Earnings Call Transcript - RIG Q2 2023

Alison Johnson, Director of Investor Relations

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, CEO

Thank you, Alison, and welcome to our employees, customers, investors, and analysts on today’s call. In our latest lease status report, we noted an addition of $1.2 billion in backlog over the past several months, raising our total backlog to $9.2 billion as of July 19. This marks our fifth consecutive quarter of adding more backlog than we consumed, leading to an increase of approximately $3 billion since April 2022. Our ultra-deepwater fleet's average day rate has significantly risen during this time. In the second quarter of 2023, our average day rate reached around $363,000 per day compared to $312,000 per day in the same quarter of 2022. By the second quarter of 2024, we expect this to approach $433,000 per day based on existing backlog. We’ve had an exciting start to the year, with rising average day rates for our ultra-deepwater fleet and a rapid tightening in the high-specification harsh environment semisubmersible market. According to Westwood Global Energy Group, this asset class is now fully utilized at 100% for the first time since 2014. We previously highlighted the trend of high-specification semisubmersibles moving out of Norway in our third quarter 2020 earnings call, predicting a shortage in the Norwegian market by 2024. However, the speed and scale of this migration exceeded our expectations. Three of our rigs—Transocean Barents, Transocean Equinox, and Transocean Endurance—are either moving or preparing to move to new markets, including Australia and Lebanon, with further opportunities ahead. Demand for the Norwegian market might reach nearly 20 rigs by 2025, but only 12 high-specification harsh environment semisubmersibles are expected to remain in Norway during that time. Consequently, day rates for these semisubmersibles have risen significantly since the start of the year, nearing $500,000 per day for firm work, with certain priced options already exceeding this amount. Transitioning to recent fixtures that have contributed to this market improvement, the Transocean Barents was awarded a one-well contract with Total Energies in Lebanon at a rate of $365,000 per day. The customer has since exercised the first option for work in the East Mediterranean Sea at $370,000 per day, extending the firm duration to an estimated 167 days. There are two more options at rates varying from $350,000 to $390,000 per day depending on the work location. In Australia, the Transocean Equinox secured a five-well contract from a major operator at $455,000 per day, excluding mobilization and demobilization, starting in the first quarter of 2024. Additionally, it was awarded a 16-well contract at $485,000 per day in Australia, also excluding those costs, allowing for options at rates from $485,000 to $540,000 per day. This contract could have the rig operating in Australia until 2028 if all options are exercised. As a reminder, the Equinox is the second of our CAT D semisubmersibles to begin operations in Australia next quarter. The Transocean Endurance, set to start in January, will operate at a rate of $380,000 per day. I want to pause and highlight the fact that in just three months, we raised rates for harsh environment semisubmersibles in Australia by over $100,000 per day, alongside a significant rise in contract duration. In Norway, Wintershall Dea has exercised a one-well option on the Transocean Norge at $365,000 per day, with three additional options at $420,000 per day. This work minimizes previously anticipated idle time during the contract. Additionally, six one-well options were exercised on the Transocean Encourage at $464,000 per day, extending the firm term an additional 370 days to February 2026. For our ultra-deepwater rigs, an operator in the U.S. Gulf of Mexico awarded the Deepwater Invictus a 20-day P&A well estimated at $440,000 per day, which will commence as a continuation of the current program. Furthermore, in the Mexican Gulf of Mexico, an independent operator awarded a 1,080-day contract for one of our high-specification seventh-generation ultra-deepwater drillships at $480,000 per day. We will select this rig from either the Deepwater Invictus, Deepwater Thalassa, or Deepwater Proteus, with the contract expected to start between the fourth quarter of 2025 and the second quarter of 2026, allowing flexibility for our asset portfolio, including a semiannual cost adjustment for inflation protection. We are observing a trend of increased customer interest in securing rigs for long-term projects that start further out. This interest is translating into action, as multiple operators are committing to multiyear projects, evidenced by our recent award in Mexico scheduled for as late as 2026. This indicates our customers’ acknowledgment of the scarcity of capable high-specification assets and demonstrates their strength in offshore project commitments, suggesting we are in a long-term up cycle. Contract durations are notably increasing. Year-to-date 2023, the average contract length of drillship awards has risen to 495 days compared to 310 days in 2022, showing a nearly 60% year-over-year increase. The average duration of semisubmersible fixtures has risen about 18% over the same time frame and nearly 150% from 2020. To date, nearly 15,000 drillship days have been awarded in 2023, representing a 134% increase from the same period last year, while nearly 8,500 harsh environment semisubmersible days awarded this year reflect a 72% rise compared to the previous year. Globally, we expect around 81 rig years of work to be awarded across 80 floater programs, suggesting an average duration of about one year, increasing from just seven to eight months 18 months ago. Notably, over a quarter of these programs are designated for exploration and appraisal wells. Although our contracting strategy might require brief periods of inactivity for key rigs to maximize long-term EBITDA and margins, we anticipate the rig market will remain tight, especially for the highest specification ultra-deepwater drillships and harsh environment semisubmersibles. According to Wood Mackenzie's analysis, which is echoed by Schlumberger, approximately 85% of nearly $500 billion in oil and gas investments from 2022 to 2025 yield favorable returns even with oil prices below $50 per barrel, with around $200 billion projected for deepwater projects. Commodity prices have consistently remained above the $50 per barrel mark for more than two years, stabilizing in the mid-$70 to mid-$80 range. Many offshore breakevens are significantly below this threshold, leading us to anticipate approvals for our customers' programs. We are also seeing operators evaluating and increasingly pursuing long-term rig contracts not yet tied to specific projects, a recent market behavior we haven’t encountered in some time, marking an exciting development. As we examine various harsh environment markets, let's turn our attention to the ultra-deepwater region. In the U.S. Gulf of Mexico, customers prefer direct negotiations for contracting, with many discussions centering on multiyear opportunities, some lasting as long as five years, involving fields that require 20,000 psi completions—a capability unique to the Deepwater Titan and Deepwater Atlas. The Titan is contracted through early 2028, and once its current contract concludes in August 2024, the Atlas will be the sole rig equipped for such completions. In Brazil, Petrobras is finalizing two tenders, including the deepwater Qila, with full awards expected by the end of August. The anticipated Petrobras Búzios tender is well underway, with the two combined tenders able to absorb up to seven rigs over the next 15 months, three of which we believe will need to be sourced from outside the region. The momentum continues, as Petrobras recently issued another tender for up to three rigs commencing mid-2025. Equinor is also requesting information for its BMC 33 Block offshore Brazil, aiming for approximately two years of service starting in the second or third quarter of 2026. In West Africa and the Mediterranean, numerous multiyear opportunities are set to start within 18 months, with various operators seeking rigs for projects exceeding five years in duration. Notable multiyear opportunities spread across the region include Shell Nigeria, Azul Energy's two-year tender in Angola, and OMV's tender in the Romanian Black Sea. In India, ONGC's tender is nearing completion, and we anticipate an award for one rig for up to 21 months soon, along with a potential demand for one or two additional rigs within the next year. Looking at our fleet in the second quarter, the Deepwater Titan began its first contract with Chevron on the anchor project in the U.S. Gulf of Mexico. Recently, the Titan 20K BOP was deployed, utilizing the third installed robotic riser system in our fleet, further enhancing operational efficiency and crew safety through automation. The Titan joins its sister ship, the Deepwater Atlas, as one of only two eighth-generation ultra-deepwater drillships worldwide. The rig's 3.4 million pound hoisting system can handle heavier casing strength than any other floating drilling rig, shortening well time and potentially allowing a larger borehole for customer follow-on production. Its 20,000 psi well control equipment opens access to higher-pressure reservoirs, unlocking previously inaccessible projects and providing advantages for both drilling and completion activities. During the quarter, we committed to selling two harsh environment floaters, the Paul B. Lloyd Jr. and the Transocean Leader, since these lower specification assets are best suited to the U.K. North Sea. This move exemplifies our strategy to focus on our high-specification fleet, which is in great demand elsewhere. Upon the sale's completion, we will have 28 ultra-deepwater floaters and eight harsh environment floaters, in addition to our non-controlling interest in Laquila Ventures, which is currently constructing the deepwater Laquila. Our fleet includes 10 of the 14 highest tier drillships globally. We have 11 cold stacked floaters, encompassing 10 ultra-deepwater rigs and one harsh environment semisubmersible. With our active fleet nearing full utilization, we are actively bidding these stacked assets in open tenders and direct negotiations, giving us significant operational leverage over our peers. Only 12 cold stacked sixth and seventh-generation drillships remain, and eight are owned by Transocean. Beyond those, there are just four stranded newbuild rigs in shipyards without known ownership or purchase options. We anticipate that commissioning these stranded rigs will cost two to three times more than reactivating cold-stacked rigs due to initial purchase prices of $200 million to $300 million, alongside preparation costs. Reactivating cold stakes is estimated to range from $75 million to $125 million. Moreover, we do not expect to see newbuild commissions for many years, and if they do occur, timelines for completion will likely stretch three to five years with capital expenditures potentially exceeding $1 billion. In summary, we believe Transocean will remain the preferred supplier for additional ultra-deepwater rig capacity, continuing our disciplined approach when considering contract renewals and reactivations. As we capitalize on the improving offshore market, our fleet's cash flow generating capacity grows stronger. We plan to prioritize capital allocation over the coming years, focusing first on reducing our balance sheet leverage while balancing other priorities such as maintaining our active fleet, reactivating stacked assets as per customer contracts, and deploying new technologies that we’ve successfully developed and tested. Our goal remains maximizing value for our shareholders. We've demonstrated our ability to generate cash flow by optimally utilizing our active fleet while maintaining discipline with our stack fleet. For several years, we’ve effectively emphasized day rates over utilization with our top-tier rigs. For example, our recent contract for the Deepwater Invictus at $480,000 per day exceeds the rate we contracted just two years ago by $220,000 per day, reflecting our contracting strategy. In some circumstances, our favorable backlog position allowed us to strategically opt for higher day rates at the expense of utilization, a critical aspect of maximizing cyclic EBITDA margins. This strategy has been beneficial for Transocean and the industry as a whole. We will continue evaluating opportunities on a case-by-case basis, using our comprehensive portfolio approach to find the right balance of utilization and day rates. In conclusion, we are clearly in a multiyear up cycle, with our customers showing confidence and commitment to their projects while recognizing the constrained supply of high-specification floaters. They are securing rigs well ahead of their programs and locking them in for multiple years. Given Transocean's ownership of the industry's high-specification fleet of ultra-deepwater and harsh environment floaters and our significant ownership of cold stacked sixth and seventh generation rigs, we believe we are optimally positioned to benefit from this up cycle, increasing day rates on our active fleet while remaining disciplined regarding our stacked fleet. Over the past year, we’ve shown we can achieve leading rates and extended contract terms while still growing our backlog. Through the efficient execution of our operations, we aim to convert this industry-leading backlog into cash, allowing us to swiftly reduce our balance sheet leverage and generate sustainable value for our shareholders. Now, I'll turn the call over to Mark.

Mark Mey, CFO

Thank you, Jeremy, and good day to all. During today's call, I will briefly recap our second quarter results and provide guidance for the third quarter and update on our expectations for the full year 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. With certain adjustments as stated in yesterday's press release, we reported an adjusted net loss of $110 million. During the quarter, we generated adjusted EBITDA of $237 million, which translates 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 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 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 expenses 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 new builds 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 fleet status report with 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 the Deepwater Titan, our capital expenditures decline 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 deeply 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, Director of Investor Relations

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.

Kurt Hallead, Analyst

Thank you. Hi, good morning, everybody.

Jeremy Thigpen, CEO

Good morning, Kurt.

Kurt Hallead, Analyst

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, CFO

Yes. Thanks, Kurt. I think year-on-year, we probably see organic increases 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, Analyst

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, Chief Commercial Officer

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 fixtures 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, Analyst

Great. And maybe just one last question. You mentioned, Jeremy, there are 12 cold stacked drill ships in the market, and you own eight of them. In the last conference call, you indicated there is potential demand for around 20 additional rigs over the next couple of years. Are you still anticipating that level of demand?

Jeremy Thigpen, CEO

I'm not sure if we ever mentioned 20, but we are still experiencing very strong demand, and we fully expect to begin reactivating some of our assets in the coming months. If you look at the 12 stacked sixth and seventh generation rigs available, we own eight of them. Among those, three are seventh generation rigs, and Keelan, who is currently away visiting our rigs, found those three rigs to be in excellent condition. He was very impressed with how well they have been preserved, and we anticipate bringing those three rigs back into operation in the near future.

Roddie Mackenzie, Chief Commercial Officer

Yes, I’d like to add that projections from various analysts indicate a shortage of available rigs in 2024 and 2025. For ultra-deepwater, this could mean a deficit of 10 to 20 rigs during that period. Additionally, in the harsh environment sector, we anticipate a shortfall of at least 5 to 10 rigs. Both sectors are showing an upcoming rig deficit starting in 2024. This situation emphasizes the need for our customers to take swift action because reactivating the cold stacked rigs will likely take about 12 months or more. We need to secure contracts soon to meet the upcoming demand in 2024, 2025, and 2026.

Kurt Hallead, Analyst

That's great. Thanks for the call. Appreciate it.

Eddie Kim, Analyst

Hi, good morning.

Jeremy Thigpen, CEO

Good morning, Eddie.

Eddie Kim, Analyst

My question is about the fixed-priced options and their escalating nature that have been secured recently for your fleet, particularly the Equinox with options reaching as high as $540,000 a day by mid-2020. Could you provide some additional insight into the recent negotiations regarding these fixed-price options? Previously, the day rates for these options were generally lower than the firm contracts, but it appears there has been a significant shift in recent months. Any details you could share would be appreciated.

Jeremy Thigpen, CEO

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 will actually be in a position to do the work is kind of the primary driver where you've got fear 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, Analyst

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, CEO

Yes, you will likely see more of it. However, in an up cycle, if there is a strong belief that things will keep moving, then securing fixed price options on rigs may not be advantageous unless those prices are significantly higher than current levels. Therefore, I’m not confident you will see an increase in that, and I actually believe it will be beneficial as the market tightens. We remain flexible on this, but we strive to maintain a strong position with our best assets.

Eddie Kim, Analyst

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, Chief Commercial Officer

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, Analyst

Got it. Great, thank you Roddie? I'll turn it back.

Greg Lewis, Analyst

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, CFO

Yes, Greg, that's not an easy number to provide because if I contrast the Corcovado and Mykonos, those rigs temporarily come out of service in Brazil as they transition between contracts. We think they go through cleaning and then return to operation. This process will only cost us a couple of million dollars, which isn't significant. However, bringing a rig into Brazil for the first time costs between $50 million to $60 million. There isn't a consistent figure as it can vary significantly between these amounts. As Jeremy noted in his prepared remarks, we've estimated the costs for reactivating the cold stack rigs to be between $75 million and $125 million. This means your range is $2 million to $125 million. If I were to provide a normalized number, it would likely be an inaccurate forecast. Therefore, I think you will need to observe the reactivation of rigs, and we will offer guidance on spending at that time. I prefer not to give a normalized figure.

Greg Lewis, Analyst

Alright. It's been positive to see how you've managed the semi market in the North Sea. I'm interested in whether the U.K. government's recognition of your well-performing rigs and high-quality semis, despite low U.K. exposure, might have a broader effect, especially in Norway in the Central and North Sea. Can you discuss the potential impact of this announcement? Looking forward, will we see the effects in 2024, or should we anticipate a greater increase in demand in the latter half of the decade due to the U.K. government's push to encourage more oil and gas drilling in the near term?

Jeremy Thigpen, CEO

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 things affect 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, CFO

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, Chief Commercial Officer

Yes, probably closer to five if not more.

Fredrik Stene, Analyst

Hi Jeremy and team, I hope you are well and had a nice summer. I want to follow up on a few themes that have been partially discussed, starting with the harsh environment market. As you mentioned, there is definitely no shortage in this area. I agree that the pace at which these semis have left Norway has been remarkable. I can imagine that some operators in Norway now have a significant need for them. I was wondering how the discussions compare to those from the third quarter last year. Are they contacting you daily asking for capacity? How are those inquiries being addressed, and how have the discussions evolved over the last six to nine months? Finally, if possible, could you provide a number for the day rate required to bring your rigs back to Norway to assist Equinor and the other companies there?

Jeremy Thigpen, CEO

Things have certainly changed a lot in the past year. If you review our previous earnings call transcripts, you'll see that we clearly communicated our need to secure work for multiple rigs. At that time, if we couldn't find opportunities within our scope, we indicated we would have to seek work elsewhere. While the pace of these changes may surprise some, we have anticipated them. As for bringing rigs back to Norway, we expect that to happen, though it may not be immediate. We have already seen a couple of tenders initiated to secure rigs for extended periods. In the next month or two, you'll find out who has been awarded those contracts, which will be at noticeably higher day rates for longer terms. The rigs will return at a higher day rate that will cover all associated expenses. We also aim to maintain solid EBITDA margins similar to those we achieve overseas to ensure the arrangements are appealing. While we expect some rigs to return, they will do so at increased costs.

Mark Mey, CFO

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, CEO

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 Barents that recently left to see if there's interest in bringing her back.

Fredrik Stene, Analyst

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, CEO

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, Analyst

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, CEO

We are currently in discussions and engaging in tenders for a few opportunities related to the Inspiration. However, it's important to note that this unit has lower specifications, so we will approach this carefully. We are not in a rush to make any decisions at this time, but there are a few promising developments on the horizon, so please stay tuned.

Fredrik Stene, Analyst

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

Jeremy Thigpen, CEO

Thank you, Tim.

Alison Johnson, Director of Investor Relations

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, Operator

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