Categories Earnings Call Transcripts, Energy

Transocean Ltd. (RIG) Q4 2021 Earnings Call Transcript

RIG Earnings Call - Final Transcript

Transocean Ltd.  (NYSE: RIG) Q4 2021 earnings call dated Feb. 23, 2022

Corporate Participants:

Cale Dillingham — Treasury Lead Analyst

Jeremy D. Thigpen — Chief Executive Officer

Mark Mey — Executive Vice President and Chief Financial Officer

Roddie Mackenzie — Executive Vice President and Chief Commercial Officer

Analysts:

Thomas Johnson — Morgan Stanley — Analyst

Karl Blunden — Goldman Sachs — Analyst

Samantha Hoh — Evercore Group — Analyst

Aaron Rosenthal — J.P. Morgan — Analyst

Presentation:

Operator

Good day, and welcome to the Q4 2021 Transocean Earnings Conference Call. Today’s conference is being recorded.

At this time, I would like to turn the conference over to Mr. Cale Dillingham. Please go ahead, sir.

Cale Dillingham — Treasury Lead Analyst

Thank you, Cynthia. Good morning, and welcome to Transocean’s fourth quarter 2021 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, Cale, and welcome to our employees, customers, investors, and analysts participating in today’s call. As all of you are acutely aware, the past seven years have been unbelievably challenging for our industry. And with the global spread of multiple variants of the COVID-19 virus, the past couple of years have exacerbated those challenges and introduced complexities and uncertainties never before experienced in offshore drilling. Through it all, due to the resilience, commitment, and expertise of the Transocean team, we have delivered the same consistent, high level of service that our customers have grown to expect from us by proactively adapting to unique circumstances of each customer, project, and operating jurisdiction.

We’ve also been able to accomplish extraordinary results in the face of dynamic environments by taking the necessary actions to ensure the safety of our employees and all parties aboard our rigs who help to generate our superior operational results. Although the pandemic has presented unique challenges, we did what we have always done and will continue to do, create technical and logistical solutions that enable our customers to execute their drilling campaigns as efficiently as possible. In fact in 2021, we surpassed both our internal and our customers’ expectations as we generated the highest uptime performance in the history of Transocean, and earned a record number of customer bonuses due to outstanding operating performance.

As reported in yesterday’s earnings release for the fourth quarter, we delivered adjusted EBITDA of $250 million on $671 million in adjusted revenue. This strong operating performance was driven by our team of experienced professionals and resulted in a fleet wide revenue efficiency of over 94.5% for the quarter and 97% for the year, our highest annual revenue efficiency rate in Transocean’s history. Our record-setting annual revenue efficiency is even more impressive considering the specific operational challenge we faced last quarter that resulted in unplanned downtime for the Deepwater partners in the U.S. Gulf of Mexico. I’m pleased to report that there were no injuries and the rig is once again operational. Despite this event we still delivered fleet uptime above 97% and generated $185 million in operating cash flow in the fourth quarter.

Now turning to the fleet. Starting in the U.S. Gulf of Mexico. I’m pleased to announce Chevron added one well with the Deepwater Conqueror at a rate of $335,000 per day immediately following completion of the current program. With nearly six years of continuous service with Chevron, the rig is now anticipated to remain on contract through December 2022. Also in the Gulf, the Discoverer Inspiration secured one form well plus two option wells with Enven. The firm term carries a rate of $290,000 per day with the two option wells at escalating rates of $300,000 and $310,000 per day. The firm work is in direct continuation of the Inspiration’s current contract with Hess, and is expected to take the rig through September. If both options are exercised, the Inspiration will be fully booked through the end of the year.

Remaining in the Gulf, the Deepwater Invictus secured a one well extension with BHP at an increased day rate of $305,000 per day. The additional well keeps the rig busy through September 2022 and continues several years of continuous service for BHP. Rounding out the Gulf of Mexico, the Deepwater Asgard has been awarded a two-well contract at a rate of $395,000 per day excluding any integrated services. The campaign is planned to commence immediately following current operations. As one of seven seventh-generation premium 2.8 million pound hook-load drillships in our fleet, the Asgard affords our customers maximum flexibility for their well programs.

Heading south to Trinidad, the Development Driller III completed a successful campaign with BHP in December. Given the strong and well-deserved reputation of the rig, we are in advanced discussions on multiple opportunities for work commencing in the next few months. Moving down to Brazil. In December, Petrobras recognized Transocean with a 2020 Best Supplier Award for operation of drilling rigs. While this award reflects performance for calendar year 2020, we continue providing Petrobras with excellent service throughout 2021 and into 2022. We are proud of the hard work and dedication our crews on the Petrobras 10000, Deepwater Mykonos, and Deepwater Corcovado displayed over the last two years in Brazil.

Over to Norway. We added a one well extension to the Transocean Spitsbergen campaign at a rate of $305,000 per day that occupies the rig through September 2022. The agreement also contains provisions for additional work at escalating rates through 2023 according to the commencement period. And finally, in the UK, Paul B. Loyd secured a one well contract with UK independent Serica Energy at a day rate of $160,000 per day commencing this summer.

As we look toward upcoming opportunities for 2022, we’re encouraged by the market and industry trends we observed developing throughout the past year. Oil prices while volatile remained highly supportive of steadily increasing offshore activity defying uncertainties brought by new COVID variants. Indeed, now in the $90 per barrel range, prices remain substantially above most offshore field breakevens.

Numerous factors have contributed to the rise in commodity prices. Chiefly, the industry has suffered from structural underinvestment and reserve replacement, a metric that affects future production capabilities. And capital that would have been allocated to traditional sources of energy is increasingly being returned to shareholders through dividends or share repurchases or directed to green energy initiatives such as wind and solar. According to the International Energy Forum, global oil and gas discoveries fell to a 75 year low in 2021 as upstream investment declined a staggering 23% from pre-pandemic levels. Additionally, recent energy consumption levels have proven resilient as vaccines became more readily available and various restrictions continue to be eased. Oil demand bounced back in 2021 and is expected to exceed pre-pandemic highs this year at greater than 100 million barrels per day.

Finally, OPEC plus production discipline last year kept supply in check as the group committed to stay with its gradual production plan despite pressures from large consumers like the United States for further increases. Further, there is growing uncertainty and evidence of OPEC plus ability to even meet production levels. While oil balances and prices had displayed some volatility due to the market’s concerns about demand and inflation, the majority of indicators point toward a sizable bullish inventory imbalance in the next 12 to 24 months.

In January, many analysts revised their oil price forecasts up from prior projections for later this year and next. We are now seeing a growing number of projections ranging from around $90 per barrel, which we’ve already achieved to more than $100 per barrel between now and the third quarter. The positive outlook for energy markets is also becoming clear for offshore drilling, particularly in the regions in which we have concentrated our fleet.

From January 2021 to January 2022, the number of floaters on contract globally increased to 114 rigs, up from 98. This trend should continue as industry analysts project global demand measured in rig years will increase approximately 6% per year on average through 2026. We anticipate as demand continues to strengthen, the upward trajectory of day rates will accelerate as utilization is driven higher. To that point, active utilization for sixth and seventh-gen drillships had surged to over 90% globally, up from the low mid-80s toward the latter half of last year.

Many of these high specification assets are concentrated in the U.S. Gulf of Mexico where we continue to see the most significant growth in day rate trajectory. Throughout 2021, we observed a pronounced increase in day rates of the ultra-deepwater fleet with rates in the Gulf climbing from the low-200,000s to well over $300,000 per day. Historically, the Gulf of Mexico has served as a barometer for the offshore deepwater drilling industry and we are excited to see the healthy progression of day rates.

We are also observing a considerable uptick in direct negotiations to secure ready-to-work assets in the region. With the majority of the active fleet contracted through the better part of 2022, we anticipate supply will remain tight. Several rigs are planned to enter the region over the next year including our two new builds, the Deepwater Atlas and the Deepwater Titan. However, these floaters will arrive already contracted for various programs.

Looking at other markets. Brazil accounted for approximately 34% of floater awards in 2021 absorbing the majority of the active fleet in the region. Consequently, floaters from other areas will be required to meet additional demand, which should remain strong over the next several years as the number of project approvals is expected to double in 2022 from 2021 levels, and remain generally robust through 2026.

In addition to the many Petrobras prospects on the horizon, medium to long-term opportunities with IOCs and other NOCs including Equinor, Shell, Petronas, and TotalEnergies are expected to commence in 2023. Given our experience and operational track record in Brazil, we believe we are very well positioned for these incremental opportunities.

In West Africa, while regional demand and utilization levels continue to lag the U.S. Gulf and Brazil, we remain encouraged by the number of opportunities surfacing in the area. Floater demand is anticipated to be between 12 and 15 rig years annually through 2025 with a substantial portion of demand driven by Angola and Ghana. If this demand materializes, we would expect the number of rig years required for opportunities in the region will reach pre-pandemic levels later this year.

In Norway, the Norwegian Petroleum Directorate recently confirmed that 2021 was a record-breaking year for the country with the highest oil and gas revenues in history driven by a combination of higher production of oil and gas, robust demand, and strong commodity prices. The NPD anticipates production in Norway will continue to increase over the next two years with new discoveries and field development projects coming online. This outlook matches broader expectations for a stronger Norwegian market from 2023 as a record level of sanctioning is expected by year-end due to the expiring tax incentives. In fact, one projection estimates a 255% increase in project sanctioning on the Norwegian continental shelf from 2021 to 2022.

In summary, we are very excited for a stronger 2022, and our outlook remains as positive as it did when we spoke at the end of the third quarter. In fact, our outlook has been further reinforced by recent fixture trends in various indicators including customer conversations, industry analyst reports, and market projections for commodity supply-demand balances. We are also encouraged by the additional consolidation of our competitors including the planned merger of Maersk and Noble announced in November, and the ongoing restructuring of the Seadrill Group. We anticipate these transactions will further enhance the overall health of the industry.

As our recent fixtures suggest customers value the assets expertise and consistency of performance the transition provides. In the context of a steadily rising market, we will continue to manage our portfolio of rigs prudently to obtain the optimal combination of rate and term. This also applies to potential reactivations as the market demands. If the market ultimately supports reactivations, it’s important to note that Transocean currently has 13 sixth and seventh-gen stacked or idle rigs. Therefore, we are best positioned to capitalize on the uptick in demand. We will evaluate these opportunities on a case-by-case basis ensuring that the financial return results in value creation for all stakeholders.

As day rates increase, the substantial cash-generating capability of our fleet will contribute meaningfully to the strengthening of our balance sheet. And as we have consistently demonstrated, our team will also execute deleveraging and liquidity-enhancing actions when appropriate ensuring we conduct transactions in the right way. The recent Court of Appeal dismissal of a challenge to our successful exchange transactions in 2020 is a clear example that underscores our ability to effectively implement sound strategies in the best interest of the company and our shareholders. We will continue making prudent use of our capital and other options available to best position the company moving forward.

In conclusion, it is increasingly clear that the strategic rationalization of our fleet over the past seven years has created a competitive advantage for Transocean. When combined with our experienced cruised — crews and shore-based support teams, we remain the logical choice for our customers’ most challenging environment, and we are proud to have positioned ourselves as the clear leader in ultra-deepwater and harsh-environment drilling. Our industry-leading $6.5 billion backlog provides us with the visibility to future cash flows to continue to invest in our people, the maintenance of our assets and new technologies, which we continue to deploy across our fleet. And with all signs pointing toward a continually improving market characterized by the increasing scarcity of the most capable rigs and related increases in day rates, we are growing increasingly confident that the recovery will progress as anticipated. We expect increasing utilization of our fleet and will continue to execute on our strategic priorities to further strengthen our position as the industry leader in offshore drilling. Mark?

Mark Mey — Executive Vice President and Chief Financial Officer

Thank you, Jeremy, and good day to all. During today’s call, I will briefly recap our fourth quarter results and then provide guidance for the first quarter as well as an update of our expectations for the full year 2022. Lastly, I’ll provide an update on our liquidity focus through the first half of 2023.

As reported in our press release, which includes additional detail on our results for the fourth quarter of 2021, we reported net loss attributable to controlling interest of $260 million or $0.40 per diluted share. After certain adjustments as stated in yesterday’s press release, we reported adjusted net loss of $126 million.

Highlights for the fourth quarter include adjusted EBITDA of $250 million reflecting generally good performance despite unexpected downtime on the Pontus. Cash flow generated from operating activities during the fourth quarter was approximately $185 million, up from $141 million in the previous quarter, largely due to the timing of interest payments and reduced income tax payments. Free cash flow generated during the fourth quarter was $114 million.

Looking closer at our results during the fourth quarter, we delivered adjusted contract drilling revenues of $671 million and an average day rate of $352,000. This is consistent with our guidance and reflects strong revenue generation across the fleet that offset downtime for an operational event previously discussed. Operating and maintenance expense for the fourth quarter was $430 million. This is above our guidance primarily due to the identification of certain excess materials and supplies that resulted in a $28 million non-cash charge in the period.

Turning to cash flow and balance sheet. We ended the fourth quarter with total liquidity of approximately $2.7 million, including unrestricted cash and cash equivalents of approximately $975 million approximately $370 million of restricted cash for debt service, and $1.3 billion from our undrawn revolving credit facility.

Let me now provide an update on our expectations for the first quarter and full-year financial performance. Before we get to the guidance, let me address the omnipresent inflation concerns. We are seeing pressure on costs as follows. Both offshore and onshore labor costs have increased. Some of it is a result of our annual collective bargaining negotiations whilst in non-unionized countries, we have provided compensation increases for the first time since the downtime — downturn started in 2014. The cost of materials and supplies are also increasing but at manageable rates. Logistics costs in the country are lower in 2022 than we experienced in the second and third quarter of 2021. Most importantly, our long-term contracts provide us with the opportunity to recover most of these costs from our customers and with new contracts with day rates rising, we could offset the inflationary impacts. And finally, all increased costs were included in our forecast.

For the first quarter of 2022, we expect adjusted contract drilling revenue of approximately $600 million based upon an average fleet-wide revenue efficiency of 96.5%. This is lower than the fourth quarter of 2021 largely due to the day rate decrease from the Deepwater Skyros and Deepwater Conqueror rolling off their legacy high day rate contracts coupled with low activity on the Development Driller III, the Nautilus, and the Paul B. Loyd Jr. in the first quarter of 2022. There is some offset from increased activity on the Transocean Barents, Transocean Norge, and Discoverer Inspiration.

For the full year, we are anticipating adjusted revenue to be approximately $2.7 billion also based on 96.5% revenue efficiency. We expect the first quarter O&M expense to be approximately $425 million. The slight quarter-over-quarter decrease is attributable to the non-cash materials and supplies charge taken in the fourth quarter, partially offset by the increased activity on the Barents, Norge, and Inspiration in the first quarter. For the full year, we are anticipating O&M expense to be approximately $1.7 billion.

We expect G&A expense for the first quarter to be approximately $44 million and ranging between $175 million and $180 million for the full year. Net interest expense for the first quarter is forecasted to be approximately $104 million. This includes capitalized interest of approximately $15 million. For the full year, we’re anticipating net interest expense of approximately $402 million, including capitalized interest of approximately $71 million. Capital expenditures including capitalized interest for the first quarter are forecasted to be approximately $121 million. This includes approximately $92 million for our new build drillships under construction and $30 million of maintenance capex.

Cash taxes are expected to be approximately $9 million for the first quarter and approximately $30 million for the year. Our expected liquidity on June 2023 including our covered $1.3 billion revolver that matures on that date is forecast to be between $1.4 billion and $1.6 billion including restricted cash of approximately $275 million, shipyard financing for our first eighth-generation drillship, the Deepwater Atlas, and anticipated secured financing of our second eighth-generation drillship, Deepwater Titan.

This liquidity forecast includes an estimated 2022 capex of $1.3 billion and the first half of 2023 capex expectation of $130 million. The 2022 capex includes $1.2 billion related to our new builds and $100 million for maintenance capex. With rig supply and demand currently well balanced, we anticipate beginning to reactivate cold stacked rigs soon. As always, we will be disciplined when assessing these opportunities to ensure that all costs are supported by the duration and day rates associated with any new drilling contracts.

In conclusion, in addition to the safe, reliable, and efficient operation of our rigs, we will maintain our focus on optimizing cash flow generation through both revenue enhancements as the market continues to improve and cost control initiatives. As we demonstrated in 2021 through various liability management transactions, strengthening our balance sheet and improving liquidity remains our priority. We will continue to actively monitor and pursue opportunities to delever and extend our liquidity runway through a variety of actions using all appropriate tools available in the market.

This concludes my prepared comments. I’ll now turn the call back over to Cale.

Cale Dillingham — Treasury Lead Analyst

Thanks, Mark. Cynthia, we’re now ready to take questions. And as a reminder to the participants, limit yourself to one initial question and one follow-up question.

Questions and Answers:

Operator

[Operator Instructions] We will take our first question from Thomas Johnson with Morgan Stanley. Please go ahead.

Thomas Johnson — Morgan Stanley — Analyst

Hey, good morning. Congrats on the strong quarter, everyone. I guess just to start off here on the harsh side of things, in the last couple of quarters you guys had highlighted the UK as a potential area of strength kind of moving through 2022. Could you guys just kind of give us maybe an update on your outlook for Norway versus the UK, and maybe how that outlook has changed over the last few months?

Roddie Mackenzie — Executive Vice President and Chief Commercial Officer

Yeah. Hey. It is this is Roddie M. I think what I’d take you through on that for the UK what we’re seeing now is things beginning to pop up. You have to remember that the UK’s activity level dropped down to very, very low levels. So everything from here looks like very good growth. So what we’re expecting to see is there’s more demand coming on by the end of ’22 and into ’23. The kind of the supply chain issues of having limited availability to wellhead equipment and that kind of stuff has delayed that a little bit, but certainly now we’re seeing a lot more tenders. As Jeremy announced there, we got the — closed the contract for the Paul B. Loyd and we’re working on several follow-on bits of work there. So we’re feeling pretty good about that.

Certainly also the P&A and decommissioning work that’s being pushed through in the UK should see a market uptick in activity in ’23. In terms of Norway, we continue to see a similar level of activity. We have to remember that — and Norway was the first place to see the recovery, so to speak. So our uptick in activity over the past couple of years has been particularly good. And what we’re seeing now is because of the tax scheme that’s being put in place and the PDOs that are expected to get approvals this year, Norway is going to be booming in the second half of ’23 and ’24, and in fact most projections show that we will be at 100% utilization of all assets at that point.

So it remains to be seen that all of those PDOs are approved. But certainly, the outlook for Norway looks particularly strong, and again delivered by the macro that is fantastic across the world at the moment. But also, the tax schemes that are being put in place by various jurisdictions. So we really think harsh environment has a very positive outlook for ’23 and ’24.

Thomas Johnson — Morgan Stanley — Analyst

Great. Thank you. And then maybe just shifting to the benign side of things. Day rates — recent day rates you guys have shown in the Gulf of Mexico have been really strong. We’ve seen kind of operators there start to market those projects as advantageous from just a carbon kind of footprint per barrel basis. In the past you guys have spoken about some of the technology that you’ve implemented across the fleet to kind of limit emissions and increase efficiencies. Could you guys just give us an update and kind of how you’re seeing emissions and kind of different carbon reduction goals kind of start to make their way into tenders?

Roddie Mackenzie — Executive Vice President and Chief Commercial Officer

Yeah. So I think we would probably all agree that the pace of the recovery that we’ve seen in the drillship side of things is probably exceeded everybody’s expectations, which is great. And certainly, when we see that really high level of utilization above 90% and for the real high-spec rigs were essentially 100% utilization at the moment. The question then turns to things as you say like emissions. So it’s true that it’s widely touted that Gulf of Mexico provides a particularly efficient carbon footprint per barrel, and that’s one of the reasons that our customers invest in that particular basin, but also because the breakevens are particularly good and the size of the developments are profound. So it’s a very constructive business environment in the U.S. Gulf.

In terms of the specific technologies, as you will have heard us say at various conferences and what have you, we do have several initiatives around reducing carbon footprint as far as you possibly can doing so in a safe manner. So not throwing caution to the wind, but certainly exploring all ways that we can reduce fuel consumption and also produce lower emissions per liter of fuel consumed. So we do have several initiatives out there. We’ve everything from fuel additives to how we manage our power plants, but we kind of engage with the customers on an individual basis on those kinds of things. The reason being that a lot of them involve capital investment, they involve upgrades, so it’s certainly something that benefits everybody.

But from our point of view, we are looking for a partnership on that investment before we push forward whole scale on that simply because the investment has a return period on it that we need to see reasonably long contracts to justify that kind of upgrade. But it’s a hot topic just know for sure. Many of the operators engage with us regularly on that and we’ve got several more initiatives that you’ll see come out over the coming years.

Thomas Johnson — Morgan Stanley — Analyst

Thanks. I’ll leave it there.

Operator

[Operator Instructions] We will take our next question from Karl Blunden with Goldman Sachs. Please go ahead.

Karl Blunden — Goldman Sachs — Analyst

Hi, good morning. Thanks very much for the time. Roddie made some comments about a very strong outlook for 2023 and — or second half of ’23 and ’24 in Norway. I’d just be interested in any color you can provide on how you see contract rates and also lengths evolving through the first half of ’23? And the reason I ask that is you do have some bonds that are coming due in ’23, ’24 that are currently backed by contracts and I’m trying to figure out what the right base case assumption should be in terms of how you refinance or address those. Could that be done backed by contracts again or is another approach more feasible?

Roddie Mackenzie — Executive Vice President and Chief Commercial Officer

I’ll answer the market part of the question and then I’ll kick it over to Mark for the financing piece of it. In terms of the market, so there is already a couple of tenders out there that are looking at much longer term. So it’s true that as the harsh environment has recovered over the past couple of years, there’s kind of a mix between longer-term contracts and some shorter-term contracts. So as I mentioned before that tax incentive is really kicks in place this year. So you’ll see the follow-on activity in ’23 and into ’24 for that one. But yeah, I think overall that market looks quite well balanced at the moment, and certainly looks to be very, very strong when you get into that ’23, ’24 timeframe.

Mark Mey — Executive Vice President and Chief Financial Officer

Yes, Karl, this is Mark. So, as you know, each of those CAT-D rigs have four three-year options. So clearly if those get exercised, the ability or the intention to go out and refinance the balloon payments over those periods would be probably number one. However, we have other options as well. And if you look at our five-year plan, we actually anticipate paying off that as balloons, not refinancing them. So anything that we do with regard to refinancing against contract backlog would be a benefit to out our liquidity forecast. But as I said, we have several things we’re working on. I don’t want to get into that right now but just watch this space.

Karl Blunden — Goldman Sachs — Analyst

Fantastic. Thanks, Mark. Maybe just one quick follow-up on liquidity. The revolver you mentioned is due in the middle of next year. What is the right time frame for addressing that? Some folks would think sooner rather than later, but with the macro improving, how does that affect the right timing for looking to extend that?

Mark Mey — Executive Vice President and Chief Financial Officer

Yeah, Karl, I think you’ve got it spot on. We have been talking about the macro improving now for a few years. The timing couldn’t be better. So clearly we’re waiting to see a few more fixtures get posted to ensure that all markets including the banks see that the market is improving, but you can expect us to start this process in the next few months and hopefully get it completed by the end of the year.

Karl Blunden — Goldman Sachs — Analyst

Thanks very much.

Operator

[Operator Instructions] And we will go next to Samantha Hoh with Evercore ISI. Please go ahead.

Samantha Hoh — Evercore Group — Analyst

Hey, guys. Thanks for taking my question. Jeremy, you had mentioned on the last call that you were being approached by customers to revisit the business model and maybe figure out different partnerships to provide both the downturn and upturn and clearly we’re in an upturn now and with the — through the fixtures that you posted, I’m just kind of curious how those dialogs are going and if you could actually share what type of arrangements are being discussed.

Jeremy D. Thigpen — Chief Executive Officer

Yes. I’ll hand that one to Roddie because he’s engaged in those conversations daily, but thanks for the question, Samantha.

Roddie Mackenzie — Executive Vice President and Chief Commercial Officer

Yeah. Hey, look, I mean, as things improve as you might imagine it, the discussion changes is no longer about trying to find a spot for the rigs and whether we’ll be able to keep them busy. The discussion for the future is now about what the economics look like. So we are heavily engaged in discussions around value proposition. So that’s not just the day rate. So yes, you’ve seen a really big increase in day rates comparatively speaking over the past 12 months, but we also see a lot more kind of value discussions around how is compensation linked to performance. So we’ve done a fantastic job. Hats off to Keelan and the operations team for delivering first-class performance that not only the results in really good revenue efficiency but also a bonus capture opportunity.

So we’re in the tens of millions of bonus capture per year. So that’s something we probably would never have said in years past, but I do remember the debate some years ago where rigs weren’t really embracing that. I think Transocean embraced it wholesale and we have a number of contracts that we’ve done particularly well in that. So there is definitely that performance-linked compensation element.

In addition to that in terms of like long-term partnerships, we do have partnerships with several of the operators that last for many years by budgeted contracts, but we’re in constant dialog with them on how to essentially enhance our service delivery, how to meet more of their goals, and similar to one of the previous questions around ESG initiatives and reduce carbon footprint, those kind of discussions take place part and parcel with performance, with long-term contracts, and investment in the rigs.

Jeremy D. Thigpen — Chief Executive Officer

Yeah, and I’ll just add to that, Samantha. It’s not just about the rates or the structure — the economic structure, it’s really around rig availability. Our customers now recognize that the availability of active high specification assets is rare, and supply is tight, and the cost — not only the cost but at the time to reactivate a rig or bring out a new build because of the supply chain challenges we’re facing around the world due to COVID is really a problem for them.

And so, the partnerships are both around what does the business model look like going forward and how do I get access to the best rigs that are currently available and hot.

Samantha Hoh — Evercore Group — Analyst

What are some of the sort of leading technologies that operators are looking for now as the conversation is to actually reactivate a rig? I think like — and I mean, for example, mentioned managed pressure drilling is kind of — they’re seeing more and more of that in rig tenders, but beyond just like the low emission technologies and what not like what other sort of technologies do you see customers are looking for in rigs these days?

Roddie Mackenzie — Executive Vice President and Chief Commercial Officer

Yeah. So we are — other than the ones that you mentioned, we are heavily engaged in performance-related technologies. So for example, ADT but also more and more drilling automation. If you’re an avid follower of our LinkedIn page, you would have seen we just posted the robotic riser bolting system, which is the first robots to be brought to drill floor. A very interesting technology because it provides a far safer drill floor operation relatively speaking to the traditional means, but also provides time savings that’s a benefit to the customers’ well program.

So yeah, we have a list of these things. We probably have about 10 key technologies that we’re currently discussing with customers. We kind of have a package of presentation of all these different techs that we take to the various drilling departments around the world. But the uptick was slow during the downturn, but we’ve seen a marked increase in the number of technologies that are being deployed on the rigs and pilots that are kicking off. So we’re pretty encouraged to see that our customers are now finally getting into that kind of investment.

Jeremy D. Thigpen — Chief Executive Officer

Yeah, I think, the key for us has always been our focus has been on technologies that can improve safety, reliability uptime, and efficiency both drilling efficiency and improving our environmental footprint. And so, that — those have been the technologies we continue to invest in despite the downturn and I’m proud that we have and we continue to develop those and even deploy some. And now we’re getting at this stage where the customers actually want to pay for it, and so that’s the encouraging piece. And so, if we can get the customers to actually pay for these technologies when they see the value in them, then we can deploy more quickly. Right now, it’s been a very measured deployment just because of a lack of capital.

Samantha Hoh — Evercore Group — Analyst

That’s wonderful. Thanks, guys. I’ll definitely go take a look at that riser bolting system on your LinkedIn page.

Operator

We will take our next question from Aaron Rosenthal with J.P. Morgan. Please go ahead.

Aaron Rosenthal — J.P. Morgan — Analyst

Hey, good morning. Thanks for taking my question. Just wanted to quickly follow up on the liquidity number detailed earlier. I think I heard about $1.5 billion in June 2023. If that’s correct, just kind of want to verify the prior year end ’22 liquidity to about [Technical Issues] was intact. Maybe you can kind of help us bridge from that figure during the interim six months to $1.5 billion in June?

Mark Mey — Executive Vice President and Chief Financial Officer

Yeah. Sorry, Aaron. You were very gobbled, I cannot hear you. I think you asked the liquidity mid-2023 and the range I gave was $1.4 billion to $1.6 billion including our $1.3 billion revolving credit facility, which matures on that date.

Aaron Rosenthal — J.P. Morgan — Analyst

So, yes. Sorry, guys, if you weren’t able to hear me. Was the $1.4 billion to $1.6 billion in June of 2022 or 2023?

Mark Mey — Executive Vice President and Chief Financial Officer

’23.

Aaron Rosenthal — J.P. Morgan — Analyst

Okay, and then the prior year-end 2022 liquidity figure of between $1.8 billion and $2 billion, is that still in place?

Mark Mey — Executive Vice President and Chief Financial Officer

Yes, it is. And obviously, the reason why we’re giving you a specific data in ’23 because that’s the day that the revolver matures. Obviously, prior to that time, we will have either replaced it or extended it, so we’ll have a better number for you once that exercise is complete.

Aaron Rosenthal — J.P. Morgan — Analyst

Yeah. Understood there, and then I guess in the — from year end ’22 to call it June of 2023 at the midpoint, that’s about $400-or-so million of liquidity falling. Can you just kind of elaborate on the bridge there? I guess you kind of laid out an the initial capex number, but if you could just give some incremental color would be appreciated.

Mark Mey — Executive Vice President and Chief Financial Officer

Yeah, the vast majority of that is debt repayments. If you recall the previous question we had on the CAT-Ds, we have one of the two CAT-D bonds maturing in that time period. So we’re paying that off during the first several months.

Aaron Rosenthal — J.P. Morgan — Analyst

Okay, perfect. Thank you very much. And then just one more, I guess on the 1Q ’22 guide. I guess, can you just elaborate further on the moving pieces there with respect to I guess both downtime and perhaps in the Gulf of Mexico as well as some of the guided opex figures?

Mark Mey — Executive Vice President and Chief Financial Officer

You’re asking about Q1 of 2022?

Aaron Rosenthal — J.P. Morgan — Analyst

Yes, sir.

Mark Mey — Executive Vice President and Chief Financial Officer

So the biggest change there is the fact that we’ve had two of our high day rate rigs, which were long-term contracts, the Skyros and the Conqueror roll-off to lower day rate contracts. That’s about $13 million. You also have two less days in the first quarter because of February being 28 days, so that’s another $12 million and we also are forecasting less reimbursables for the first quarter versus the fourth quarter, and that’s about $7 million. But as you know, that can fluctuate based upon what we get asked to buy for customers during the quarter. But those are the three components that drive the difference.

Aaron Rosenthal — J.P. Morgan — Analyst

Perfect. Thank you.

Mark Mey — Executive Vice President and Chief Financial Officer

Thank you.

Operator

This will conclude today’s question and answer session. I would now like to turn the call back over to Cale Dillingham for any additional or closing remarks.

Cale Dillingham — Treasury Lead Analyst

Thank you, Cynthia, and thank you, everyone, for your participation on today’s call. We look forward to talking with you again when we report our first quarter 2022 results. Have a good day.

Operator

[Operator Closing Remarks]

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