Transocean Ltd (RIG) 2023 Q2 法說會逐字稿

Good day, everyone, and welcome to today's Q2 2023 Transocean Earnings Call. (Operator Instructions) Please note, this call may be recorded. It is now my pleasure to turn today's program over to Alison Johnson, Director of Investor Relations. Please go ahead.

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 resulting 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 look -- 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 will now turn the call over to Jeremy.

Thank you, Alison, and welcome to our employees, customers, investors and analysts participating on today's call.

As you saw in our latest release stats 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. Per 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 2022 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 this migration. Since then, 3 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 may be 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, day rates for harsh environment semisubmersibles have meaningfully increased since the beginning of the year and are now rapidly approaching $500,000 per day for firm work with certain price 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 Transition Barents was awarded a 1-well contract with Total Energies in 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 2 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 5-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 option well at the end of the firm turn.

The Equinox was also awarded a 50-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 1-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 3 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 1-well option on the Transocean Norge at a rate of $365,000 per day and 3 1-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, 6 1-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 in Victus, 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.

And finally, in the Mexican Gulf of Mexico, an independent operator awarded a 1,080-day contract for 1 of 3 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 Vilas 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 1 year prior to the commencement window.

Additionally, the contract includes a semiannual cost adjustment mechanism that provides margin protection from cost inflation. This 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, representing a year-over-year increase of nearly 60%. Additionally, the average duration of semisubmersible fixtures 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 1 year. This is up from just between 7 and 8 months just 18 months ago. Of note, more than 1/4 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, 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 2 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.

Since we've already discussed the various harsh environment markets, let's take a closer look at each 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 5 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 2 tenders in its final stages, with Petrobras recently announcing the winning bids, including the deepwater kilo. We expect the full award to be finalized by the end of August. Additionally, the much anticipated Petrobras Buzios tender is well underway. The 2 tenders combined could absorb up to 7 rigs in the next 15 months, 3 of which we believe would need to come from outside the region.

The momentum in the region is expected to continue as just last week, Petrobras issued another tender for up to 3 rigs with a commencement of mid-2025. Additionally, Equinor has issued a quest for information for its BMC 33 Block offshore Brazil for approximately 2 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 5 years in duration. We also see multiyear opportunities spread across the region, including Shell Nigeria, Azul Energy's 2-year tender in Angola and OMV's tender in the Romanian Black Sea.

And finally, in India, ONGC's tender is nearing completion, and we believe an award for 1 rig for up to 21 months is imminent. We also expect to see demand for 1 or 2 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 Titans 20K BOP was deployed using the third installed robotic riser system in our fleet, which further improves operational efficiency and crew safety through automation.

The Titan joins its sister ship the Deepwater Atlas as one of only 2 eighth generation ultra-deepwater drillships in the global fleet. The rig's 3.4 million pound hoisting systems are capable of running heavier casing strengths than any other floating drilling rigs. This can shorten the well time as well as potentially preserve a larger borehole for our customers' follow-on production activities.

The rig's 20,000 PSI well control equipment enables completion of higher-pressure reservoirs thereby unlocking projects that were previously inaccessible. The increased hookload 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 2 harsh environment floaters, the Paul B. Loyd Junior 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 8 harsh environment floaters in addition to our noncontrolling ownership interest in Liquila Ventures, which is currently building the deepwater kilo.

Within our portfolio, we have 10 of 14 highest (inaudible) drillships in the global fleet. We also have 11 cold-stacked loaders, including 10 ultra-deepwater rigs and 1 harsh environment semisubmersibles. 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 8 of these are owned by Transocean. In addition to these 12 cold-stacked sixth and seventh-generation drillships, there are just 4 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 2 to 3x 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 a cold-stacked reactivation estimates of $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 unlikely event that we do, the time line to completion would likely be between 3 to 5 years and the capital required to transition will remain the supplier of choice for incremental ultra-deepwater 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 remaining 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 overutilization 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, given 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.

As Transocean Ocean 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 actively and remaining disciplined with our stack fleet.

Over the past 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.

I'll now turn the call over to Mark. Mark?

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 $155 million or $0.22 per diluted share. After 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 translated into cash flow from operations of 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 H&R ration 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 plan 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 of approximately $821 million, approximately $175 million of restricted cash for debt service and $600 million from our undrawn revolving product 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 activations 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%. This quarter-over-quarter decrease is mainly due to 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 3 and discoverer inspiration. This is partially offset by our 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 fee activity, timing of in-service projects, continuing operation of the Deepwater Orion in advance of its contract commencement in Brazil and the start of contract preparation activities on a transaction of Equinox, the Transocean Endurance for their 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 of 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 $75 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 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 recipient cash of $220 million, which is mostly a reserve for debt service.

This liquidity forecast includes 2023 CapEx expectations of $270 million, which approximately $160 million is related to our 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. The weighted average of our new contract day rates announced in our July 19 Feature report was approximately $456,000. As 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 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 that 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 EB debt obligation is approximately $620 million. In addition to reducing our debt through early conversion of EVs, 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.

This concludes my prepared comments. Now I'll turn the call back over to Alison.

Thanks, Mark. Carlos, we're now ready to take questions.

(Operator Instructions) We will go first to Kurt Hallead with Benchmark.

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 about $100 million at the midpoint for this year. And I guess, I take it as increased number of rigs running and contract prep and other things that are going into it.

So 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?

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%.

Okay. Got it. And then coming back to the market, as you've kind of referenced in the fleet status report, it 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 drillship, but it was a semi. So I guess the question is, what do you see on the horizon for drillship pricing? And do you think we'll still see a drill ship book a contract at over $500,000 a day before the end of the year?

This is Roddie. I think I'll take that one. So specifically, thank you for mentioning the contract that's now finally in Black & White as being above $500,000 a day. He was padding himself on the back -- and rightly so.

Look, 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 the industry analysts, 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 a really solid recovery had the day rates in the high 3s. 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 fixtures be in the high 5s.

So in terms of when the first one for the all 3 water fleet will be in print above 5. I think we had previously said we'd expect it 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.

Great. And maybe just one last one. So you mentioned Jeremy, there's 12 cold-stacked drillships in the market. Obviously, you own 8 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, 2 years or so. Is that -- are you still looking at that level of demand?

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.

If you look at the 12 stacked sixth- and seventh-gen rigs out in the marketplace, we do have 8 of them, 3 of those are seventh-gen rigs, which we Keelan is not with us today because he's been out visiting our rigs. Those 3 segment gen rigs are in very, very good shape. He was very impressed with the quality of the preservation there. And so we fully expect to bring those 3 rigs out in the not-too-distant future.

Yes. I think I'll add to that and just say that 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 altered deepwater side, that's going to be anywhere from 10 -- maybe even all the way up to 20 rigs in that time frame.

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.

Right. And that really puts the emphasis on our customers 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 signed soon if we're going to meet this demand that's coming up in '24, '25 and '26.

And we will go next to Eddie Kim with Barclays.

So my question is on the fixed price options and the 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-2027. 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.

Yes, sure. So look, 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 upcycle.

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 this feed of missing out or format that is now present amongst many of the operators that if they have to do the work, then best to get a binding option on a 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 or missing out is real because the available supply in the market is just substantially less than it was in the last up cycle.

Got it. That's great to hear. And just on the fixed price option, it looks like based on your fleet status report, then 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?

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 rig is 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.

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 drillships in your fleet and in the global fleet. Otherwise, it wouldn't have been selected as one of the rigs for that 3-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?

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 a shorter-term basis at the moment, and that's actually what allowed us to secure that $480,000 a day, 3-year contract based on the fact that she was available.

So it's really all part of that strategy that we described 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.

We will next go to Greg Lewis with BTIG.

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 market is tight you'll be able to activate a couple of rigs here in the next call of 2 to 3 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?

Yes, Greg, that's not an easy number to give you because they differ widely, take for argument's sake, the Corcovado and the Mechanist, as they go between contracts in Brazil, those bodies have 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 that can vary widely between those levels. And as Jeremy mentioned in his prepared comments, we've estimated our reactivations on the cold-stacked 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 reactive 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.

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. I'm curious, the U.K. government realizing your rigs are -- your semis are higher end, so you don't have a lot of U.K. exposure, but it seems like strength in 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.

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 it has Northern 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 helpful to the U.K., but reality.

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 mean, I imagine that's 3, 4, 5 years. Is that...

Yes, probably closer to 5 if not more. For semi, they're more complicated.

We will take our last question from Fredrik Stene with Clarksons Securities.

Jeremy and team, I hope you are well, and you've had a nice summer. So I want to just 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 shorter here. And I agree the pace at which these semis have less Norway has been astounding in a way. And I can imagine that there are a few operators in Norway now that maybe 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 have they handled up? How have the discussions with them changed over this last 6 to 9 months?

And I guess kind of finally, what -- 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 here?

Okay. I'll take that and then... 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 2, 3, 4 of these rigs. So we messaged that, look, if we can't find the work in Norway, 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 we 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 2. 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 look, I do think there will be some rigs to come back, but it's going to be a higher numbers.

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, meaning the customers is really going to have to pay for not only the mode, but a higher day rate. And so it's going to be a challenge.

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 2 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.

Second question. As you say, you control 2/3 of the spect basically, and I got the impression now that we could start to see you guys reactivating some of those assets as well. 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 fleet.

So I was wondering now that you're approaching 100% market share on the flat 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 sector? Or are you thinking that now is the time to start to bring some of those units back?

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 a 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 pursue that strategy, that's fine with us.

And final short question. You talked briefly about the indicators and some potential short-term opportunity there on the inspiration unless I missed it, are there any news there on what can be on the news for her going forward in terms of New York?

Yes. So we're in discussions and part of tenders on a couple of things for the inspiration. But 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.

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

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 2023 earnings. Have a good day.

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