're starting to get ready for springtime? 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 (EVP & Chief Commercial Officer)

Yeah, 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 committed is looking really, really good for 2023 already. So, as we enter, like, the last couple of months of the year, you know, the things that we're actively engaged in just now are all long-term in nature. There's one or two short-term things, but the majority of the stuff, especially the headlines that you're gonna see over the next couple of three months, is all for long-term stuff. And we're not just talking about, you know, one-year deals. We're talking about, what?

three-, four-, five-, maybe even 10-year deals. So there, there's a lot of stuff in terms of the stats on the number of fixtures made, but what we're looking at, as kind of Jeremy said, is, like, 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, you know, the decisions we make are all about, you know, generating returns and value for the shareholders. So, we're gonna 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 2024 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 multi-year, multi-rig, multi-country kind of tenders. So expect to see several of those in the near term.

Jeremy Thigpen (CEO)

Yeah, 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. So I wouldn't read anything else into it other than that.

Gregory Lewis (Managing Director of Energy and Infrastructure)

Super helpful, everybody. Thank you.

Jeremy Thigpen (CEO)

Thanks, Greg. Happy Halloween.

Operator (participant)

Our next question comes from Eddie Kim with Barclays.

Eddie Kim (VP of Equity Research)

Hi, good morning. Just wanted to ask about the day rate progression that we saw earlier this year. It seemed almost like a foregone conclusion that we'd see an announcement of a term contract at $500,000 a day before year end. And I know we still have two 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 this timing out a bit?

Jeremy Thigpen (CEO)

I would say our customers are violently opposed to any day rate that starts with a five at this point in time. And like you, we've been disappointed that we haven't seen one. I do feel like that's kind of become the new ceiling 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 gonna happen, Eddie. I don't know if it's gonna happen over the next two months. There's still some opportunities out there that we're pushing, but it will happen.

Roddie Mackenzie (EVP & Chief Commercial Officer)

Yeah, yeah. No, no, I'd also add in that, as you look at the kind of the average drillship fixture across the market of all of 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, you know, 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 that's holding that back. But as Jeremy said, you know, 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 (VP of Equity Research)

Got it. 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, or 12 months, I should say? 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 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 (EVP & 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, so we tend to spend about $200 million on preparing the rig for Brazil. As you know, Brazil, Petrobras has some stringent requirements around what the rig has to be able to do, what equipment they want, including MPD. And we will be taking the rig into Brazil sometime in June, July, August of next year.

Eddie Kim (VP of Equity Research)

Okay, got it. 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 (EVP & CFO)

That's correct, yes.

Eddie Kim (VP of Equity Research)

Okay. Okay, understood. Thanks for that, clarification. I'll turn it back.

Operator (participant)

We have our next question from Kurt Hallead with Benchmark.

Kurt Hallead (Head of Global Energy)

Hey, good morning, everybody.

Jeremy Thigpen (CEO)

Morning, Kurt.

Kurt Hallead (Head of Global Energy)

Always appreciate the, the color. So in the, just in the context of, terms and conditions, and looks like you have, you reference a number of opportunities where you're gonna see three-five-year kind of contract terms. Again, that kinda historically wouldn't necessarily jive with a landmark, you know, new, new high day rate, right? Usually, you're trading some, some term for, for rate. So just kinda curious as to, you know, those dynamics and, and kinda how you're thinking about them, and, and again, in the context of you, as a management team, you know, trying to maximize returns and maximize cash flow, flow as we go into this next, upcycle.

Jeremy Thigpen (CEO)

Yeah, I would say we covered it a bit in the prepared remarks, and I think a bit last quarter too, Kurt, but I mean. You know, 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 wanna fix this rig to a longer-term contract that we believe is gonna be a discount to market by the end of that contract. And there are other rigs, we wanna keep that rig and kinda test the market on short-term work and 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, you know, a discount towards the tail end of that, sort of 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.

Roddie Mackenzie (EVP & Chief Commercial Officer)

Yeah.

I think I'd just add, you know, 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, you know, kind of a little bit counter to previous cycles, where all the best rigs got fixed first at the lowest day rates, 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, you know, high-specification, top-spec rigs, and of course, that might come with a little extra cash.

Kurt Hallead (Head of Global Energy)

Gotcha. Thanks for that. So, I guess my follow-up question here is, you kinda referenced or you addressed, you know, some of the questions earlier on about a little bit of a lull in new contract announcements as we've kind of progressed through the second half of the year. But is there also an element of, you know, or are you seeing an element where the oil companies are kinda looking at the same rig availability profile that everybody else kinda 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, you know, the rigs that they want?

Roddie Mackenzie (EVP & Chief Commercial Officer)

I think there's probably an element of that. For example, if you're gonna do a P&A program, then it 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, you know, not all of the information is public, but if you look at what's going on with the majors, you're gonna 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, kinda working diligently towards placing the right assets where they need them. So I kinda think it's a little counterintuitive, that you see 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 gonna continue to see, you know, I wouldn't even say it was a dip. It's just going in terms of long-term contracts, you're gonna continue to see steady fixtures being made for multiple years. And if you think about where we were, like, just one year ago, you know, we were looking at an activity chart that literally had, you know, a couple of handfuls of rigs that had the longer-term stuff on it.

Now, you know, we're talking about somewhere in the region of kind of 15-17 of our rigs have got more than two years-... outlook on them. 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 a kind of natural ebb and flow that Jeremy was talking about.

Kurt Hallead (Head of Global Energy)

That's great. Really appreciate it. Thank you.

Jeremy Thigpen (CEO)

Thanks, Kurt.

Operator (participant)

Our next question comes from David Smith with Pickering Energy Partners.

David Smith (VP)

Hey, good morning, and thank you for taking my question.

Jeremy Thigpen (CEO)

Good morning, David.

David Smith (VP)

So this is actually a question about cost, so please bear with me a second. But the average reported ultra-deepwater rate in Q3, four hundred and six point five thousand 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. That delta for the ultra-deepwater fleet has 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.

Mark Mey (EVP & CFO)

Yeah, David, let's take this math offline. I don't want to go through this when we're trying to talk about the macro.

David Smith (VP)

[crosstalk]Sorry.But we can-

You bet.

Mark Mey (EVP & CFO)

We can reconcile this for you offline.

David Smith (VP)

Absolutely. Then quick follow-up, if I may, the, the support cost of $67 million, was that a little step up versus the prior run rate? Was there anything anomalous, or is, is this a good run rate to use?

Mark Mey (EVP & CFO)

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 two or three years ago, very low in reimbursables. You look at the ones now, much, much higher. So yes, there is a higher runway to reimbursables, but like I said, we can give this to you offline and give you the math.

David Smith (VP)

Perfect. I'll, I'll circle back with the big picture question. Thank you.

Operator (participant)

Our last question comes from Scott Gruber with Citigroup.

Scott Gruber (Director of Oilfield Services and Equipment Research)

Yes, good morning. I had a question on-

Mark Mey (EVP & CFO)

Hi, Scott.

Scott Gruber (Director of Oilfield Services and Equipment Research)

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, you know, around how you guys manage maintenance spend that's keeping a lid on spending?

Mark Mey (EVP & 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's 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 as part of the care agreement is a cap on the inflation each year, and that cap ranges around 2%. So even if inflation is 4% or 5%, which, you know, 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 gonna 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 gonna have a catch up in 2023, 2024, 2025 and beyond. So, I think this is what you can expect from us going forward. You know, our CapEx has been very high because of new builds. But on a sustaining basis, we've been saying this for a long time, that, you know, don't expect to see very big numbers from us going forward.

Scott Gruber (Director of Oilfield Services and Equipment Research)

Right. And just a quick follow-up on, on the SPS side, you know, you will have a few more, it looks like, in 2025 and 2026, and I know you're not spending as much, you know, on the 10-year SPS this cycle as you did last cycle. But just kind of ballpark, you know, what would a 10-year SPS, you know, run you now?

Mark Mey (EVP & CFO)

It all depends on the asset, because, you know, with these care 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's equipment stays certified 24/7, 365. So the cost benefit, because we pay a day rate to our vendors, is that we can do, for the drill ships, 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, you know, 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, no out of service time. For the semis, however, we do have to take those rigs into the dry dock because we have to inspect the hull, the pontoons and the undercarriages of the rigs, and that can be 15-20 days.

Scott Gruber (Director of Oilfield Services and Equipment Research)

Got it. I appreciate the call. Thank you.

Mark Mey (EVP & CFO)

Thanks.

Operator (participant)

Our next question comes from Fredrik Stene with Clarkson Securities.

Fredrik Stene (Head of Research)

... Hey, Jeremy and team, hope you're all well. I wanted to circle a bit back to the market here, and you know, weighing short to medium term versus long term outlook. And you know, I think we're pretty much aligned in what we think about this market, that it's going to be a highly sustained and long upcycle. But based on how estimates for you know, drillers in general has been revised a bit downwards now for 2024, and partially 2025 over the last few months. It's you know, there seems to be some concerns that at least 2024 will be, call it, a bit volatile. And then you partially touched upon it with you know, white space and all that.

But I just wanted to, in a way, 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. If the white space that we might see on a few rigs in 2024 for you and peers, more like a result of call it what can we say? Arbitrary contract ends and startups, and not really a result of you know anything changing in how you look at this market in the long run. It's just you know people need time to decide and the consequence of that is it's a bit of white space, although it shouldn't be taken as a kind of a weaker market. Sorry for all those-

Roddie Mackenzie (EVP & Chief Commercial Officer)

Yeah

Fredrik Stene (Head of Research)

but hopefully I-

Roddie Mackenzie (EVP & Chief Commercial Officer)

No, no, that makes sense. That makes sense.

Fredrik Stene (Head of Research)

Yeah.

Roddie Mackenzie (EVP & Chief Commercial Officer)

Yeah. No, that, that makes sense. Yeah.

Fredrik Stene (Head of Research)

Okay.

Roddie Mackenzie (EVP & Chief Commercial Officer)

So really, that's exactly our view, is that, you know, like for example, we talked about a couple of rigs. So if we take the Inspiration. So Inspiration actually was a winner in one of the tenders that just did not get consummated. So she would've, you know, assuming that had gone ahead, there was some technical issues on wells that they decided not to do that. But assuming that had gone ahead, 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, you know, a confluence of events.

So, you know, for example, in the U.S., we really had no hurricanes this year upsetting any of the activity, which is great, right? But normally, that does have an impact on the length of term for some of these rigs. And likewise, you know, 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 they decided not to drill the extra wells. So that's kinda like a victim of your own success. But other instances where, you know, 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, quote-unquote, you know, got lucky, in terms of programs running longer. This year, things have not run longer. They've really gone either, you know, to 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 costs for the operators are coming down again. And we think that's positive for building, you know, larger demand as we go forward. It's just slightly unfortunate because some of those rigs were on these short-term contracts that we talked about.

But the really good upside is, with substantial portion of our fleet migrating to the long-term contracts, those things are not gonna be an issue anymore as we step into, you know, later in 2024 and 2025.

Fredrik Stene (Head of Research)

That's very helpful. And just to follow up on that, now that we're seeing some of this white space in 2024 for these various reasons, do you think, you know, all else equal, that this has delayed the pace at which capacity will be reactivated, either from cold stack or from yard, both kinda as for the market as a whole, but also on your own, and since you're controlling most of that cold stack capacity?

Roddie Mackenzie (EVP & Chief Commercial Officer)

Yeah. Yeah. Yeah, so like, a good example might be, you know, what's happened in Brazil. So obviously I can't really talk about, you know, fixes that have yet to be made, but there's rumors that, you know, 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 two assets from the shipyard. So that would be a consequence of... Well, it makes sense to place your active fleet ahead of, you know, reactivating or standing up new build 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, "Now, 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, yeah, 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 genuinely justifies spending the money to do that. So again, I think, yeah, the only real consequence of any...

You know, the 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.

Fredrik Stene (Head of Research)

All right. Thank you. Thank you very much for the comprehensive commentary. Super helpful, as always. So, I guess I wish you all a good day, and we'll talk again soon.

Roddie Mackenzie (EVP & Chief Commercial Officer)

Thanks. You too.

Operator (participant)

We have our final question from David Smith with Pickering Energy Partners.

David Smith (VP)

Hey, thanks for letting me back in, and a little bit bigger picture question. Just focusing on some of these five-year plus programs that operators are looking to fill. I expect they're looking for a discount to leading edge rates, you know, and maybe they could get those discounts with rates that give really solid returns for a reactivation, right? Or one of the new builds that were, you know, bought from a yard earlier this year. But when I look at those seventh-gen rigs that are still stacked or previously stranded, you know, I only count 6 that aren't owned by you. I'm not including the Libra that can do new builds. I think those are gonna cost a lot more.

My, my question to you is just, given your view of demand, when do you think we see these last 6 incremental seventh-gen drillships absorbed, right? Those ones not owned by you. And then what happens to the cost of incremental supply when those are on?

Roddie Mackenzie (EVP & Chief Commercial Officer)

Right. Okay, 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 2024, 2025 timeframe. And then the following year, in 2026, they were projecting 104% or 105% utilization. So what that tells you is that that's the timeframe 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 5-6 additional cold stacked assets in that timeframe.

So again, you know, my crystal ball is a little biased, but I would say if you follow some of the commentary elsewhere, you'll probably point to the 2025 timeframe as being, you know, 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, you know, 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 multi-year tenders, that's clearly the case is that, you know, operators are looking to secure capacity at a day rate that they feel is acceptable and works for the projects. And, you know, 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 certainty 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 gonna see the same thing on some of these long-term five-year deals. It's not necessarily the top-spec rigs that are gonna do it. They're gonna 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.

David Smith (VP)

Great point and great color. Thank you so much.

Operator (participant)

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 of 2023 results. Have a good day.

Operator (participant)

This does conclude today's program. Thank you for your participation. You may now disconnect.