Categories Earnings Call Transcripts, Energy

Transocean Ltd (RIG) Q1 2023 Earnings Call Transcript

Transocean Ltd Earnings Call - Final Transcript

Transocean Ltd (NYSE:RIG) Q1 2023 Earnings Call dated May. 02, 2023.

Corporate Participants:

Alison Johnson — Senior Manager, Investor Relations

Jeremy D. Thigpen — Chief Executive Officer

Mark Mey — EVP and Chief Financial Officer

Roddie Mackenzie — EVP and Chief Commercial Officer

Keelan Adamson — President and Chief Operating Officer

Analysts:

James West — Evercore ISI — Analyst

Thomas Johnson — Morgan Stanley — Analyst

Eddie Kim — Barclays — Analyst

David Smith — Pickering Energy Partners — Analyst

Kurt Hallead — The Benchmark Company — Analyst

Fredrik Stene — Clarksons Platou Securities — Analyst

Presentation:

Operator

Good day, everyone, and welcome to Q1 2023 Transocean’s Earnings Call. At this time, all participants are in a listen-only mode. Later, you will have an opportunity to ask questions during the question-and-answer session. [Operator Instructions] Please note, this call is being recorded.

It is now my pleasure to turn today’s program over to Alison Johnson, Director of Investor Relations. Please go ahead.

Alison Johnson — Senior Manager, Investor Relations

Thank you, Gretchen. Good morning and welcome to Transocean’s first quarter 2023 earnings conference call. A copy of our press release covering financial results along with supporting statements and schedules, including reconciliations and disclosures regarding non-GAAP financial measures, are posted on our website at deepwater.com.

Joining me on this morning’s call are Jeremy Thigpen, Chief Executive Officer; Keelan Adamson, President and Chief Operating Officer; Mark Mey, Executive Vice President and Chief Financial Officer; and Roddie MacKenzie, Executive Vice President and Chief Commercial Officer.

During the course of this call, Transocean management may make certain forward-looking statements regarding various matters related to our business and Company that are not historical facts. Such statements are based upon current expectations and certain assumptions and therefore are subject to certain risks and uncertainties.

Many factors could cause actual results to differ materially. Please refer to our SEC filings for our forward-looking statements and for more information regarding certain risks and uncertainties that could impact our future results. Also, please note that the Company undertakes no duty to update or revise forward-looking statements.

Following Jeremy and Mark’s prepared comments, we will conduct a question-and-answer session with our team. During this time, to give more participants an opportunity to speak, please limit yourself to one initial question and one follow-up.

Thank you very much. I’ll now turn the call over to Jeremy.

Jeremy D. Thigpen — Chief Executive Officer

Thank you, Allison, and welcome to our employees, customers, investors and analysts participating on today’s call. As reported in yesterday’s earnings release, for the first quarter Transocean delivered adjusted EBITDA of $217 million on $667 million in adjusted contract drilling revenues, resulting in an adjusted EBITDA margin of approximately 33%. Our overall performance was supported by superb revenue efficiency of nearly 98% and is representative of our commitment to operational excellence.

During the quarter, we booked nearly $900 million of contract backlog, disrupting the first quarter lull observed in years past. In fact, this is more than double the backlog added in the first quarter of 2022 and more than 7 times what we added in the first quarter of 2021. We believe this is another clear indication of the sustainability of this constructive market environment, particularly in light of the record backlog we booked last year.

Turning to the individual fixtures, in Lebanon the Transocean Barents was awarded a one-well contract with Total Energies at a rate of $365,000 per day. The approximately 65-day contract is expected to commence in direct continuation of the rig’s current program and provide for up to three option wells at rates between $375,000 per day and $390,000 per day.

As discussed on our fourth quarter 2022 earnings call, in January, the KG2 was awarded a 910-day contract in Brazil at approximately $439,000 per day, including integrated services. The contrast — contract is expected to start in the third quarter of this year.

In Australia, the Transocean Endurance was awarded a multi-well contract for plug and abandonment work with an independent operator at a rate of $380,000 per day. The contract also provides for up to five option periods, the first of which has already been exercised at the same dayrate. The remaining four options are at a rate of $390,000 per day.

The contract is expected to commence in January of 2024, and including the exercise option, the term work now extends through February 2025. If all options are exercised, the rig may remain in Australia through at least the fourth quarter of 2025.

On the Norwegian Continental Shelf, the Transocean Enabler was awarded a 19-well contract with Equinor for work on the Johan Castberg field in the Barents Sea at $377,000 per day, as adjusted for currency exchange rates. The contract which is expected to commence in April of 2024 also provides for up to eight optional wells at an $420,000 per day.

Also in Norway, the Transocean Courage was awarded a 9-well contract with Equinor at a rate of $350,000 per day, as adjusted for currency exchange rate. The contract is expected to start in direct continuation of the rig’s current program.

And finally in Norway, Wintershall Dea exercised four one-well options on the Transocean Norge at rates of $338,000 per day, $358,000 per day, $358,000 per day and $408,000 per day respectively, again as adjusted for currency exchange rates.

Following our latest fleet status report, Wintershall Dea exercised a fifth option well at $358,000 per day, keeping the rig working through the third quarter of 2024. Also subsequent to our latest fleet status report, the Transocean Endurance was awarded a two-well contract in Norway at a rate of $385,000 per day. The contract is expected to commence in July 2023.

These harsh environment fixtures in the KG2 award complement the prolific ultra-deepwater pictures we announced in the second half of 2020 and keep us on track to deliver yet another strong year of backlog additions. Moreover, these harsh environment fixtures highlight the predicted tightness in the supply of higher specification, harsh environment semi-submersibles that we’ve anticipated for some time now.

Of note, the Endurance of the sixth semi-submersible to depart in the Norwegian Continental Shelf in the past 18 months, joining most recently the Transocean Barents, which is now operating in the UK.

With the departure of the Endurance, there are now just 13 active semi-submersibles remaining in Norway that have the certifications required to participate in petroleum operations, and we currently expect at least two more rigs to leave the region within the next 18 months.

As we’ve discussed on previous calls, demand for rigs capable of drilling in harsh environment is no longer solely dependent upon geographic regions that have historically utilized harsh environment rigs. Rather, demand is increasingly coming from other areas, including Australia, the Mediterranean and Namibia.

As we see multiple upcoming long-term developments on the horizon in Norway, the departure of these assets in the region is meaningful. If demand continues to materialize as we expect, by the end of 2024, we anticipate that future projects in Norway will require several of these assets to return and to lure them back, significant mobilization fees and higher day rates may be required.

Perhaps the most interesting new market for our harsh — high-specification harsh environment semis is Australia. With numerous programs planned for overlapping operational windows, there appears to be strong competition among operators to secure the best and most capable rigs. As a result, we are observing an increased willingness from our customer base to pay higher mobilization and other contract preparation costs. And if current tenders proceed as expected, we could see one or two new contract awards in Australia by the end of the second-quarter.

Turning to the benign environment rig market, over the last year we’ve observed a marked increase in dayrates for ultra-deepwater drillships, which are now predominantly between $400,000 a day to $450,000 per day across the global fleet. We believe this demonstrates a more widespread understanding by all market participants of current market rates.

Sixth and seventh gen drillship utilization remains at nearly 100%. We expect these utilization levels will be sustained as drillship demand is anticipated to rise throughout 2023, and we believe that as a result dayrate will continue to trend upward, especially for the higher specification ultra-deepwater fleet. In fact, by the end of the year, we expect the leading-edge rates to exceed $500,000 per day.

Additionally, we have recently observed a change in the behavior of several of our customers due to the recognition of the increasing scarcity of high specification assets. The shift is occurring mostly behind the scenes through direct inquiry and negotiations, as they seek to secure rigs for longer terms, in some cases in excess of three years. We anticipate this trend will continue for certain customers, as access to available desirable rigs becomes more difficult.

Looking closer at each region, based on current activity and the open and planned Petrobras tenders, we believe Brazil will continue to be a large consumer of available rig supply. We anticipate Petrobras will secure six floaters or seven floaters under the pool two and Buzios tenders, including up to three from outside the region. If these awards materialize as expected, access to active and warm-stacked rigs for use in other regions will be further constrained, likely resulting an increasingly favorable contract terms for qualified floaters.

This has already occurred in India following the award of the KG2 under the Petrobras pool tender in early January. We believe that the KG2’s departure from the Far East further highlights the limited available local supply of assets to meet the requirements of upcoming drilling campaigns, such as ONGC’s two 21-month opportunities in India. Consequently, we make the assets mobilize from other regions for this work.

And in West Africa and the Mediterranean, floater demand is expected to trend upward over the next 18 months with multi-year programs expected in Angola, Egypt and Cyprus. Additionally, incremental work is emerging in Namibia, following recent discoveries by both Shell and Total Energies in the Orange Basin.

Activity in the US Gulf of Mexico has kept regional supply and demand largely in balance over the last several quarters. We’re highly encouraged by the results of the lease sale concluded in late March in which the number of deepwater blocks receiving bids increased by 30% from the last lead-sale held in 2021. We anticipate the region will continue to have strong activity for the foreseeable future.

Year-to-date 34 rig-years have been awarded for the global floater fleet as compared to 22 rig-years this time last year. The quantity of programs awarded with a duration of one or more years has also increased, with 11 awarded year-to-date, up from five last year.

The outlook remains strong for the foreseeable future, as over 80 rig-years of work are expected to be awarded in the next 18 months. In fact, industry analyst reports estimate the offshore sector will experience its highest growth in more than a decade, with according to Rystad Energy, more than $200 billion of new project investments during the next two years, with offshore activity comprising nearly 70% of all sanctioned conventional hydrocarbons in 2023 and 2024.

As demand continues to improve, we want to show that Transocean is differentiated from our competitors by providing the highest value for our customers and developing and deploying innovative technologies that further enhance our already safe, reliable and efficient operations.

Just last month, utilizing a combination of various automation technologies, which we previously deployed within our fleet, the Transocean Encourage drilled an entire whole section for 21 consecutive hours in a fully automated mode. This achievement is an important milestone for automation technologies. We believe automation will further improve our operational performance, improving the quality and consistency over the wells we drill for our customers, further enhancing the safety of our personnel while also reducing emissions.

As we continue to deploy automation technologies, we plan to aggregate and analyze this data to gain new insights in the performance of our equipment and processes to improve our overall operations. Congratulations to our team in Norway for this significant accomplishment.

As we progress further into this upcycle, we will continue to deploy our portfolio of high specification, ultra-deepwater and harsh environment rigs to maximize value for our shareholders. Throughout the downturn, we practiced a thoughtful approach to contracting our assets and place the right rig on the right opportunity at the right time. We utilize different asset classes and we’re patient so as not to lock up our best assets on long-term low dayrate contracts. We continue to believe this is the correct approach. And moving forward, we will continue to remain disciplined when contracting our fleet.

With 23 total cold-stacked assets, we have the most operational leverage within our peer group and significant upside potential in a rising market, particularly given the quality of our assets. There are only 13 remaining sixth and seventh generation cold-stacked drillships in the industry and eight are in our fleet. Three of these, the Athena, Apollo and Melos, are seventh generation ultra-deepwater drillships that are well preserved in a relatively mild climate offshore Greece.

We expect the economics of reactivations will be cost advantageous as compared to acquiring a stranded newbuild and preparing it for an initial contract. Recently stated newbuild purchases suggest between $200 million and $250 million to acquire the asset plus the cost to reactivate versus our current estimate of $75 million to a $125 million to reactivate one of our existing cold-stacked rigs.

In summary, our outlook remains unambiguously optimistic, reinforced by increased market tightness in various regions around the world and the continued upward trajectory of day rates. Our industry-leading backlog increased for the fourth consecutive quarter to currently about $8.6 billion. Additionally, the average dayrate on our working benign environment rig fleet is beginning to

Reflect the high-quality backlog we booked over the last 18 months and it’s projected across the $400,000 per day mark later this year. As more of our rig transition to higher dayrate contracts, we will begin to utilize cash generated from our fleet to fulfill our commitment to our broader deleveraging efforts.

Our focus remains on delivering safe, reliable and efficient operations. With our strong year-to-date fleet uptime and revenue efficiency of nearly 98%, we continue to take positive steps toward ultimately strengthening our balance sheet and generating value for our shareholders.

I’ll now turn the call over to Mark.

Mark Mey — EVP and Chief Financial Officer

Thank you, Jeremy, and good day to all. During today’s call, I will briefly recap our first quarter results, then provide guidance for the second quarter as well as an update on our expectations for the full year 2023 and our liquidity forecast through the end of 2023.

As-reported in our press release, which includes additional details on our results, for the first-quarter of 2023, we reported a net loss attributable to controlling interest of $455 million, $0.64 per diluted share. After certain adjustments, as stated in yesterday’s press release, we reported adjusted net loss of $275 million. During the quarter, we generated adjusted EBITDA of $217 million.

Looking closer at our results, during the first quarter, we delivered adjusted contract drilling revenues of $667 million at an average day rate was $364,000. This is above our previous guidance, mainly due to strong bonus conversion on the Conqueror, Endurance and Spitsbergen, higher-than-expected revenue recharge and earlier than forecasted commencement of operations for the DD3.

Operating and maintenance expense for the first quarter was $409 million. This is below our guidance, reflecting the delay of in-service maintenance on our working fleet and other service maintenance on rigs that we’re preparing for contracts commencing later in 2023, partially offset by increased costs related to the early commencement of operations for the DD3.

Turning to the cash flow and balance sheet, cash flow from operations was a negative $47 million, resulting from lower collections from customers, reflective of reduced revenue due to certain risks from P&A contracts during the previous quarter, disbursements incurred preparing several rigs for our next contracts and the timing of tax and interest payments.

Our free cash flow of negative $128 million in the first quarter reflects the contract preparations above and $81 million of capital expenditures, which are largely related to our eighth generation drillships, the Deepwater Atlas and Deepwater Titan.

We ended the first quarter with total liquidity of approximately $1.7 billion, including unrestricted cash and cash equivalents of approximately $747 million, approximately $175 million of restricted cash for debt service and $774 million from our undrawn revolving credit facility.

I will now provide an update on our expectations for our second quarter and for full year financial performance. As always, our guidance would reflect only contract-related rig reactivations and/or upgrades.

For the second quarter of 2023, we expect adjusted contract drilling revenues of approximately $735 million based upon an average fleet-wide revenue efficiency of 96.5%. This quarter-over-quarter increase is primarily attributable to a full-quarter utilization of the Transocean Barents and DD3, which started contracts in the prior quarter and the contract commencement of the Deepwater Titan and Transocean Norge during the second quarter, partially offset by in-between contract idle time for the Transocean Endurance in Norway.

For the full-year 2023, I am reiterating prior guidance of adjusted contract drilling revenues of between $2.9 billion and $3 billion. We expect second-quarter O&M expense to be approximately $490 million. This quarter-over-quarter increase is primarily due to higher utilization, increased other service maintenance incurred on the KG2 and Deepwater Orion in preparation for the contracts with Petrobras and the timing of in-service maintenance activities. I expect full-year 2023 operating and maintenance expense remains unchanged from our fourth-quarter call at approximately $1.9 billion.

We continue to see some upward pressure on salaries and wages, and vendor pricing. Absorbed inflation appears to have [Indecipherable] around 6%, which is reflected in our guidance. As a reminder, the influence of inflation on our maintenance cost is largely tempered by our long-term K agreements with our largest suppliers.

We also have protection on the revenue side, as our legacy long-term contracts with our customers contain cost adjustment mechanisms. For ongoing and future contract negotiations, we will continue to insist on provisions to protect our margins against cost increases in dayrate and terms as appropriate.

We expect G&A expense for the second quarter to be approximately $49 million, and around $200 million for the full year. Net interest for the second quarter is forecasted to be approximately $118 million, including capitalized interest of approximately $12 million and excluding any non-cash fair-value adjustment of the bifurcated exchange feature embedded in our exchangeable bonds issued in September of 2023 [Phonetic].

For the full year, we estimate net interest expense of approximately $479 million, including capitalized interest of approximately $31 million and excluding the non-cash loss of $133 million mentioned above.

Capital expenditures, including capitalized interest, for the second quarter are forecast to be approximately $100 million, which includes approximately $70 million for newbuild capex and approximately $30 million sustaining and contract preparation related capex.

Cash taxes are expected to be $15 million for the second quarter and $35 million for the year. As expected — our expected liquidity in December 2023 is projected to be between $1.2 billion and $1.3 billion, reflecting our revenue and cost guidance and including the $600 million capacity of our revolving credit facility and restricted cash of $215 million, which is primarily reserve for debt service. This liquidity forecast includes 2023 capex expectations of $285 million, of which $167 million relate to our newbuilds and $118 million for sustaining and contract preparation capex.

We continue to focus on deleveraging our balance sheet and reducing interest expense, and simplifying our capital structure and maintaining financial flexibility. As I discussed in the fourth quarter call — earnings call, we’ve addressed substantially all material maturities until 2025. Consistent with our deleveraging objectives, one of our large holders of our exchangeable bonds recently agreed to convert its exchangeable bonds to equity, reducing our debt by $213 million. We may look to address a portion of the remaining $618 million of outstanding exchangeable bonds, should other economic and prudent opportunities present themselves.

Given our current contracting activity and strong dayrate environments, we expect to utilize available free-cash flow to continue reducing debt and interest expense. Concurrently, we will look to continue to evaluate opportunistic financing transactions to address medium-term maturities and optimize the balance sheet and reduce the cost of debt.

This concludes my prepared comments. Now, I will turn it over to Allison.

Alison Johnson — Senior Manager, Investor Relations

Thanks, Mark. Gretchen, 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.

Questions and Answers:

Operator

[Operator Instructions] We’ll take our first question from James West from Evercore ISI.

James West — Evercore ISI — Analyst

Good morning, guys.

Jeremy D. Thigpen — Chief Executive Officer

Good morning, James.

James West — Evercore ISI — Analyst

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

Jeremy D. Thigpen — Chief Executive Officer

Okay, I’ll hand it over to Roddie.

Roddie Mackenzie — EVP and Chief Commercial Officer

Yeah, no problem. Yes, so I think that would be the case, yes, you would see that come in next year. And there’s been a lot of discussion about this magical $500,000 mark, but I [Speech Overlap] a couple of statistics on that just real quickly. We don’t know what our competitors bid except when they bid into public tenders. So, we use the Petrobras tenders in Brazil as an example.

And the pool number one tender that happened last year, there was only two rigs were bid above the $500,000 a day. And the pool 2 tender that just completed this week, it was the nine, so that’s like a marked change in that, right, because you see lots of folks across the board saying that the expectation is it will be this year for the 500s and I’ve seen a couple of projections this year will be mid-500s by 2025.

James West — Evercore ISI — Analyst

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

Jeremy D. Thigpen — Chief Executive Officer

Yeah, thanks, James. Good question. We have seen a lot of consolidation in this space. We’ve dramatically improved industry structure for offshore drillers, far fewer players, far fewer assets, fewer retirements. So, it’s a much — far more disciplined behavior as a result. So, we’re going-in the right direction.

I think there’s still room for more consolidation, especially now that most of our competitors have gone through Chapter 11 and have emerged with clean balance sheets. I think — and all of us have digested our own acquisitions over the course of the last couple of years. So, I would expect to see some more consolidation through this year.

We certainly look at every opportunity out there and we get pitched every opportunity that’s out there. Mark is smiling at me. And so, we’ll continue to look. But again, we’re going to kind of follow the same blueprint we’ve followed so far.

It’s got to be ultra-deepwater and harsh environment high-specification assets, so fleet matters. And we can’t do anything to compromise the balance sheet. And so, we looked through those — that lens really at every strategic opportunity.

James West — Evercore ISI — Analyst

Okay, got it, thanks. Thanks, guys.

Jeremy D. Thigpen — Chief Executive Officer

Thanks, James.

Operator

Our next question comes from Thomas Jonsson from Morgan Stanley.

Thomas Johnson — Morgan Stanley — Analyst

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

Roddie Mackenzie — EVP and Chief Commercial Officer

Yeah, I think I’ll take that one. So, yeah, as we think about another kind of 8 rigs to 10 rigs potentially leaving Norway, that pretty much leaves you a fleet of maybe 12 rigs or 13 rigs. What we see in the expected demand in the 2024 into 2025 time frame is about 15 rigs to 18 rigs. So, you’re suggesting that there’s probably a deficit of 4 rigs to 6 rigs in that time frame. Thus, that, in my view is going to have a step-change in dayrates, right.

I mean, we’ve seen that we’re consistently now and in the upper 300s. I would expect that the next fixtures are going to be solidly in the fours and who knows where that may lead to, but certainly, we’re at this kind of 13 AOC compliant floaters in Norway. Just note that, that is historically the lowest number ever.

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

Jeremy D. Thigpen — Chief Executive Officer

And Thomas, the other thing I would mention in addition to having dayrates firmly in the 400s if not higher, customers are paying mobilization fees as well upfront. So, you layer that in as well and it looks pretty lucrative for that market.

Thomas Johnson — Morgan Stanley — Analyst

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

Jeremy D. Thigpen — Chief Executive Officer

Yeah, Keelan, could you take that one?

Keelan Adamson — President and Chief Operating Officer

Yeah, Thomas, I think our guidance on that still hasn’t changed since the last time. We’re still looking at 12 months — anywhere between 12 months and 18 months to get a cold-stacked reactivation effective door to door into operation, largely probably around 15 months.

So, the supply-chain side is improving as capacity is getting better across the supply chain. But we’re still facing some long-lead issues, particularly on heavy steel forgings and obviously on electronic components, that there’s a reliability probably issue in terms of delivery in the supply chain from Europe in that regard. But I think we’re still seeing 12-months to 18-month range on our cold-stacked reactivations at this time.

Thomas Johnson — Morgan Stanley — Analyst

Great, thank you very much. I’ll turn it back now.

Operator

And our next question comes from Eddie Kim from Barclays.

Eddie Kim — Barclays — Analyst

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

Roddie Mackenzie — EVP and Chief Commercial Officer

Yeah, sure. Yes, so obviously I can’t tip my hand to the precise opportunities we’re exploring, but yes, we’re in active dialog on both the rigs for different things. And we expect that fairly shortly we’ll be able to add some more backlog to those.

And kind of as a reminder on that contracting philosophy, we are purposefully keeping a couple of rigs available in the near term to take advantage of this improving market for us. So, you did see — and thank you for noting the prolific contracting that we did on many of the assets over the last couple of quarters. So, we maintain that balance of, yes, it’s nice to have the majority of the fleet on long-term contracts, but we certainly also want to be able to capture the upside in this improving market.

Eddie Kim — Barclays — Analyst

Got it, understood. So, a bit of a negotiate — just kind of strategic negotiation going on there. Understood. My follow-up is just on kind of the pace of reactivations we’ve been seeing. There has been one major contract that has been reactivating a number of cold-stacked floaters, as I know you’re well aware.

Does the pace of reactivations concern you at all in terms of the dayrate progression, your expectation that your contract announced with a five handle by end of year would suggest you’re not very concerned at all. But any thoughts here will be appreciated.

Jeremy D. Thigpen — Chief Executive Officer

Go ahead.

Keelan Adamson — President and Chief Operating Officer

Yes, so if you look at the results from the Petrobras contracts was announced last Friday, the two rigs at one, the first one, were both in the mid-fours and they are stranded newbuilds. So, it’s very similar to a reactivation of a cold-stacked rig. These are rigs that are coming out. And as Jeremy mentioned in his prepared comments, you’re paying about $200 million for these rigs, then you’re spending another $150-ish million to bring those rigs to market.

So, to see that those investors are bidding in the mid-fours, I don’t see them dragging rigs down at all. I think it was a very good high watermark for Brazil. So, I don’t think that’s a challenge for us at this stage.

Eddie Kim — Barclays — Analyst

Got it, understood. Thank you. I’ll turn it back.

Roddie Mackenzie — EVP and Chief Commercial Officer

Yeah, actually, me, I don’t talk about the — the interesting thing against pool one versus pool two which is kind of 7 months of apart is we saw a 17% increase in the average bid rate, so you kind of went from $350,000 a day average to $408,000 a day, so — I mean that’s pretty substantial increase in just a few months, $58,000 [Phonetic] a day on average.

Operator

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

David Smith — Pickering Energy Partners — Analyst

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

Jeremy D. Thigpen — Chief Executive Officer

Good morning, David.

David Smith — Pickering Energy Partners — Analyst

So, few interesting agreements you all announced in the past 3 months, first dedicating the Olympia up for subsidy mineral exploration and then the second, converting up to two floating vessels for floating wind turbine installation. And I just wanted to make sure I’m right to understand the two vessels will be coming from your stacked fleet?

Roddie Mackenzie — EVP and Chief Commercial Officer

That’s correct, yes.

David Smith — Pickering Energy Partners — Analyst

So, I was just hoping to get your thoughts on removing up to three stacked rigs for alternative uses. And how you think about the trade-off for increasing exposure to the energy transition versus the option value of eventually having — the last incremental capacity for newbuilds would be needed. And maybe if you’re considering dedicating anymore stacked rigs for alternative uses.

Roddie Mackenzie — EVP and Chief Commercial Officer

Yeah, I’ll take that one. So, look, I mean, if we do consider using some of our stacked fleet for these opportunities, the logic is pretty simple. We basically have a good crop of available cold-stacked units for writing the upside of this increased activity, as we expect floaters to go from kind of like the 140 level committed rigs to up to 150 rigs.

We’ve got plenty of room to grow on the on the drilling side of the business, but the assets that we might consider for something like this would happen to be the lowest specification of our stacked assets. So, it’s really a very interesting way to get into the energy expansion to be not just one-dimensional in our outlook, but also to take assets that otherwise might be stacked for many, many more years and making good use of them in the near term. So, I think it’s extremely interesting opportunity and a smart use of our of our fleet.

Mark Mey — EVP and Chief Financial Officer

And let me just add to that. We’ve been talking about the pace of reactivations for the industry and for Transocean specifically. We believe given the current constraints, especially in the supply chain side, it’s about two a year. So, if we have 11 and you take those two out, now it’s nine, that’s 4.5 years of reactivations.

Do we believe the cycle is going to last 4.5 years, 5 years, 6 years? Not so sure. We do believe it’s going to last 3 years. So, we certainly can get through the majority of our stacked fleet by reactivating them. And if dayrates support reactivating the rest of it, we’ll clearly do that. But we’re targeting these rigs into markets that we believe will generate returns for our shareholders over time as well as what you said, helping us as a company to move into energy expansion little more forcefully.

David Smith — Pickering Energy Partners — Analyst

All right, thank you. That’s all I had.

Operator

Our next question comes from Kurt Hallead from Benchmark.

Kurt Hallead — The Benchmark Company — Analyst

Hey, good morning.

Jeremy D. Thigpen — Chief Executive Officer

Good morning, Kurt.

Kurt Hallead — The Benchmark Company — Analyst

So, Jeremy, I think as you referenced here earlier, there’s something along the lines of 13 cold-stacked rigs. I think on prior calls, you indicated that Brazil might see incremental rig demand of order of magnitude 20 rigs over the next, I don’t know, 2-year to 3-year period I think is what the time frame was.

And I just wonder if you could give us an update on overall demand dynamics as you see it, maybe updated relative to how you saw it versus the prior call. And I guess the context is it seems to me that Brazil could absorb the vast majority of the available idle capacity in the market, leaving West Africa and other areas scrambling to compete for what’s left. So, just want to get your perspective on that.

Roddie Mackenzie — EVP and Chief Commercial Officer

Yes, sure. So, yeah, with regards to Brazil, yes, if you think about just a larger context before you go into the details of that, the drillship market is effectively 100% utilized at the moment for assets that are available. Yes, certainly, Brazil has more to add. There is no doubt, so I think you’re going to see — as Mark pointed out, there are — two stranded assets are going to come to satisfy the cold to tender [Phonetic].

We think there’s still plenty more cold-stacked potential for satisfying Buzios and other tenders that may also come out. So, yeah, Brazil really is putting a draw on pretty much everything that’s available. But as we go around the world and we think about the different markets, I mean every market is up. If you view it on a 12-month basis, every market is up. So, that simply means that we’re going to continue to book the rigs that are coming available and have to reactivate other ones.

So again, as I said, the kinds of the numbers are supposed to be heading to 150 active floaters as we get into 2024. That would suggest that we’ve got 10 to ad. That’s a total order, but certainly in good shape for that. And I think as I have articulated many times, we’ve got 12 cold-stacked assets at the moment. We could dedicate a couple of those to alternate purposes. But will we also be optimistic about reactivating a couple of those over the next year or so into new opportunities.

Kurt Hallead — The Benchmark Company — Analyst

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

Roddie Mackenzie — EVP and Chief Commercial Officer

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

Kurt Hallead — The Benchmark Company — Analyst

Okay, great. I appreciate the color. Thank you.

Jeremy D. Thigpen — Chief Executive Officer

Thanks, Greg.

Operator

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

Fredrik Stene — Clarksons Platou Securities — Analyst

Hey, guys, thank you for taking my question. Hopefully, you can hear me okay. So I have again, two questions for you. I would like to add a bit to the cold-stacked asset discussion here. As you mentioned in your prepared remarks, you have the majority really of the cold-stacked assets here. And one thing is talking about where these assets can go and you can absorb them better.

But I think another part or dimension of that discussion is the strategy in the way of how to employ them because it seems some of your peers are taking out their spec capacity at lower rates or being more aggressive in taking out their — that capacity. But at some point I think that could leave you as the only price that — really of incremental capacity into the floater market. But that also gives you a bit more risk on your side.

So, do you have any color or thinking about how you’re approaching that right now, or if the way you’re approaching it has changed as we’ve seen rate levels move higher?

Jeremy D. Thigpen — Chief Executive Officer

Yeah, I don’t think our approach has changed. I think we’ve been pretty clear that the customer has to pay for the reactivation. And so, we’re going to continue to follow that strategy I think going-forward — I know, going forward.

So, we’re happy to continue to push rates on our existing fleet as they become available. And then when the customer is willing to pay for reactivation, we’ll certainly do it.

Roddie Mackenzie — EVP and Chief Commercial Officer

Yeah. No — and I think as we think about what it costs for those rigs to remain stacked, it’s really de minimis. So, choosing the right time and choosing the right contract is really what the strategy is about and showing some patience, not — we certainly do not value utilization over EBITDA generation. So, I think most of our competitors see it that way. Maybe one or two don’t, but we’ll certainly continue to push that mantra. We will not reactivate on spec.

Fredrik Stene — Clarksons Platou Securities — Analyst

Perfect. And the last one, turning to the harsh environment markets again, I think you’ve — you said that you’d like to — or you’d prefer to keep your assets in Norway or at least the Norway compliant assets, but obviously you and some of your competitors have now started to take those assets out. Have there been any change in that preference for your side that you’re seeing that the economics are just too good to kind of give up the optionality of keeping the assets in Norway or do you think that you have a balanced approach to that, some optionality in Norway and then some hard cash in other parts of the world right now?

Jeremy D. Thigpen — Chief Executive Officer

Go ahead.

Roddie Mackenzie — EVP and Chief Commercial Officer

Yeah, I’m just going to say, no, I mean it’s pretty simple. I think we’ve showed an exceptional amount of patients over the last few years of keeping rigs in Norway. We’ve had rigs idle in Norway for some time. We’ve talked to kind of all the major customers about this, and been, I would say, very competitive in our attempt to keep the rigs busy in Norway, especially during 2019, 2020 and so on.

But now, we’re really at the point that the demand elsewhere is so substantial. It’s always our preference to keep the rigs where they are. There’s no question about that. But the economic challenge is now overwhelming when you compare how accretive the contracts are elsewhere.

Fredrik Stene — Clarksons Platou Securities — Analyst

All right, thank you so much. That’s all from me. Have a good day.

Jeremy D. Thigpen — Chief Executive Officer

Thanks, Fredrik, you too.

Operator

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

Alison Johnson — Senior Manager, Investor Relations

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

Operator

[Operator Closing Remarks]

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