Transocean Ltd. (NYSE:RIG) Q2 2023 Earnings Call Transcript

Transocean Ltd. (NYSE:RIG) Q2 2023 Earnings Call Transcript August 1, 2023

Operator: Good day, everyone, and welcome to today’s Q2 2023 Transocean’s Earnings Call. [Operator Instructions] Please note this call maybe recorded. It is now my pleasure to turn today’s program over to Alison Johnson, Director of Investor Relations. Please go ahead.

Alison Johnson: Thank you, Carlos. Good morning and welcome to Transocean’s second 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; 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. 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 you saw in our latest lease status report, over the past several months, we added $1.2 billion of backlog for a total backlog of $9.2 billion as of July 19. This is the fifth consecutive quarter during which we have added more backlog than we consumed, resulting in an increase in backlog of approximately $3 billion from April 2022. Importantly, our ultra-deepwater fleet average day rate increased significantly over the same time period. For our fleet status reports, in the second quarter of 2023, our average day rate was approximately $363,000 per day versus $312,000 per day in the second quarter of 2022.

And based on existing backlog by the second quarter of 2024, we expect it to approximate $433,000 per day. Needless to say, it’s been an exciting start to the year. Not only have we increased average day rates for our ultra-deepwater fleet, we’ve also experienced a rapid tightening of the high-specification harsh environment semisubmersible market. As recently confirmed by Westwood Global Energy Group, this asset class is now effectively sold out with committed utilization at 100% for the first time since 2014. We first highlighted the emergence of new harsh environment regions on our third quarter 2020 earnings call. At that time, we predicted that the exodus of high-specification semisubmersibles from Norway would lead the Norwegian market undersupplied in 2024.

Even so, we underestimated the speed and magnitude of migration. Since then, three of our rigs, the Transocean Barents, the Transocean Equinox and the Transocean Endurance have moved or are preparing to move to new markets, including Australia and Lebanon. And we see more movement on the horizon as opportunities for these assets continue to develop, deepening our conviction that this market will remain tight for the foreseeable future. Compounding these supply constraints, expected demand for the Norwegian market maybe nearly 20 rigs by 2025. If this work materializes, Norway will be significantly short of supply, as only 12 high-specification harsh environment semisubmersibles are anticipated to remain in country through this period. As a natural consequence, dayrates for harsh environment semisubmersibles had meaningfully increased, since the beginning of the year and are now rapidly approaching $500,000 per day for firm work with certain priced options already above this threshold.

With that context, I’ll now transition to our recent fixtures, many of which contributed to this rapid improvement in the harsh environment market. As discussed on our first quarter call, the Transocean Barents was awarded a one-well contract with Total Energies and Lebanon at a rate of $365,000 per day. The customer subsequently exercised the first option well for work in the East Mediterranean Sea, at a rate of $370,000 per day, extending the firm duration to an estimated 167 days. There are two additional options remaining at rates between $350,000 per day and $390,000 per day depending upon the location in which the work takes place. In Australia, the Transocean Equinox was awarded a five-well contract by a major operator at a rate of $455,000 per day, excluding mobilization and demobilization.

The contract is expected to start in the first quarter of 2024 and provides for one-well — one option well at the end of the firm turn. The Equinox was also awarded a 16-well contract in Australia, at a rate of $485,000 per day, excluding mobilization and demobilization, which is expected to commence in direct continuation of the rig’s initial contract in Australia. The new contract provides for 21 one-well options at rates between $485,000 per day and $540,000 per day. If all options are exercised, the rig may remain in Australia into 2028. As a reminder, the Equinox is the second of our CAT D semisubmersibles that will begin operating in Australia in the first quarter of 2024. As we announced in late-March, the Transocean Endurance will start in January at a rate of $380,000 per day.

I’d like to pause and take this opportunity to highlight that in just three months, Transocean was able to increase rates for harsh environment semisubmersibles in Australia by over $100,000 per day, along with a material increase in duration. In Norway, Wintershall Dea exercised a one-well option on the Transocean Norge at a rate of $365,000 per day and three one-well options at a rate of $420,000 per day. This work eliminates the majority of previously anticipated idle time during the contract period. And as we indicated in our fleet status report, the customer has agreed to pay a reduced day rate for any remaining idle time on the rig. Also in Norway, six one-well options were exercised on the Transocean Encourage at a rate of $464,000 per day.

The added duration extends the firm term an additional 370 days to February 2026. As for our ultra-deepwater rigs, following the release of our latest fleet status report, an operator in the U.S. Gulf of Mexico awarded the Deepwater Invictus, an estimated 20-day P&A well at a rate of $440,000 per day. The well will commence a direct continuation of the rig’s current program. Finally, in the Mexican Gulf of Mexico, an independent operator awarded a 1,080-day contract for one of three of our high-specification seventh-generation ultra-deepwater drillships at a rate of $480,000 per day. We will select the rig from among the Deepwater Invictus, Deepwater Thalassa and Deepwater Proteus. The contract, which does not include any additional services is expected to commence between the fourth quarter of 2025 and the second quarter of 2026, and provides us with considerable flexibility to optimize our asset portfolio as we maintain the ability to designate the rig up to one year prior to the commencement window.

Additionally, the contract includes a semiannual cost adjustment mechanism that provides margin protection from cost inflation. The picture also highlights the trend we observed in our discussions over the past several months. More customers expressing strong interest in securing rigs for longer-term projects starting further in the future. This interest is now progressing into action as multiple operators intend to commit to multiyear projects starting as illustrated by our recent award in Mexico as late as 2026. We believe this signals our customers’ recognition of the scarcity of capable high-specification assets and clearly demonstrates their strength and commitment to offshore projects, further validating that we are in an up cycle that would be of significant longevity.

Contract durations are linking materially. In fact, year-to-date 2023, the average contract length of a drillship awards has increased to 495 days versus 310 days in 2022 and representing a year-over-year increase of nearly 60%. Additionally, the average duration of semisubmersible pictures increased approximately 18% over the same time period and nearly 150% from 2020. Nearly 15,000 drillship days have been awarded in 2023 to-date, a 134% increase when compared to the same period in 2022. Similarly, nearly 8,500 harsh environment semisubmersible days have been awarded this year, a 72% increase when compared to the same period last year. Globally, we see approximately 81 rig years of work to be awarded across 80 floater programs, suggesting an average duration per program of approximately one year.

This is up from just between seven and eight months just 18 months ago. Of note, more than a quarter of these programs are designated for exploration and appraisal wells. Although our contracting strategy may necessitate short periods of inactivity on key rigs as we maximize our long-term EBITDA and margins, we expect the rig market will remain tight, particularly for the highest specification ultra-deepwater drillships and harsh environment semisubmersibles. According to Wood Mackenzie analysis and as recently echoed by Schlumberger, approximately 85% of the nearly $500 billion of investment in oil and gas between 2022 and 2025, and generate favorable returns at oil prices below $50 per barrel. Of this, approximately $200 billion is expected to be invested in deepwater projects.

As you well know, commodity prices have remained comfortably above the $50 per barrel level for more than two years and remained stable in the mid-$70 to mid-$80 per barrel range. As the majority of offshore breakevens are significantly below this threshold and many are below $50 per barrel, we expect our customers’ programs to receive approvals to move ahead. As further evidence of market strength, a number of operators are evaluating and increasingly pursuing long-term rig contracts that are not yet tied to specific projects or may not yet have the approval of all project partners. We have not seen this type of market behavior in some time, and it is perhaps one of the more exciting and encouraging market developments to-date. As we’ve already discussed the various harsh environment markets, let’s take a closer look at the ultra-deepwater region.

In the U.S. Gulf of Mexico, direct negotiations continue to be the preferred contracting strategy for our customers. Many of the conversations we are having involve multiyear opportunities, in some cases, up to five years. These include programs in fields that require 20,000 psi completions, a capability that only the Deepwater Titan and Deepwater Atlas currently possess. With the Titan contracted through the first quarter of 2028, the Atlas will be the only rig available with this capability following the completion of its current contract in August 2024. In Brazil, the Petrobras pooled two tenders in its final stages, with Petrobras recently announcing the winning bids, including the deepwater Qila. We expect the full award to be finalized by the end of August.

Additionally, the much anticipated Petrobras Búzios tender is well underway. The two tenders combined could absorb up to seven rigs in the next 15 months, three of which we believe would need to come from outside the region. The momentum in the region is expected to continue at just last week. Petrobras issued another tender for up to three rigs with a commencement of mid-2025. Additionally, Equinor has issued a request for information for its BMC 33 Block offshore Brazil for approximately two years, starting in the second or third quarter of 2026. In West Africa and the Mediterranean sea, there are numerous multiyear opportunities expected to commence within the next 18 months. Several operators seek rigs for projects that could be greater than five years in duration.

We also see multiyear opportunities spread across the region, including Shell Nigeria, Azul Energy’s two year tender in Angola and OMV’s tender in the Romanian Black Sea. And finally, in India, ONGC tender is nearing completion, and we believe an award for one rig for up to 21 months is imminent. We also expect to see demand for one or two additional rigs in the next 12 months. Taking a closer look at our fleet, during the second quarter, the Deepwater Titan started its first contract with Chevron on the anchor project in the U.S. Gulf of Mexico. And just last week, the Titan 20K BOP was deployed using the third installed robotic riser system in our fleet, which further improves operational efficiency and crew safety through automation. Titan joins its sister ship the Deepwater Atlas as one of only two eighth generation ultra-deepwater drillships in the global fleet.

The rig’s 3.4 million pound hoisting systems are capable of running heavier casing strength than any other floating drilling rigs. This can shorten the well time as well as potentially preserve a larger borehole for sour customers’ follow-on production activities. The rigs 20,000 psi well control equipment enables completion of higher-pressure reservoirs, thereby unlocking projects that were previously inaccessible. The increased hook load and higher pressure equipment provide important advantages for both drilling and completions and make the rigs highly desirable for both activities. Also during the quarter, we committed to the sale of two harsh environment floaters, the Paul B, Lloyd Jr. and the Transocean Leader. These lower specification assets are best suited to the U.K. North Sea, and further demonstrate our strategy to focus on our high-specification floating fleet that is in high demand in other jurisdictions.

Once the sale closes, we will have a fleet of 28 ultra-deepwater floaters and eight harsh environment floaters in addition to our noncontrolling ownership interest in Laquila Ventures, which is currently building the deepwater Laquila. Within our portfolio, we have 10 of the 14 highest tier drillships in the global fleet. We also have 11 cold stacked floaters, including 10 ultra-deepwater rigs and one harsh environment semisubmersible. With our active fleet near full utilization, we are actively bidding these stacked assets into open tenders and direct negotiation opportunities. Our stacked fleet provides us with the most operational leverage of our peer group. There are just 12 cold stacked sixth and seventh generation drillships remaining, and eight of these are owned by Transocean.

In addition to the 12 cold stacked sixth and seventh-generation drillships, there are just four so-called stranded newbuild rigs remaining in the shipyards without an owner or publicly known option to purchase. We expect the cost to commission these stranded rigs into the active fleet to be between two to three times the cost of reactivating cold-stacked rigs due to an initial purchase price between $200 million and $300 million, plus contract preparation costs. As compared to the cold stack reactivation estimates, they’re $75 million to $125 million. And for those of you who may be wondering, we do not believe we will see any newbuild commission for many years and in the extremely likely event that we do, the timeline to completion would likely be between three to five years and the capital required could exceed $1 billion.

In short, we believe the transition will remain the supplier of choice for incremental ultra-deep water rig capacity and we will continue to demonstrate extreme discipline when considering contract renewals and reactivations. As we continue to benefit from the rapidly improving offshore market, the cash flow generating ability of our fleet becomes increasingly strong. Utilizing free cash flow from operations, we intend to prioritize capital allocation during the next several years, starting as we previously said, with a focus on deleveraging our balance sheet. This remains an imperative and will be carefully balanced and coordinated with our other priorities, including maintaining our active fleet, reactivating stacked assets to specific customer contracts and deploying some of the new technologies that we have successfully developed and tested over the past several years, all with the ultimate goal of maximizing value for our shareholders.

As we have demonstrated, we will generate that cash flow by maximizing the value of our active fleet and remain disciplined when it comes to reactivating our stack fleet. For the past several years, we have taken the approach quite effectively of emphasizing day rates over utilization using several of our highest specification rigs. As an example, our recent contract for the deepwater. Invictus at a rate of $480,000 per day is $220,000 per day higher than we contracted the Invictus just 2 years ago. an increase that is a direct result of our contracting strategy. In some circumstances again our strong backlog position, we were able to take the tactical decision to trade utilization in pursuit of higher day rates, which, as you know, is the essential foundation of cyclical EBITDA margin maximization.

This strategy has benefited Transocean and, quite frankly, the industry overall. We will continue to evaluate opportunities on a case-by-case basis and applying our holistic portfolio approach, use our available assets to secure the optimal combination of utilization and day rates. In summary, we are undoubtedly in what appears to be a multiyear up cycle, our customers are both demonstrating their confidence and commitment to their projects and acknowledging the tightness of the supply for the high-specification floaters by securing rigs well in advance of their programs and locking them up for multiple years is Transocean owns and operates the industry’s high-specification fleet of ultra-deepwater and harsh environment floaters and also owns the majority of the sixth and seventh generation cold stacked rigs, we believe that we are best positioned to capitalize on this up cycle through increasing day rates on our active fleet and remaining disciplined with our staff fleet.

Over the past last year, we have demonstrated that we can achieve both leading-edge rates and maximize term and still grow our backlog. And through the flawless execution of our operations, we will efficiently convert that industry-leading backlog to cash which we will then use to quickly delever the balance sheet and create sustainable value for our shareholders. Now I’ll turn the call over to Mark. Mark?

Mark Mey: Thank you, Jeremy, and good day to all. During today’s call, I will briefly recap our second quarter results and provide guidance for the third quarter and update on our expectations for the full year 2023. Lastly, I will provide an update on our liquidity forecast through the end of 2023. As reported in our press release, which includes additional detail on our results for the second quarter of 2023, we reported a net loss attributable to controlling interest of $165 million or $0.22 per diluted share. The certain adjustments as stated in yesterday’s press release, we reported adjusted net loss of $110 million. During the quarter, we generated adjusted EBITDA of $237 million which translate into cash flow from operations for approximately $157 million.

Our free cash flow of $81 million in the second quarter reflects capital expenditures of $76 million of which approximately $50 million was related to the recently delivered eighth-generation drillships, the Deepwater Atlas and Deepwater Titan. Looking closely at our results, during the second quarter, we delivered adjusted contract drilling revenues of $748 million at an average day rate of $367,000. This is above our previous guidance, mainly due to the postponement of a couple of short playing out-of-service projects into Q3, higher-than-expected recharge revenue and higher revenue efficiency stemming from strong bonus conversion on several rigs. Operating and maintenance expense in the second quarter was $484 million this is below our guidance primarily due to timing of certain maintenance activities.

Turning to the cash flow and balance sheet. We ended the second quarter with total liquidity of approximately $1.6 billion, including unrestricted cash and cash equivalents were approximately $821 million, approximately $175 million of restricted cash for debt service and $600 million from our undrawn revolving credit facility. I will now provide an update on our expectations for our third quarter and full year financial performance. As always, our guidance reflects only contract-related rig reactivations and/or upgrades. For the third quarter of 2023, we expect adjusted contract drilling revenue of approximately $720 million based upon an average fleet-wide revenue efficiency of 96.5%. The quarter-over-quarter decrease is mainly due to the planned mobilization and contract preparation activities on the Transocean Barents, the Transocean Endurance, Deepwater Corcovado and Deepwater Mykonos also driving this decrease is the Deepwater Atlas 20K bop swap and low utilization on a Development Driller III and Discoverer Inspiration.

This is partially offset by a full quarter of activity in Deepwater Titan and Transocean Norge. The commencement of the KG2 contract in Brazil and higher day rates on the Corcovado new contract following the other service period. For full year 2023, I am reiterating prior guidance of adjusted contract drilling revenue of between $2.9 billion and $3 billion. We expect third quarter O&M expense to be approximately $540 million. This quarter-over-quarter increase is due to the changes in feed activity, timing of in-service projects, continuing preparation of the Deepwater Orion in advance of its contract commencement in Brazil and the start of contract preparation activities on Transocean Equinox, the Transocean Endurance with a work in Australia.

Our expected full year 2023 operating and maintenance expense is forecasted at $1.95 billion, slightly higher than our prior guidance and mainly due to certain contract preparation activities on the recently announced fixtures, including the Transocean Equinox and Transocean Barents. We expect G&A expense for the third quarter to be approximately $55 million and around $210 million for the full year. Net interest expense for the third quarter is forecasted to be approximately $133 million. For the full year, we estimate net interest expense to be approximately $470 million including capitalized interest of approximately $38 million. And excluding the fair value adjustment for the bifurcated exchange feature embedded in our exchangeable bonds issued September 2022 of $179 million from the first half of 2023.

Capital expenditures for the third quarter are forecasted to be approximately $705 million, including approximately $33 million related to the Deepwater Atlas and Deepwater Titan. Cash taxes are expected to be $6.3 million for the third quarter and $45 million for the year. Our expected liquidity in December of 2023 is predicted 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. Unrestricted cash of $220 million, which is mostly a reserve for debt service. This liquidity forecast includes 2023 CapEx expectations of $270 million, with approximately $160 million which relates to our new previously delivered newbuilds and $110 million for sustaining and contract preparation CapEx. As Jeremy mentioned in his prepared comments, we have seen a material increase in day rates across our portfolio of assets.

Weighted average of our new contract day rates announced in our July 19 fleet status report with approximately $456,000. An existing contracts conclude and our fleet continues to move on to these and other higher day rate contracts, we will increasingly generate more operational cash flow. With the completion delivery and contract commencement with the Deepwater Atlas and the Deepwater Titan, our capital expenditures declined materially, increasing free cash flow to address our balance sheet and assess other actions that create value for shareholders. With respect to ongoing balance sheet activities, our recent share price performance has resulted in all of our tangible bonds being deepened consistently in the money. As such, we expect but these bondholders may be inclined to convert their position to shares.

And in fact, we have received numerous inquiries regarding early conversion. As a reminder, our total remaining EV debt obligation is approximately $620 million. In addition to reducing our debt through early conversion of EVs. And as we have previously indicated, we remain committed to simplifying our balance sheet and reducing cash interest costs as and when market conditions are supportive. That concludes my prepared comments. Now I turn the call back over to Alison.

Alison Johnson: Thanks, Mark. Carlos, 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.

Q&A Session

Operator: [Operator Instructions] We will go first to Kurt Hallead with Benchmark. Your line is open.

Kurt Hallead: Thank you. Hi, good morning, everybody.

Jeremy Thigpen: Good morning, Kurt.

Kurt Hallead: Thanks as always for the color commentary on market dynamics and the guidance points. So maybe just want to kick off just on the guidance. So it looks like, Mark, as you mentioned, you slightly increased the operating cost elements by about $100 million at the midpoint for this year. And I guess I take it it’s increased number of rigs running and contract prep and other things that are going into it. So as we – as we maybe think about going into 2024, what kind of increases in op costs just at a high level, if any, would you anticipate?

Mark Mey: Yes. Thanks, Kurt. I think year-on-year, we probably see organic increase somewhere in the 2% to 4% looking at inflation, driven mainly by our CBA negotiations with our crews in various parts of the world. We’re still seeing some inflation on the R&M side, but it’s being muted. So unless we increase the number of active rigs, as you said, I don’t see it increasing much more than 2% to 4%.

Kurt Hallead: Got it. Thanks. And then coming back to the market, as you’ve kind of referenced in the fleet status report, looks like you guys were the first company to get a contract that exceeds $500,000 a day. And I guess the note there was, it was not a drill ship, it was a semi. So I guess, the question is, you know, what do you see on the horizon for drill ship pricing and do you think we’ll still, you know, see a drill ship book a contract at over $500,000 a day before the end of the year?

Roddie Mackenzie: All right. Hi, this is Roddie. I think I’ll take that one. So specifically thank you for mentioning the contract that’s now finally in black and white as being above 500,000 a day. Jeremy was patting himself on the back and rightfully so. Look we, you know, we, we don’t really pay too much attention to the actual thresholds, but what I would draw your attention to is as we think about, you know, the industry analysts, you know, even including ourselves, the pace at which day rates have increased and the thresholds at which they’ve reached have eclipsed everybody’s expectations. If we think just 18 months ago, the forward projections for, you know, a really solid recovery had the day rates in the high threes.

Now, if you start to look at forward projections from various different sources, they’re saying that within the next 12 months or so, you should see the pictures being the high fives. So in terms of when the first one for the alternate water fleet will be in print above a five, I think we had previously said we’d expect by the end of this year, I think I’d say the same thing again. But you never know, so far the recovery in the market has kind of outstripped everybody’s expectations.

Kurt Hallead: Great. And maybe just one last one. So you mentioned, Jeremy, there’s 12 cold stacked drill ships in the market. Obviously, you own eight of those. I think in the last conference call you indicated that there is, I think potential demand for something along the lines of maybe 20 incremental rigs over the course of the next, I don’t know, two years or so. Is that — are you guys still looking at that level of demand?

Jeremy Thigpen: I’m not sure that we ever referenced 20 maybe we did. We’re still seeing very strong demand, and we do fully expect to start reactivating some of these assets here over the course of the next several months. You know, if you look at the 12 stacked sixth and seventh gen rigs out in the marketplace, we do have eight of them. Three of those are seventh gen rigs, which we and Keelan, is not with us today because he is been out visiting our rigs those three seventh gen rigs are in very, very good shape. He was very impressed with the — with the quality of the preservation there. And so we fully expect to bring those three rigs out in the not too distant future.

Roddie Mackenzie: Yes. Hi, I think I’ll add to that and just say that, you know, if you look at some of the projections by the various analysts, it shows in certainly in ’24 and ’25 that there are going to be a deficit of rigs available. So on the ultra-deepwater side, that’s going to be anywhere from 10 — maybe even all the way up to 20 rigs in that timeframe. And then, of course, in the harsh environment side, we’re seeing there’s going to be a shortfall of at least 5, maybe as many as 10 rigs in the harsh environment sector. So definitely both sectors are showing a deficit of rigs going forward from ’24. And that really puts the emphasis on our customer to act quickly because as we said before, it’s going to take probably 12 months, maybe a little bit more to reactivate these cold stacked rigs. And so we need to see contracts on soon if we’re going to meet this demand that’s coming up in ’24, ’25 and ’26.

Kurt Hallead: That’s great. Thanks for the call. Appreciate it.

Operator: And we will go next to Eddie Kim with Barclays. Your line is open.

Eddie Kim: Hi, good morning.

Jeremy Thigpen: Good morning, Eddie.

Eddie Kim: My question is on the fixed priced options and escalating nature of these options that have been secured in recent months for your fleet, the one that stands out is obviously the Equinox with those options as high as 540,000 a day by mid-2020. And — could you just provide us with a little more insight into the recent negotiations on these fixed-price options in the past, the day rate on these options were typically lower than the firm contract. But this seems to have clearly shifted in recent months. Any color here would be great.

Jeremy Thigpen: Yes, sure. So one of the key things is, once the rigs are in place and working steady state, the cost for the operators to switch to perhaps a cheaper alternative is fairly substantial. So you get this phenomenon that typically extensions at that point are going to be higher in day rates when you’re in this multiyear up-cycle. So to kind of underline that, the number of rigs available to go do this work and that we’ll actually be in a position to do the work is kind of the primary driver where you’ve got feed of missing out or formal that is now present amongst many of the operators that if it has to do the work, then best to get a binding option on our rig, even if that happens to be at a market-leading rate, because I think by the time we get to the time frame that is executed, that will not be the market-leading rate.

I think those guys will have proven to benefit by moving quickly and getting those options on the table first. So I think this is the tip of the iceberg. I think you see many, many more of these contracts come out this way. I think we’re in this phase of higher for longer and as we said before, the fear of missing out is real because the available supply in the market is just substantially less than it was in the last up cycle.

Eddie Kim: Got it. That’s great to hear. And just on the fixed price option, it looks like based on your fleet status report that most of your fixed price options are on a harsh environment fleet. Has it been more difficult to secure these options on your drillship fleet? Or is that something we should expect to see more of with new contracts signed in the coming months?

Jeremy Thigpen: Yes. You probably will see more of it. But one of the things in an up cycle, if you really have the feeling that — things are going to continue to move, then putting fixed price options on rigs, perhaps not to our advantage unless those prices are really substantially higher than where they are today. So I’m not sure you’ll see a lot more of that, and I actually think that’s going to be a positive as this market gets tighter and tighter. So yes, we’re pretty flexible on that, but we certainly try to keep our powder dry on our very best assets.

Eddie Kim: Got it. Understood. That makes sense. If I could just squeeze one more in here. The question is on the Invictus. It’s clear that this is one of the highest-quality drill-ships in your fleet and in the global fleet. Otherwise, it wouldn’t have been selected as one of the rigs for that three-year contract you just signed in Mexico that commences in late 2025. But at the same time, the rig is currently idle since coming off contract in July or was idle, I should say, until you just announced that 20-day P&A work in prepared remarks, but could you just provide some more insight here given the significant near-term availability the rig has is there just enough incremental near-term demand in the U.S. Gulf of Mexico? Or is the decision to keep availability on the rig more of an intentional one?

Roddie Mackenzie: Yes. So our intention on this rig is being one of the highest specifications. We do want to keep time available on her. As we kind of had demonstrated and Jeremy alluded to it in his comments, using the higher-spec assets to kind of move to the next tier of day rates is essentially the strategy that we played out over the past 18 months. So with the rest of our high-specification fleet in the Gulf of Mexico spoken for. And again, several options in place that mean really the Invictus is the only rig that we have available at that specification level. So as we pointed out, yes, we just picked up another contract on her now. So that was actually in direct continuation of the previous one. And without giving away all our cards, we are in extended discussions with other operators for similar events.

So we’re quite comfortable to have her on kind of shorter-term basis at the moment, and that’s actually what allowed us to secure that $480,000 a day, three-year contract based on the fact that she was available. So it’s really all part of that strategy that we describe as making sure we have some of the best assets available to take advantage of this rapidly improving market. And at the same time, you offset that with the fleet as a whole, we have more rigs on long-term contracts than anybody else. So we’re kind of in a luxurious position to be able to do that.

Eddie Kim: Got it. Great, thank you Roddie? I’ll turn it back.

Operator: We will next go to Greg Lewis with BTIG. Your line is open.

Greg Lewis: Yes, thank you, everybody. Thank you for taking my questions. Mark, I was hoping you could talk a little bit more around costs and realizing we’re ramping rigs, we’re spending money to get some rigs where they need to be before they go on contracts. Is there kind of any way to think about what normal beyond just the regular cost inflation of a couple of percent a year. Is there any kind of way to think about how we should think about it on an ongoing basis about what’s maybe like a normalized number, realizing you’re probably going to be activating. It seems like the markets thought you’ll be able to activate a couple of rigs here in the next, call it, two to three years. With each of those I mean, ballpark, maybe want to add $50 million to $60 million in annual OpEx. Is that like any kind of color on normalization?

Mark Mey: Yes, Greg, that’s not an easy number to give you because if I differ widely, take for arguments sake, the Corcovado and Mykonos. As they go between contracts in Brazil, those rigs come out of service, we think go and clean the halls and then move them back into the operating environment. That’s only going to cost us a couple of million dollars. That’s not a big number. And then you bring a rig into Brazil for the first time, you’re looking at that $50 million to $60 million. So there really isn’t a normalize — it can vary widely between those levels. And as Jeremy mentioned in his prepared comments, we’ve estimated our reactivations on the cold stack rigs to be $75 million to $125 million. So now your range is $2 million to $125 million.

So if I give you a normalized number, it’s really going to be just a bad forecast. So I think you have to listen and watch and see if we reactivate rigs, and we’ll give you guidance then as to what we’re going to be spending on that. But I don’t want to give you a normalized number.

Greg Lewis: Okay. Great. And then, as I think about what you guys have done in tightening the semi market in the North Sea has been pretty constructive. Curious, the U.K. government realizing your rigs are hot, your semis are higher end, so you don’t have a lot of U.K. exposure, but it seems like strengthening the U.K. should filter into Norway in the Central and North Sea. Could you talk a little bit about the potential impact for that announcement? And really, as we look ahead, is this — should this start to show up in ’24? Or is it more kind of back half a decade kind of pickup in demand from the U.K. news about, I guess they’re trying to incentivize more oil and gas drilling sooner rather than later?

Jeremy Thigpen: Yes, I’ll take that. Look, I mean the issue with the U.K. without us getting into politics is really simply a windfall tax is not constructive for taking FID decisions, so in the U.K., where you have somewhat of an uncertain tax regime with regards to oil and gas. The announcement of increased lease sales doesn’t actually solve the current problem of unknown or varying taxation So, we don’t expect our customers to rapidly increase activity in the U.K., but certainly, new licensing is welcome. It says that the government recognizes that oil and gas is going to be a very strong part of the energy balance as we move forward. In terms of how [indiscernible] effect in Norway, you’re right to observe that typically the higher specification rigs go to Norway and other places, and that’s certainly what we’re seeing going forward here.

But I think in general, the harsh environment market today is 100% sold out for the high-spec assets, and that does not look like it’s going to change anytime soon. In fact, most projections show that we are going to be short several rigs. So given Jeremy’s comments about what it would take to bring a new build to the market, we actually don’t see that deficit being solved anytime soon. So I think you’re going to see very strong harsh environment fixtures for the foreseeable future and arguably that’s kind of the key marker for the long-cycle thinking that’s in place now. So yes, not really help to the U.K., but reality.

Mark Mey: And Ryan, just since you brought it up, I mean, the lead time between ordering a new build in today’s market and slotting that spot at a shipyard, I imagine that’s three, four, five years.

Roddie Mackenzie: Yes, probably closer to five if not more.

Greg Lewis: Understood. Okay, thank you for the color.

Operator: We will take our last question from Fredrik Stene with Clarksons Securities. Your line is open.

Fredrik Stene: Hi Jeremy, and teams. Hope you are well and you’ve had a nice summer. I want to finish it with a few follow-ups on themes that have been partially discussed. And we can start with a harsh environment market. As you said initially, there is there’s definitely nothing to be a shortage here. And I agree the pace at which these semis have less Norway has been sounding in a way. And I can imagine that there are a few operators in Norway now that may we have the greatest form of all. So I was wondering kind of compared to how those discussions were back in the third quarter last year. Are you — are they phoning you every day asking for capacity? And how are they handled and how have the discussions been changed over this last six to nine months? And I guess kind of finally, what’s — if you can give us a number what’s the day rate that you would require to bring your rigs back into Norway to help Equinor and the peers out there?

Jeremy Thigpen: Okay. I’ll take that. And so the first part of the question about how have things changed in 12 months. So obviously, they’ve changed substantially. I think if you have the time, if you go back and look at our transcripts from previous earnings calls, and we messaged this as loud and clear as we possibly could because we’re in a position back then a year ago that we really needed to work for two, three, four of these rigs. So we messaged that, look, if we can’t find the work in our way, we have to go elsewhere. So to us, it certainly wasn’t a surprise, but I realize that that’s the case for some that the pace at which that change is substantial. So in terms of where you are now, bringing rigs back to Norway, I think you’re going to see — that’s going to happen actually.

I think almost — maybe not quite as quickly, but certainly, you will see a response, which we’ve already seen in terms of a couple of tenders that were launched in very short order to pick up rigs for multiple years to bring them back into Norway. You’ll see who’s basically concluded over the next month or two. And that’s going to be at substantially higher day rates with substantially longer term, and that’s basically what it’s going to take. If I think about the rigs coming back, it’s going to be — they’re going to be paid on day rate to come back. All the expenses will be covered to come back. And of course, you’ll be looking to maintain those solid EBITDA margins that you make overseas to make it attractive. But I do think there will be some rigs come back, but it’s going to be at higher numbers.

Mark Mey: Yes. And just to add to that, I mean, operationally, there is real value and continuity. And that’s why we approached our customers in Norway before we decided to move these rigs out of Norway to new jurisdictions. There’s value in continuity. And so if the opportunities remain robust in Australia, it’s going to take a lot to pull those rigs out of Australia at meeting the customers is really going to have to pay for or not only the mode, but a higher day rate. And so it’s going to be a challenge.

Jeremy Thigpen: Yes. No, really, we’ve got options on one of the rigs out to 2028 and then on the other rig, we’re in active discussions to add more time to her. So realistically, I think for those two CAT-Ds, it’s going to be a very long cycle before they come back. I think there’s probably more focus around the likes of the parents that recently left to see if there’s interest in bringing her back.

Fredrik Stene: That’s super helpful color. Second question. As you say, you control two-thirds of the stacked dealership fleet and I got impression now that we could start to see you guys reactivating some of those assets as well. And I guess so far, it’s clear that some of your peers have been more aggressive in some of those reactivations, which has left you now with a larger, call it, market share of that stacked fleet. So I was wondering now that you’re approaching 100% market share on the stacked assets? Are you having kind of an active strategy to wait until they have flushed out the remaining of their capacity to be the sole price factor? Or are you thinking that now is the time to start to bring some of those units back?

Jeremy Thigpen: I think we’ve been pretty consistent on that front. We are going to be paid by the customer in the first contract to reactivate those rigs plus the return. And so we’re going to continue to be disciplined on that front. We feel no urgency to reactivate for the sake of reactivating. And if our competitors foresee that strategy, that’s fine with us.

Fredrik Stene: One final short question. You talked briefly about the indicators and some potential short-term opportunities there on the Inspiration unless I missed it. Are there any news there on what can be on the news of her and going forward in terms of New York?

Jeremy Thigpen: Yes. So we’re in discussions and part of tenders on a couple of things for the inspiration. But –you know she’s an example of one of our lower specification units. So we’ll kind of take a measured approach to that. We’re not going to jump on anything just yet. We’re not in a particular hurry to do anything there, but there are a couple of interesting things on the horizon. So stay tuned.

Fredrik Stene: Great. Thank you guys for taking all my questions, and have a good day.

Jeremy Thigpen: Thank you, Tim.

Operator: As there are no other questions, I will turn the call back to the speakers for any closing comments.

Alison Johnson: Thank you, Carlos, and thank you, everyone for your participation on today’s call. We look forward to talking to you again when we report our third quarter 2020 earnings. Have a good day.

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