Transocean Ltd. (NYSE:RIG) Q1 2023 Earnings Call Transcript

Transocean Ltd. (NYSE:RIG) Q1 2023 Earnings Call Transcript May 2, 2023

Transocean Ltd. misses on earnings expectations. Reported EPS is $-0.38 EPS, expectations were $-0.22.

Operator: Good day, everyone and welcome to Q1 2023 Transocean’s Earnings Call. At this time, all participants are in a listen-only mode. Later, you’ll have an opportunity to ask questions during the question-and-answer session. Please note, this call is being recorded. It is now my pleasure to turn today’s program over to Alison Johnson, Director of Investor Relations. Please go ahead.

Alison Johnson: Thank you, Gretchen. Good morning and welcome to Transocean’s first 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 our 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 question. Thank you very much. I’ll now turn the call over to Jeremy.

Jeremy Thigpen: Thank you, Alison, and welcome to our employees, customers, investors, and analysts participating on today’s call. As reported in yesterday’s earnings release for the first quarter, Transocean delivered adjusted EBITDA of $217 million on $667 million in adjusted contract drilling revenues, resulting in an adjusted EBITDA margin of approximately 33%. Our overall performance was supported by superb revenue efficiency of nearly 98% and is representative of our commitment to operational excellence. During the quarter, we booked nearly $900 million of contract backlog, disrupting the first quarter low observed in years past. In fact, this is more than double the backlog added in the first quarter of 2022 and more than seven times what we added in the first quarter of 2021.

We believe this is another clear indication of the sustainability of this constructive market environment, particularly in light of the record backlog we booked last year. Turning to the individual fixtures, in Lebanon, the Transocean Barents was awarded a one well contract with TotalEnergies at a rate of $365,000 per day. The approximately 65 day contract is expected to commence in direct continuation of the rigs current program and provide for up to three option wells at rates between $375,000 per day and $390,000 per day. As discussed on our fourth quarter 2022 earnings call, in January, the KG2 was awarded a 910 day contract in Brazil at approximately $439,000 per day, including integrated services. The contract is expected to start in the third quarter of this year.

In Australia, the Transocean Endurance was awarded a multi-well contract for plug and abandonment work with an independent operator at a rate of $380,000 per day. The contract also provides for up to five option periods, the first of which has already been exercised at the same day rate. The remaining four options are at a rate of $390,000 per day. The contract is expected to commence in January of 2024 and including the exercise option, the term work now extends through February, 2025. If all options are exercised, the rig may remain in Australia through at least the fourth quarter of 2025. On the Norwegian Continental Shelf, the Transocean Enabler was awarded a 19 well contract with Equinor for work on the Johan Castberg field in the Barents Sea at $377,000 per day as adjusted for currency exchange rates.

The contract, which is expected to commence in April of 2024, also provides for up to eight option wells at $420,000 per day. Also in Norway, the Transocean Encourage was awarded a nine well contract with Equinor at a rate of $350,000 per day as adjusted for currency exchange rates. The contract is expected to start in direct continuation of the rigs current program. And finally, in Norway, Wintershall Dea exercised four one-well options on the Transocean Norge at rates of $338,000 per day, $358,000 per day, $358,000 per day and $408,000 per day respectively, again as adjusted for currency exchange rates. Following our latest Fleet Status Report, Wintershall Dea exercised a fifth option well at $358,000 per day, keeping the rig working through the third quarter 2024.

Also, subsequent to our latest Fleet Status Report, the Transocean Endurance was awarded a two-well contract in Norway at a rate of $385,000 per day. The contract is expected to commence in July, 2023. These harsh environment fixtures and the KG2 award complement the prolific ultra-deep water fixtures we announced in the second half of 2022 and keep us on track to deliver yet another strong year of backlog additions. Moreover, these harsh environment fixtures highlight the predicted tightness in the supply of higher specification, harsh environments, semi-submersibles that we’ve anticipated for some time now. Of note, the Endurance is the sixth semi-submersible to depart the Norwegian Continental Shelf in the past 18 months, joining most recently, the Transocean Barents which is now operating in the UK.

With the departure of the Endurance, there are now just 13 active semi-submersibles remaining in Norway that have the certifications required to participate in petroleum operations, and we currently expect at least two more rigs to leave the region within the next 18 months. As we’ve discussed on previous calls, demand for rigs capable of drilling in harsh environments is no longer solely dependent upon geographic regions that have historically utilized harsh environment rigs. Rather, demand is increasingly coming from other areas, including Australia, the Mediterranean, and Namibia. As we see multiple upcoming long-term developments on the horizon in Norway, the departure of these assets from Norwegian is meaningful. If demand continues to materialize as we expect, by the end of 2024, we anticipate that future projects in Norway will require several of these assets to return and to lure them back significant mobilization fees and higher day rates may be required.

Perhaps the most interesting new market for our harsh – high specification harsh environment semis is Australia with numerous programs planned for overlapping operational windows. There appears to be strong competition among operators to secure the best and most capable rigs. As a result, we are observing an increased willingness from our customer base to pay higher mobilization and other contract preparation costs, and if current tenders proceed as expected, we could see one or two new contract awards in Australia by the end of the second quarter. Turning to the benign environment rig market, over the last year, we’ve observed a marked increase in day rates for ultra-deep water drill ships, which are now predominantly between $400,000 a day to $450,000 per day across the global fleet.

We believe this demonstrates a more widespread understanding by all market participants of current market rates. Sixth and seventh gen drill ship utilization remains at nearly 100%. We expect these utilization levels will be sustained as drill ship demand is anticipated to rise throughout 2023 and we believe that as a result, day rates will continue to trend upward, especially for the higher specification ultra-deep water. In fact, by the end of the year, we expect leading-edge rates to exceed $500,000 per day. Additionally, we’ve recently observed a change in the behavior of several of our customers due to their recognition of the increasing scarcity of high specification assets. The shift is occurring mostly behind the scenes through direct inquiry and negotiations as they seek to secure rigs for longer terms, in some cases in excess of three years.

We anticipate this trend will continue for certain customers as access to available desirable rigs becomes a more difficult. Looking closer at each region, based on current activity in the open and planned Petrobras tenders, we believe Brazil will continue to be a large consumer of available rig supply. We anticipate Petrobras will secure six or seven floaters under the pool two Brazil’s tenders, including up to three from outside the region. If these awards materialize as expected, access to active and warm stacked rigs for use in other regions will be further constrained, likely resulting in increasingly favorable contract terms for qualified floaters. This has already occurred in India following the award of the KG2 under the Petrobras pool tender in early January.

We believe that the KG2’s departure from the Far East further highlights the limited available local supply of assets to meet the requirements of upcoming drilling campaigns such as ONGC’s two 21-month opportunities in India. Consequently, we may see assets mobilized from other regions for this work. In West Africa and the Mediterranean floater demand is expected to trend upward over the next 18 months with multi-year programs expected in Angola, Egypt, and Cyprus. Additionally, incremental work is emerging in Namibia following recent discoveries by both shell and total energies in the Orange Basin. Activity in the U.S. Gulf of Mexico has kept regional supply and demand largely in balance over the last several quarters. We’re highly encouraged by the results of the lease sale concluded in late March in which the number of deepwater blocks receiving bids increased by 30% from the last lease sale held in 2021.

We anticipate the region will continue to have strong activity for the foreseeable future. Year-to-date, 34 rig years have been awarded for the global floater fleet as compared to 22 rig years this time last year. The quantity of programs awarded with a duration of one or more years has also increased with 11 awarded year-to-date up from five last year. The outlook remains strong for the foreseeable future as over 80 rig years award – are expected to be awarded in the next 18 months. In fact, industry analyst reports estimate the offshore sector will experience its highest growth in more than a decade with according to Rystad Energy more than $200 billion of new project investments during the next two years with offshore activity comprising nearly 70% of all sanctioned conventional hydrocarbons in 2023 and 2024.

As demand continues to improve, we will ensure that Transocean is differentiated from our competitors by providing the highest value for our customers and developing and deploying innovative technologies that further enhance our already safe, reliable, and efficient operations. Just last month, utilizing a combination of various automation technologies which we’ve previously deployed within our fleet. The Transocean encouraged drill an entire whole section for 21 consecutive hours in a fully automated mode. This achievement is an important milestone for automation technologies. We believe automation will further improve our operational performance, improving the quality and consistency of the wells we drill for our customers, further enhancing the safety of our personnel while also reducing emissions.

As we continue to deploy automation technologies, we plan to aggregate and analyze the data to gain new insights into the performance of our equipment and processes to improve our overall operations. Congratulations to our team in Norway for this significant accomplishment. As we progress further into the sub cycle, we will continue to deploy our portfolio of high specification, ultra deepwater and harsh environment rigs to maximize value for our shareholders. Throughout the downturn, we practice a thoughtful approach to contracting our assets and place the right rig on the right opportunity at the right time. We utilize different asset classes and we’re patient so is not to lock up our best assets on long-term low day rate contracts. We continue to believe this is the correct approach and moving forward, we will continue to remain disciplined when contracting our fleet.

With 12 total cold stacked assets, we have the most operational leverage within our peer group and significant upside potential in a rising market, particularly given the quality of our assets. There are only 13 remaining sixth and seventh generation cold stacked drillships in the industry and eight are in our fleet. Three of these the Athena, Apollo, and Mylos are seventh generation ultra deepwater drillships that are well preserved in a relatively mild climate offshore grease. We expect economics of reactivations will be cost advantageous as compared to acquiring a stranded new build and preparing it for an initial contract. Recent stranded new build purchases suggest between $200 million and $250 million to acquire the asset plus the cost to reactivate versus our current estimate of $75 million to $125 million to reactivate one of our existing cold stacked rigs.

In summary, our outlook remains unambiguously optimistic, reinforced by increased market tightness in various regions around the world and the continued to upward trajectory of day rates. Our industry-leading backlog increased for the fourth consecutive quarter to currently about $8.6 billion. Additionally, the average day rate on our working benign environment rig fleet is beginning to reflect the high quality backlog we booked over the last 18 months, and it’s projected across the $400,000 per day mark later this year. As more of our rigs transition to higher day rate contracts, we’ll begin to utilize cash generated from our fleet to fulfill our commitment to our broader deleveraging efforts. Our focus remains on delivering safe, reliable, and efficient operations.

With our strong year-to-date fleet up time and revenue efficiency of nearly 98%, we continue to take positive steps toward ultimately strengthening our balance sheet and generating value for our shareholders. I’ll now turn the call over Mark.

Mark Mey: Thank you, Jeremy, and good day to all. During today’s call, I’ll briefly recap our first quarter results then provide guidance for the second quarter as well as an update on our expectations for the full year 2023 and our liquidity forecast to the end of 2023. As reported in our press release, which includes additional detail on our results, for the first quarter of 2023, we reported a net loss attributable to controlling interest of $465 million, $0.64 per diluted share. After certain adjustments as stated in yesterday’s press release, we reported adjust net loss of $275 million. During the quarter, we generated adjusted EBITDA of $217 million. Looking close at our results during the first quarter, we delivered adjusted contract drilling revenues of $667 million at an average day rate of $364,000.

This is above our previous guidance, mainly due to strong bonus conversion on the Conqueror, Endurance and Spitsbergen higher than expected revenue recharge at earlier than forecast commencement of operations for the DD3. Operating and maintenance expense for the first quarter was $409 million. This is below our guidance reflecting the delay of in-service maintenance on our working fleet and other service maintenance on rigs that we are preparing for contracts commencing later in 2023, partially offset by increased cost related to the early commencement operations for the DD3. Turning to the cash flow and balance sheet. Cash flow from operations was a negative $47 million resulting from lower collections from customers reflective of reduced revenue due to certain rigs completing their contracts during the previous quarter, disbursements incurred preparing several rigs for our next contracts and the timing of tax and interest payments.

Our free cash flow of negative $128 million in the first quarter reflects the contract preparations above and $81 million of capital expenditures, which were largely related to our eighth generation drillstrips the Deepwater Atlas and Deepwater Titan. We ended the first quarter with total liquidity of approximately $1.7 billion including unrestricted cash and cash equivalents of approximately $747 million approximately $175 million of restricted cash for debt service and $774 million from an undrawn revolving credit facility. I will now provide an update on expectations for our second quarter and for full year financial performance. As always, our guidance would reflect only contract related rig reactivations and/or upgrades. For the second quarter of 2023, we expect adjusted contract drilling revenue of approximately $735 million, based upon an average fleet wide revenue efficiency of 96.5%.

This quarter-over-quarter increase is primarily attributable to a full quarter of utilization of the Transocean Barents and DD3, we started contracts in the prior quarter and the contract commencement of the Deepwater Titan and Transocean Norga during the second quarter, partially offset by in between contract auto time were Transocean Endurance in Norway. For the full year 2023, I’m reiterating prior guidance of adjusted contract drilling and revenue of between $2.9 billion and $3 billion. We expect second quarter O&M expense to be approximately $490 million. This quarter-over-quarter increase is primarily due to higher utilization, increased other service maintenance incurred on the KG2 and Deepwater Orion in preparation for the contracts with Petrobras and the timing of in-service maintenance activities.

I expected full year 2023 operating a maintenance expense remains unchanged in my fourth quarter call at approximately $1.9 billion. We continue to see some upward pressure on salaries and wages and vendor pricing. Observed inflation appears to have around 6%, which is reflected in our guidance. As a reminder, the influence of inflation on our maintenance costs is largely tempered by our long-term care agreements with our largest suppliers. We also have protection on the revenue side as our legacy long-term contracts with our customers contained cost adjustment mechanisms. For ongoing and future contract negotiations, we’ll continue to insist on provisions to protect our margins against cost increases in day rate and terms as appropriate.

We expect G&A expense for second quarter to be approximately $49 million and around $200 million for the full year. Net interest for the second quarter is forecasted to be approximately $118 million, including capitalized interest of approximately $12 million and excluding any non-cash fair value adjustment of the bifurcated exchange feature embedded in our exchangeable bonds issued in September of 2023. For the full year, we estimate net interest expense of approximately $479 million, including capitalized interest of approximately $31 million and excluded the non-cash loss of $133 million mentioned above. Capital expenditures including capitalized interest for the second quarter of forecast will be approximately $100 million, which includes approximately $70 million for new builds CapEx and approximately $30 million of sustaining and contract preparation related CapEx. Cash taxes are expected to be $15 million for the second quarter and $35 million for the year.

As expected, our expected liquidity in December 2023 is projected to be between $1.2 billion and $1.3 billion, reflecting our revenue and cost guidance and including the $600 million capacity of our revolving credit facility and restricted cash of $215 million, which is primarily reserved for debt service. This liquidity forecast includes 2023 CapEx expectations of $285 million, of which $167 million related to our new builds and $118 million for sustaining and contract preparation CapEx. We continue to focus on deleveraging our balance sheet and reducing interest expense and simplifying our capital structure and maintaining financial flexibility. As I discussed in the fourth quarter call – earnings call, we’ve addressed substantially all material – maturities until 2025.

Consistent with our deleveraging objectives, one of our large holders of our exchangeable bonds, we simply agreed to convert its exchangeable bond to equity, reducing our debt by $213 million. We may look to address a portion of the remaining $618 million of outstanding exchangeable bonds should other economic improve and opportunities present themselves. Given our current contracting activity and strong day rate environments, we expect to utilize available free cash flow to continue reducing debt and interest expense. Concurrently, we will look to continue to evaluate opportunistic financing transactions to address medium-term maturities and optimize the balance sheet and reduce the cost of debt. This concludes my prepared comments and I will turn it over to Alison.

Alison Johnson: Thanks, Mark. Gretchen, we’re now ready to take questions. As a reminder to the participants, please limit yourself for one initial question and one follow-up question.

Q&A Session

Operator: We’ll take our first question from James West from Evercore ISI.

James West: Hey, good morning guys.

Jeremy Thigpen: Good morning, James.

James West: So Jeremy, talking about day rates for non-harsh environment in the $500,000 day range by year end, which I think is probably consistent with where you’re negotiating contracts now. Would any of these rigs that would achieve that type of day rate actually start this year or are we talking about rigs that are going to be coming out of cold stack that given that we’re in May now would probably take until next year to really kick off campaigns?

Jeremy Thigpen: Good. I’ll hand it over to Roddie.

Roddie Mackenzie: Hey, no problems. Yes. So I think that would be the case. Yes. You would see that coming next year and there’s been a lot of discussion about this magical 500 mark. But I wanted to give a couple of statistics on that just real quickly. We don’t know what our competitors bid, except when they bid into public tenders. So we used the Petrobas tenders in Brazil as an example. In the pool number one tender that happened last year, there was only two rigs were bid above the $500,000 a day and the pool two tender that just completed this week it was nine, so that’s like a mark change in that. And of course, you see lots of folks across the board saying that the expectation is that it’ll be this year for the 500s, and I’ve seen a couple of projections that say will be mid-500s by 2025.

James West: Right. Okay. That’s kind of our expectation as well. The – I guess, the follow-up for me is on consolidation in the space we obviously have had a good amount during the restructuring phase that we saw. There are still some companies that were aware of that are kind of up for grabs here and there’s some assets up for grabs. How are you guys thinking about, I guess, one, the need for consolidation and two Transocean’s role in that consolidation?

Jeremy Thigpen: Yes. Thanks, James. Good question. We have seen a lot of consolidation in space. We’ve dramatically improved industry structure for offshore drillers, far fewer players, far fewer assets due to retirements. So it’s much – far more disciplined behavior as a result. So we’re going in the right direction. I think there’s still room for more consolidation especially now that most of our competitors have gone through chapter 11 and have merged with clean balance sheets. I think – and all of us have digested our own acquisitions over the course of the last couple of years. So I would expect to see some more consolidation through this year. We certainly look at every opportunity out there and we get pitched every opportunity that’s out there, Mark smiling at me.

And so we’ll continue to look, but again, we’re going to kind of follow the same blueprint we followed so far. It’s got to be alter deep water and harsh environment high specification assets, so fleet matters and we can’t do anything to compromise the balance sheet. And so we look through those – that lens really at every strategic opportunity.

James West: Okay. Got it. Thanks guys.

Jeremy Thigpen: Thanks, James.

Operator: Our next question comes from Thomas Johnson from Morgan Stanley.

Thomas Johnson: Hi, congratulations on the strong quarter. First one would be helpful to kind of go back to the harsh environment outlook. You guys mentioned a handful of rigs has left the European space, which is clearly supportive of utilization there. You mentioned $500,000 per day leading edge by year-end on the benign side. But maybe if you could kind of add some color around how people should think about the potential range for leading edge rates in the harsh environment outlook over the next 12 to 18 months. Thanks.

Jeremy Thigpen: Yes. I think I’ll take that one. So as we think about another kind of eight to 10 rigs potentially leaving Norway, that pretty much leaves you a fleet of maybe 12 or 13 rigs. What we see in the expected demand in the 2024 into 2025 timeframe is about 15 to 18 rigs. So you’re suggesting that there’s probably a deficit of four to six rigs in that timeframe. That’s – that in my view is going to have a step change in day rates, right? I mean, we’ve seen that we’re consistently now in the upper 300s. I would expect that the next fixtures are going to be solidly in the fours. And who knows where that may lead to, but certainly we’re at this kind of 13 AOC compliant floaters in Norway just now that is historically the lowest number ever.

And I think just in the context of an improving global market that has consistently delivered quarter-over-quarter, you’re now seeing this kind of mass exodus to rigs moving to places that they can not only be active and have work, but also get pretty high EBITDA margins comparatively speaking to staying in Norway. So I think that’s going to be the key hurdle. It it’ll be the rigs that have to come back to Norway that will command a super premium.

Roddie Mackenzie: And Thomas, the other thing I would mention, in addition to these having day rates firmly in the 400s if not higher, customers are paying mobilization fees as well up front. So you layer that in as well and it looks pretty lucrative for that market.

Thomas Johnson: Great, thanks. And then just last comment still related to the supply. Thanks for the range of 75 to 125 on reactivation. But can you maybe update us on the timeline to reactivate a cold stacked drill ship in the market? Obviously aware that there’s going to be a range depending on the assets, but just kind of broad strokes, reactivation, timeline ranges. And then maybe an update on how you see supply chain whether they’re major hurdles to reactivating rigs potentially based on equipment availability? Thanks.

Jeremy Thigpen: Yes. Keelan, can you take that one?

Keelan Adamson: Yes, Thomas. I think our guidance on that still hasn’t changed since the last time. We’re still looking at 12, anywhere between 12 and 18 months to get a cold stack reactivation effective door to door into operation, largely probably around the 15 month side. The supply chain side is improving as capacity is getting better across the supply chain. But we still – we’re still facing some long lead issues, particularly on heavy steel forgings and obviously on electronic components that there’s a reliability probably issue in terms of delivery in the supply chain from Europe in that regard. But I think we’re still seeing 12 to 18 month range on our cold stacked reactivations at this time.

Thomas Johnson: Great. Thank you very much. I’ll turn it back.

Operator: And our next question comes from Eddie Kim from Barclays.

Eddie Kim: Hi. Good morning. So you announced a handful of nice contracts for harsh environment semis this past quarter, but notably absent were contracts for the Invictus and the Inspiration, especially given their near-term expiration of their current contracts. Both of those rigs are also in the U.S. Gulf of Mexico, which is effectively a sold down market. So could you just talk about the future prospects for those two rigs specifically and when we should expect them to get back to work?

Roddie Mackenzie: Yes, sure. Yes, so obviously I can’t tip my hand to this precise opportunity we’re exploring. But yes, we’re in active dialogue on both the rigs for different things. And we expect that fairly shortly we’ll be able to add some more backlog to those. And kind of as a reminder on that contracting philosophy, we are purposefully keeping a couple of rigs available in the near-term to take advantage of this improving market for us. So you did see, and thank you for noting the prolific contracting that we did on many of the assets over the last couple of quarters. So we maintain that balance of – yes, it’s nice to have the majority of the fleet on long-term contracts, but we certainly also want to be able to capture the upside in this improving market.

Eddie Kim: Got it, got it. Understood. It’s a bit of a – kind of strategic negotiation going on there. Understood. And my follow-up is just on kind of the pace of reactivation we’ve been seeing. There’s been one major contractor has been reactivating a number of cold stack floaters as I know you’re well aware. Does the pace of reactivations concern you at all in terms of the day rate progression? Your expectation to see a contract announced with a five handle by end of year would suggest you’re not very concerned at all. But any thoughts here would be appreciated?

Jeremy Thigpen: Go ahead.

Mark Mey: Yes. So if you look at the results from the Petrobras contracts was announced last Friday, the two rigs, that one the first one were both in the mid 4s and they are stranded new builds, so very similar to a reactivation of a cold stack rig. These are rigs that are coming out, and as Jeremy mentioned in his prepared comments, we’re paying about $200 million for these rigs and you’re spending another $150-ish million to bring those rigs to market. So to see that those investors are bidding in the mid-4s, I don’t see them dragging rates down at all. I think it was a very good high water mark for Brazil. So I don’t think that’s a challenge for us at this stage.

Eddie Kim: Got it. Understood. Thank you. I’ll turn it back.

Roddie Mackenzie: Yes. Actually I may add on top of that. The interesting thing again pool 1 versus pool 2, which is kind of seven months apart is we saw a 17% increase in the average bid rate. So you kind of went from three 50k a day average to 408k. That’s pretty substantial increase in just a few months, 58k a day on average.

Operator: And our next question comes from David Smith from Pickering Energy Partners.

David Smith: Good morning. Thanks for taking my questions.

Jeremy Thigpen: Good morning, David.

David Smith: So two interesting agreements you all announced in the past three months, the first dedicating the Olympia for subsidy mineral exploration, and then the second converting up to two floating vessels for floating wind turbine installation. Am I – just wanted to make sure I’m right to understand those two vessels would be coming from your stack fleet.

Roddie Mackenzie: That’s correct, yes.

David Smith: So I was just hoping to get your thoughts on removing up to three stacked rigs for alternative uses and kind of how you think about the trade-off for increasing exposure to the energy transition versus the option value of eventually having the last incremental capacity before new builds would be needed and maybe if you’re considering dedicating any more stacked rigs for alternative uses?

Roddie Mackenzie: Yes. I’ll take that one. So look, I mean, if we do consider using some of our stacked fleet for these opportunities the logic’s pretty simple. We basically have a good crop of available cold stacked units for riding the upside of this increased activity as we expect floaters to go from kind of like the 140 level committed rigs to up to 150. We’ve got plenty of room to grow on the drilling side of the business. But the assets that we might consider for something like this would happen to be the lowest specification of our stacked assets. So it’s really a very interesting way to get into the energy expansion, to be not just one dimensional in our outlook, but also to take assets that otherwise might be stacked for many, many more years and making good use of them in the near-term. So I think it’s an extremely interesting opportunity and a smart use of our fleet.

Mark Mey: And I’m going to add to that. We’ve been talking about the pace of reactivations for the industry and for transaction specifically. We believe given the current constraints, especially on the supply chain side, it’s about two a year. So if we have 11, and you take those two out, now it’s nine, that’s 4.5 years of reactivations. Do we believe the cycle’s going to last 4.5 years, five years, six years? Not so sure. We do believe it’s going to last three years. So we certainly can get through the majority of our stack fleet by reactivating them. And if day rate support reactivating the rest of it, we’ll clearly do that. But we’re targeting these rigs into markets that we believe will generate returns for our shareholders over time, as well as Roddie said helping us as a company to move into the energy expansion a little more forcefully.

David Smith: That’s great color. Thank you. And that’s all I had.

Operator: Our next question comes from Kurt Hallead from Benchmark.

Kurt Hallead: Hey, good morning.

Jeremy Thigpen: Good morning, Kurt.

Kurt Hallead: So, hey Jeremy. I think as you referenced here earlier, there’s something along the lines of 13 cold stack rigs. I think on prior call, you indicated that Brazil might see incremental rig demand of order magnitude 20 rigs over the next, I don’t know, two to three year period. I think is what the timeframe was. And I just wonder if you give us an update on overall demand dynamics as you see it maybe updated relative to how you saw it versus the prior call? And I guess the context is it seems to me that Brazil could absorb the vast majority of the available idle capacity in the market leaving West Africa and other areas scrambling to compete for what’s left . So just want to get your perspective on that?

Jeremy Thigpen: Sure, sure. So yes, with regards to Brazil, yes. If you think about just a larger context before you go to the details of that. The drill ship market is effectively a 100% utilized at the moment for assets that are available. Yes, certainly Brazil has more to add, there’s no doubt. So I think you’re going to see as Mark pointed out, there is two stranded assets are going to come to satisfy the cold to tender. We think there’s still plenty more cold stacked potential for satisfying Buzios and other tenders that may also come out. So yes, Brazil really is putting a draw on pretty much everything that’s available. But as we go around the world and we think about the different markets, I mean, every market is up.

If you view it on a 12-month basis, every market is up. So that simply means that we’re going to continue to book the rigs that are coming available and have to reactivate other ones. So again, as I said, the kind of numbers are supposed to be heading to 150 active floaters as we get into 2024 that would suggest that we’ve got 10 to add. So that’s a tall order, but certainly in good shape for that. And I think as the guys had articulated many times, we’ve got 12 cold stacked assets at the moment. We could dedicate a couple of those to alternate purposes, but we’d also be optimistic about reactivating a couple of those over the next year or so into new opportunities.

Kurt Hallead: That’s great. Appreciate that color. So follow-up here would be, again, on the harsh environment side where you’re moving these assets from Norway to Australia. Just wonder if you can just give us an update on what’s the cash margin differential, if any between what you could have earned in Norway versus what you’re getting in Australia?

Jeremy Thigpen: Yes, I’m not sure I comment exactly on the margins. But there is a better margin to be got in Australia. There’s a substantially better margin to be got in West Africa. So you’ve seen the access of the rigs. There’s currently standing at six of them. So if you think about just where we are normally in terms of like the rules and regulations for not only the equipment, but crews and a number of people on the rigs, it’s going to be a pretty substantial hurdle to pull those rigs back, particularly if you’re already making whatever that where you are. And the demand for the rigs in the new countries appear set to continue for several years.

Kurt Hallead: Okay. Great. Appreciate the color. Thank you.

Jeremy Thigpen: Thanks Kurt.

Operator: And our last question comes from Fredrik Stene from Clarksons Securities.

Fredrik Stene: Hey guys. Thank you for taking my question. Hopefully, you can hear me, okay. So I have…

Jeremy Thigpen: We can.

Fredrik Stene: …two questions for you. I would like to kind of to add a bit to the cold stacked asset discussion here. As you mentioned in your prepared remarks, you have the majority really of the cold stacked assets here. And one thing is talking about where these assets can go and who can absorb them. But I think another part or dimension of that discussion is the strategy in a way of how to employ them because it seems to me your peers taking out their stack capacity at lower rates or being more aggressive in taking out their – that capacity. But at some point, I think, that could leave you as the only price sector really of incremental capacity into the flow to market. But that also gives you a bit more risk on your side. So do you have any color thinking about how you’re approaching that right now, or if the way you’re approaching it has changed as we’ve seen rate levels move higher?

Mark Mey: Yes, I don’t think our approach has changed. I think we’ve been pretty clear that the customer has to pay for the reactivation. And so, we’re going to continue to follow that strategy I think going forward. I know going forward, so we’re happy to – we have to continue push rates on our existing fleet as they become available. And then when the customers willing to pay for a reactivation, we’ll certainly do it.

Jeremy Thigpen: Yes, and I think as we think about what it costs us for those rigs to remain stacked, it’s really de minimus. So choosing the right time and choosing the right contract is really what the strategy is about and showing some patients not we certainly do not value utilization over generation. So I think most of our competitors see it that way. Maybe one or two don’t. But we’ll certainly continue to push that mantra we will not reactivate on spec.

Fredrik Stene: Perfect. And the last one. Turning to the harsh environment market, again, I think you’ve – you said that you’d like to or you would prefer to keep your assets in Norway or at least the Norway compliant assets. But obviously you and some of your competitors have not started to take those assets out. Have there been any change in that preference for your side that you’re seeing that the economics are just too good to kind of give up the optionality of keeping the assets in Norway? Or do you think that you have a balanced approach to that, some optionality in Norway and then some hard cash in other parts of the world right now?

Jeremy Thigpen: Yes, I was just going to say, no, I mean, it is pretty simple. I think we’ve showed an exceptional amount of patience over the last few years of keeping rigs in Norway. We’ve had rigs idle in Norway for some time. We’ve talked to kind of all the major customers about this and been – I would say very competitive in our attempt to keep the rigs busy in Norway, especially during 2019, 2020 and so on. But now we’re really at the point that the demand elsewhere is so substantial, is always our preference to keep the rigs where they are. There’s no questions about that. But the economic challenge is now overwhelming when you compare how accreted the contracts are elsewhere.

Fredrik Stene: All right. Thank you so much. That’s all for me. Have a good day.

Jeremy Thigpen: Thanks, Fredrik.

Operator: It appears you have no further questions at this time. I will now turn the program back over to Alison Johnson for any additional or closing remarks.

Alison Johnson: Thank you, Gretchen. And thank you everyone for your participation on today’s call. We look forward to talking with you again when we report our second quarter 2023 results. Have a good day.

Operator: Thank you ladies and gentlemen, this concludes today’s conference. You may now disconnect.