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Transocean (RIG 0.39%)
Q2 2022 Earnings Call
Aug 02, 2022, 9:00 a.m. ET


  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:


Good day, ladies and gentlemen, and welcome to the Q2 2022 Transocean earnings conference call. For information, today's conference is being recorded. At this time, I would like to turn the call over to your host Ms. Alison Johnson, investor relations.

Please go ahead, ma'am.

Alison Johnson -- Investor Relations

Thank you, George. Good morning and welcome to Transocean's second quarter 2022 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.

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Also, please note that the Company undertakes no duty to update or revise forward-looking statements. Following Jeremy and Mark's prepared comments, we will conduct a question-and-answer session with our team. During this time, to give more participants an opportunity to speak, please limit yourself to one initial question and one follow-up. Thank you very much.

I will now turn the call over to Jeremy.

Jeremy Thigpen -- Chief Executive Officer

Thank you, Alison, and welcome to our employees, customers, investors, and analysts participating in today's call. It has certainly been an eventful three months since our last update. Commodity prices have exhibited considerable volatility with the magnitude of the existing supply demand imbalance, energy security concerns, and the inability of swing producers to meet their production targets, all driving prices higher, while concern around potential demand destruction due to either or both high gasoline prices and/or a dramatic slowdown in global economies pushing prices lower. That said perspective is important.

While we have experienced volatility, commodity prices have remained within a range that is still extremely healthy for offshore development. Indeed, the outlook for our industry-leading assets and services as the most promising it has been in many, many years. Globally, we continue to face an energy crisis resulting from years of underinvestment in oil and gas reserves replacement and production growth, as energy companies reacted to significant pressure from investors to maintain capital discipline and pressure from investors, activists, and politicians to rapidly transition to lower carbon energy sources and renewables. As a consequence, the long-term replacement of hydrocarbon reserves has consistently fallen short to production levels and consequently depleted global inventories driving barrel and end product crises to near record highs.

This consistent shortfall in production leads us to conclude that we're in the early stages of a sustainable recovery. Now to our results and a summary of global offshore drilling markets and fixtures. As reported in yesterday's earnings release for the second quarter, Transocean delivered adjusted EBITDA of $245 million on $722 million and adjusted revenue, resulting in an adjusted EBITDA margin of approximately 34%. These solid results were once again driven by strong operating performance as we delivered fleet uptime in excess of 96% and revenue efficiency of 97.8%, which was supported by strong contractual bonus conversion.

Notwithstanding our solid operating performance, in the backdrop of a strengthening offshore drilling market, illustrated by our recent fleet status report and the fixtures we announced last night. As we look to the back half of the year, we are likely to experience some gaps between contracts, which could impact our utilization as our customers grapple with temporary supply chain challenges that hamper their near-term ability to secure key capital equipment and consumables required to convince their campaigns in a timely manner. However, we expect these delays to gradually diminish over the next 12 to 18 months. Mark will provide some additional color when he updates our guidance in a few minutes.

Let's now turn to the fleet and our recent fixtures. We continue to see steady improvement in day rates, contract terms and the utilization of the global offshore drilling fleet, particularly the high specification assets Transocean owns and operates. First, in the Gulf of Mexico, we signed an agreement with a major operator for two years on the Deepwater Conqueror and direct continuation of the current program at a leading edge rate of $440,000 per day, with up to an additional $39,000 per day for MPD integrated services and our technology products. The contract represents approximately $321 million in firm backlog.

That is in addition to the amount disclosed on our fleet status report. In Norway, Equinor exercised two one-well options on the Spitsbergen at a rate of $305,000 per day, extending the current firm term through June 2023. We also signed a nine-well contract with Equinor for the transition Spitsbergen at a rate of $335,000 per day commencing October 2023. The agreement contains a provision for two one-well options at a rate of $375,000 per day.

And similar to many of our contracts in Norway, we have the opportunity to earn a healthy bonus percentage in addition to the base day rate. In the UK as disclosed in the fleet status report, we secured a one-well contract plus options with NEO energy and Harbour energy for the Paul B. Loyd at a rate of $175,000 per day. Subsequent to the release of the fleet status report, the first option well was exercised to commence indirect continuation of the rigs current program, adding approximately $17.5 million to our backlog.

The firm period now stands at 200 days. If all options are exercised, this will keep the rig busy through April 2024. Down in Brazil, the Deepwater Mykonos was awarded a 435-day contract at a rate of approximately $364,000 per day in direct continuation of the current program. Also in Brazil, subsequent to release of our fleet status report, the Petrobras 10,000 received a 5.8-year contract at $399,000 per day escalating annually to $462,000 per day.

The rate does not include an additional fee for the customers anticipated use of our patented dual activity technology, which remain valid through May 2025. The contract commences directly following the end of the current term in October 2023 and adds an estimated $915 million to our backlog. In India, Reliance Industries awarded an estimated 86-day contract extension plus up to four option wells for the KG1 at a local market-leading rate of $330,000 per day. The firm work extends the contract through July 2023.

And if all options are exercised, the campaign will extend through April 2024. This leading edge rate in India reinforces that the industry recovery has moved beyond the harsh environment in Golden Triangle and is truly extending to other regions across the globe. In total, I'm pleased to share we have added in approximately $1.3 billion in backlog since the release of our fleet status report. Next, I'd like to take some time to discuss energy security and the important role we play.

Though the alarming conflict between Russia and the Ukraine, the latest catalysts for recognition of this critical situation, it opened the entire world's eyes to the increasingly fragile state of global energy supply. In fact, the consistent and systemic marginalization of companies involved in the production of hydrocarbons has significantly contributed to the situation we find ourselves in today. This is now more apparent than ever. Recently, OPEC+ agreed to moderately increased production at the behest of large oil consuming countries, chiefly the United States.

OPEC+ producers, however, appear to have little or no spare capacity, raising the question of whether these actions will reduce short and long-term oil prices for simply contribute to sustained volatility. Indeed, one of the leading energy research consultancies estimates the spare capacity within OPEC+ is just 1% of global demand, the lowest level since the inception of its assessments in 2012. Without additional drilling it is estimated non-OPEC production will decline by 9 million barrels per day by 2025 and 20 million barrels per day or 41% by 2030. Additionally, according to Rystad Energy's 2022 review, global recoverable oil reserves now total an estimated 1.6 trillion barrels, which is a drop of almost 9% Since last year, and 152 billion barrels fewer than the 2021 total.

For those who are willing to look beyond political advocacy and honestly assess the empirical data, there is no doubt that hydrocarbons will continue to play an important role in supplying the world's energy for the foreseeable future. As an example, electricity generation is highly dependent upon hydrocarbons. According to BPs most recent statistical review of world energy 63% of global electricity is generated by fossil fuels, with over a quarter of total supply coming from oil and natural gas. Moreover, 84% of global primary energy consumption comes from fossil fuels, with 57% from oil and natural gas.

With that, we believe the case is clear that E&P companies will continue to engage in exploration and development work to meet worldwide demand and replenish diminishing reserves. This is especially true in the offshore basins requiring our assets and services where recoverable reserve levels are high and carbon intensity is relatively low. With sustained constructive commodity prices, the economics of offshore projects remain compelling for continued development. The concept of energy expansion rather than transition means we need to develop and deploy all energy sources and technologies without ideological bias.

The production of hydrocarbons or renewables must happen in concert to meet even the most conservative estimates of global energy demand. As such, it's not surprising that we continue to see a rapid tightening of the offshore market for high capability drilling assets unfolding across multiple regions with committed drillship utilization remaining above 90%, and we believe further tightening is on the horizon. In June, Rystad revised its year-over-year offshore deepwater E&P investment growth projection to 28%, which is double its March projection, driven by higher service costs and additional anticipated requirements in Brazil, Ghana, West Africa, and Australia. The trend of day rate fixtures also supports our positive view on the outlook for offshore drilling.

Most recently, we saw Equinor contract to competitors asset with nearly $90 million in upfront payments to partially cover mobilization, reactivation, and upgrade costs. Bringing the total equivalent day rate about $600,000 per day, a move we take his recognition by one of our largest customers that the market is growing increasingly tight for the highest specification drillship fleet. And the latest projection by Fernley shows active utilization for global sixth and seventh gen fleet over 97% with rate projections clearly crossing the $400,000 per day threshold, which we certainly validated with the fixtures we announced last night. Taking a closer look at the global market environment, the Gulf of Mexico is expected to remain tight through the end of the year, while fixtures in the region have slowed a bit this quarter, we anticipate contract activity will accelerate over the next two quarters.

Our estimates show more than 10 programs yet to be awarded that are set to commence between now in the second quarter 2023. Importantly, direct negotiations continue to dominate as a result of market tightness, and we are seeing improved contractual terms, higher day rates, and longer durations. Several operators are urgently looking to secure seventh gen assets for multiyear agreements in the U.S. Gulf of Mexico, some of which have not appeared on any of the annual reports today.

There have also been constructive developments in the 20K market. And you likely know shell recently assumed 51% ownership of the project formerly known as North Platte, which they have since renamed Sparta. The agreement for another drilling contractor vessel that was initially contracted by total energies for North Platte was recently terminated and we believe we are now very well positioned to secure this work, if and when the project is re tendered. As a reminder in addition to the 20K well control equipment that will be installed on the Deepwater Titan in the Deepwater Atlas, both rigs are also outfitted with industry-leading 1,700 short-term hoisting capability, a feature that is unique to these two rigs and has the potential to enable our customers to run fewer casing strings presenting a significant time and cost savings.

On that note, I'm proud and pleased to report that the Deepwater Atlas was delivered from the shipyard in June, and is expected to arrive in the U.S. Gulf of Mexico in Q4, or contract preparations will be completed prior to commencement of our main contract with Beacon Offshore Energy, and while on the subject of new builds, we are on pace to accept delivery of the Deepwater Titan later this year. In Latin and South America, substantial contracting activity is ongoing and the region continues to drive the largest recovery and incremental deepwater rig demand. Specifically in Brazil, there are 10 opportunities comprising in excess of 21 years of demand.

One of these opportunities is the Petrobras multiyear pool tender, an opportunity we believe could draw up to seven rigs from the global fleet into Brazil, which would obviously require several reactivations. Tender submissions are due within several weeks, and we believe our long-standing relationships and experience robust support infrastructure and strong operational performance in the region make us highly competitive for this work. In addition to the Petrobras prospects, medium to long-term opportunities with IOCs and other NOCs, including Equinor, Shell, Petronas, and Total Energies are expected to commence in 2023 and 2024. As we mentioned on our last call, there are no high specification available floaters in the region.

Therefore rigs from other areas will be required to meet additional demand, which we anticipate will remain strong over the next several years, as Brazil continues on his journey to double production by 2030, which would make the country the world's fifth largest crude exporter. In West Africa and the Med, we remain very encouraged by floater demand, as we expect over 20 programs to be awarded and commence within the next 18 months. A number of these programs are multiyear opportunities with multiple NOCs and IOCs. As an example, E&I is currently tendering for two red lines each at 18 months commencing between Q1 and Q2 next year.

Similarly, Shell is looking to secure an asset for its campaign in Egypt that could keep that rig off the market for up to two years. If the demand materializes as anticipated, we could see around 15 rig years of work awarded in the next several quarters. In Asia Pacific, we continue to observe demand in various jurisdictions with limited risk supply. If the demand materializes as we expect, we could see a significant increase in day rates from what we've observed in the past several years.

In fact, ONGC has demand for more than four rig years of work in India that could absorb it three rigs. Additional demand and Indian and Australia is expected to increase in mid 2023 and early 2024, which would result in a regional rig shortage at this time driving higher day rates as assets will need to be mobilized from other regions to fill this demand. Moving to the harsh environment market in Norway, we expect relative softness and activity to continue through the end of the year, with a sizable uptick in sanctioning and contracting activity anticipated by year-end, as the Norwegian tax incentives expire in December. We think this will ultimately lead to a sold-out market in 2024, as current active utilization is already at 88%, up from 82% last quarter.

And it's important to note that we also expect to see several of those assets leave the harsh environment market for higher margin work and benign environments, which will further strained supply. Consequently, we believe rates in Norway will continue the upward trajectory we've seen with our recent fixture on the Spitsbergen. In fact, the latest third-party projections suggest we could see base day rates excluding bonus potential exceed $400,000 per day, and some of the next fixtures being announced. In summary, our outlook remains very constructive, supported by the upward trajectory of fixtures, customer conversations, industry analyst reports, and market projections for commodity supply, demand, and balances.

All indications point to a further tightening of the market as we continue to see increasingly healthy day rates posted across all regions as well as longer terms. As we approach rate levels that meaningfully support strengthening our balance sheet, we reaffirm the message we have conveyed for the last several years, liquidity and deleveraging is of paramount importance to us. Therefore, we are actively managing our portfolio of high specification floating rigs to fit the best combination of rate and term and will not reactivate an asset if it does not fit within our broader strategy, including generating an appropriate return on the full cost of reactivation. We will continue to evaluate opportunities for our stack fleet on a case-by-case basis and will mobilize them if and when it makes sense in light of market conditions and if we are convinced that will enhance shareholder value.

The future of our core business is very bright, and we expect offshore drilling to comprise the majority of value for investors for the foreseeable future. However, we fully embrace the need to wherever possible utilize our numerous competencies, assets and talented employees to support the expansion of our business and to transition to a lower carbon future. In this regard, we continue to support several ongoing initiatives, including our collaboration with our partner Ocean Minerals to help support the sustainable collection of Seabed Minerals that are required for high-capacity batteries, such as those found in electric vehicles. We continue to leverage our significant offshore energy experience in ways that contribute to the development of non-traditional energy sources.

However, to be clear, as we and other leaders in our industry have indicated, offshore drillers will continue to play a vital role in the production of hydrocarbons for the foreseeable future. For Transocean, our core offshore drilling business will be the foundation that allows us to develop adjacent opportunities and lower carbon energy sources, while at the same time remaining focused on improving our balance sheet to ensure that we have the liquidity to support our business. As the industry leader in ultra-deepwater and harsh environment drilling, we are continuing to invest in innovations that make our fleet safer, more reliable, and more efficient, creating value for our customers and shareholders. On our last call, we shared progress on the implementation of a robotic riser system on one of our rigs in the U.S.

Gulf of Mexico. I'm pleased to report that we have installed this system on a second ship in the Gulf and are currently working to outfit a third rig in the coming quarters. As a reminder, the robotic riser system automates activities around the rotary table during riser operations, which improve the safety of the operation for our personnel and ultimately improves the consistency and efficiency of our operations. We are also working with our customers on a fuel additive that optimizes fuel consumption, thereby lowering emissions and reducing costs.

Fuel tests utilizing the additives suggest fuel consumption can be reduced by up to 6% depending upon engine loads. To date, we have worked with two customers in the U.S. Gulf of Mexico to adopt and implement the additive and are in conversations for additional implementations. In conclusion, our industry leading backlog which I would like to emphasize grew last quarter and with our announcements last night will certainly grow again this quarter, along with the steadily increasing cash flow producing ability of our fleet enables us to maintain Transocean's position as the market leader for ultra-deepwater and harsh environment drilling.

As we move further along the curve in the industry recovery, we will continue providing safe, reliable, and efficient operations for our customers, while simultaneously focusing on the leveraging our balance sheet to safeguard and create value for our shareholders. I'll turn the call over to Mark. 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 second quarter results and then provide guidance for the third quarter as well as an update of expectations for full year 2022. Let's now provide an update on our liquidity forecast for the end of 2023. As reported in a press release, which includes additional detail on our results, for the second quarter of 2022, we reported a net loss attributable to controlling interest of $68 million or $0.10 per diluted share.

During the quarter, we generated adjusted EBITDA of $245 million and improved our EBITDA margin to approximately 34%. We also generated cash flow from operations of approximately $41 million. Looking closer at our results, during the second quarter we delivered adjusted contract drilling revenues of $722 million at an average day rate of $358,000. Revenues above our previous guidance and reflects better than forecasted uptime, higher bonus conversion and higher reverse reimbursable.

Operating and maintenance expense in the second quarter was $433 million. This is less than guidance primarily due to timing of certain maintenance activities. Turing to cash flow and the balance sheet. We ended the second quarter with total liquidity of approximately $2.5 billion, including unrestricted cash and cash equivalents of approximately $729 million, approximately $400 million of restricted cash for debt service and $1.3 billion from our undrawn revolving credit facility.

Before update guidance, I'm pleased to share that we have closed an amendment to our revolving credit facility, extending its maturity through June of 2025. The extended RCF has a capacity of $774 million through mid-June 2023 and $600 million thereafter through maturity. This extension provides additional certainty and enables us to maintain sufficient financial flexibility as the global drilling market continues to improve. Through an accordion feature, the minute facility also permits us to increase the amount the aggregate amount of capital by up to $250 million.

I'll now provide an update on expectations for our third quarter and full year financial performance. For the third quarter of 2022, we expect adjusted contract drilling revenue to be approximately $670 million based on an average fleetwide revenue efficiency of 96.5%. The quarter-over-quarter decrease is largely attributable to low utilization to chiefly to idle time on the Asgard development rule of three in the balance. For the full year 2022, we were adjusting -- we were anticipating adjusted contract drilling revenue to be approximately $2.6 billion down from our prior guidance by $100 billion due to the additional adult time mentioned above.

To provide context for the aforementioned idle time, that is not a result of a lack of contract drilling opportunities, as witnessed by our recent fleet status report and the $1.2 billion of contract backlog announced yesterday, but rather primarily a result of supply chain challenges faced by customers. For example, in the Gulf of Mexico, several operators have been struggling to access tubulars and consumables for the work construction activities. And in Norway, similar supply chain issues are coupled with lengthy approval cycles that have been hampering near-term activity While these delays are disappointing, they did not alter our mid to longer-term outlook. We expect third quarter O&M expense to be approximately $464 million.

The quarter-over-quarter increase is primarily attributable to timing of maintenance projects across the fleet. For the full year 2022, we anticipate O&M expense to be approximately $1.7 billion. We continue to experience pressure on employee costs and increased pricing from our vendors. Significant portion of our maintenance expenditures fall under our comprehensive services agreements.

These CSAs contain provisions capping annual inflation and limit exposure to rising costs. Additionally, longer-term customer contracts provide cost escalation protection. Finally, with the expected rapid increase in activity, we may experience a shortage of qualified personnel and resulting labor inflation over the next 12 to 18 months. We expect G&A expense for the third quarter to be approximately $45 million and approximately $175 million for the full year.

Net interest expense for the third quarter is forecasted to be approximately $98 million dollars. This includes capitalized interest of approximately $21 million. For the full year, we estimate to incur net interest expense of approximately $395 million, including capitalized interest of approximately $72 million. Capital expenditures and capital additions including capitalize interest, our forecast will be approximately $150 million for the third quarter.

This represents approximately $100 billion for our newbuild drillships predominately the Deepwater Atlas and $50 million of maintenance capex. Cash taxes are expected to be approximately $11 million for the second quarter and approximately $34 million for the year. Our expected liquidity at December of 2023 is projected to be approximately $1.1 billion, reflecting $550 million remaining capacity of our revolving credit facility, and including restricted cash of approximately $280 million, which is primarily reserved for debt service, and anticipated secured financing of a second eighth generation drillship Deepwater Titan. This liquidity forecast includes an estimated 2022 capital expenditures and capital addition of $1.2 billion and 2023 capex expectation of $200 million.

The 2022 capex includes $1.1 billion related to our new build and $60 million for maintenance capex. As always, our guidance excludes speculative rig reactivation or upgrades. In conclusion, strengthen the balance sheet and extending our liquidity runway remained our priority. The extension of our revolving credit facility is the first in a series of actions we will take to address our balance sheet and financial flexibility.

We also anticipate continue to utilizing open at the market equity offering program, which we have received aggregate cash proceeds of $367 million as of June 30. As you're probably aware, our first and highly successful ATM equity program is limited to $40 million. We fully anticipate with new now authorization for another $400 million. As always, you can expect us to continue to prudently make in share capital and opportunistically access capital markets as and when we believe it makes sense.

Retail rates have not comfortably surpassed levels necessary to generate cash flow sufficient to meaningfully support deleveraging our balance sheet over time. This remains our primary priority, and as we expand accordingly, creates value for all shareholders. This concludes my prepared comments. I'll now turn the call back over to Alison.

Alison Johnson -- Investor Relations

Thanks, Mark. George, we're now ready to take questions. [Operator instructions]

Questions & Answers:


Thank you so much, Ms. Johnson. [Operator instructions] Today's first question is coming from Mr. Thomas Johnson calling from Morgan Stanley.

Please go ahead. Your line is open, sir.

Thomas Johnson -- Morgan Stanley -- Analyst

Hi. Thanks. Good morning and congratulations on the strong quarter. Question on the day rate side, obviously, two fantastic rates reported, but historically we've seen some lag between when contract negotiations take place when the date rate traction printed to the public.

So just to help the sell-side kind of place expectations on where day rates could be going specifically on the drillship side of things; A, could you give us some time frame for when negotiations were taking place for the two most recent contracts now? And B, could you update us on how conversations are going customers relative to the day rates and just disclose?

Roddie Mackenzie -- Senior Vice President of Marketing, Innovation, and Industry Relations

Hey. This is Roddie, I'll take that one. Look, I appreciate the compliment there. But I think what I would first like to say is that, you'll -- those may look like market-leading day rates.

But I really believe those are very savvy customers who are moving to get access to the right assets in the right timeframe. So, yes, they look like they're leading the market today, but I don't think that's going to be the case in the next six to 12 months. I think the truth of the matter is very simply as we look at things around the world, especially on the specification of the assets, the customers are moving extremely quickly. So it used to be that you saw six to nine months, sometimes between when we were answering tenders when a fixture would be made.

That's not the case. Now, the majority of the negotiations were involved in are direct negotiations and not part of a tender. So that really helps as we're beginning to see commitments being made within the space of weeks and a couple of months rather than quarters. So, I think you're going to see an acceleration there because especially for the high specification units, there simply is very, very little availability.

So that bodes very well. And I think the second part of the question was around the conversations with the customers. I think, again, it's an increased sense of urgency, but also making sure that they have access to the rate iron for their prospects. So of course, having higher specification units is important in that realm.

So, I think you'll see a real push at the moment for access to the existing fleet, especially the high-spec stuff. Because we really are close to being sold out completely and that means reactivations and moving called assets back into the market, which obviously is not as desirable as picking up one of the highest spec rigs in the world that's hot and already performing very well.

Thomas Johnson -- Morgan Stanley -- Analyst

Great. And then just stay on the topic of reactivation, I think last quarter, you've stated that reactivations would likely take 12 plus months to supply chain lead time. So, I guess, could you just update us on reactivation timelines, where the biggest constraint for the supply chain are, and maybe how labor availability is going to play a role and limiting the number of reactivation that can feasibly take place over the next 24 months?

Keelan Adamson -- President and Chief Operating Officer

Yes, Thomas. This is Keelan and very good question. I think our guidance remains the same. We're probably looking at over 12 to 18 months or a reactivation based on the limitations in the supply chain at this time.

Obviously, we're hoping that that will improve as the situation stabilizes. From a labor point of view, that is something that the industry is used to and we're used to the simplicity that exists in our business. And you'll find that most of the drilling contractors in our space, including ourselves, are prepared from a recruiting processes to our training and our competency development programs. So, we have access to people we can recruit and develop those people in a very timely fashion.

So, yes, it's a challenge, but I think the bigger challenge we have right now is the supply chain side, which is still around 12 to 15 months.

Roddie Mackenzie -- Senior Vice President of Marketing, Innovation, and Industry Relations

I was going to supplement that just with a comment that, as we look at the latest projections from foreign leaders there. The discussion is just for sixth and seventh gen rigs that you're expecting to see something like 15 to 20 floater reactivations in the next year and a half. Well, we know that's not possible. So, to the Keelan's point, I think there's going to be a tremendous pressure on the supply chain here, and I think we're only just beginning to see the demand for reactivation.

So that's only going to get worse.

Keelan Adamson -- President and Chief Operating Officer

In the positive side of all that is our customers are starting to recognize that which feeds directly and to what Roddie was saying earlier, that our customers are approaching us with urgency, and quietly actually in the direct negotiations to try to secure the assets that are going to be available. Because they know if they don't, they're not going to have availability at all, it's going to take a little bit longer than they want to start their campaigns, they're going to have to pay more for it because they'll have to pick to the reactivation and the upgrade in the mode. So, all of that bodes well for us and continued progression day rates.

Thomas Johnson -- Morgan Stanley -- Analyst

Absolutely. Thanks. I'll turn it over now.


Thank you, sir. We will now go to Greg Lewis calling here from BTIG. Please go ahead, sir.

Greg Lewis -- BTIG -- Analyst

Hey, thank you. Thank you. And good morning, everybody. I think sometimes we forget when the markets rolling higher or how quickly it can roll higher.

I guess Roddie, this is probably for you. As you think about the different basins and just kind of piggybacking on the press releases from last night, is there any way to characterize the type of duration demand you're seeing in different basins, i.e., as we look at opportunities in West Africa? Are those more term duration work versus what you're seeing and maybe Gulf of Mexico? Any way to kind of parcel that out, whereas we look ahead, could we see some more multiyear contracts or is it really broad based?

Roddie Mackenzie -- Senior Vice President of Marketing, Innovation, and Industry Relations

Yes. So I'll deal with the broad base first because that's the easy bit. So if we compare the number of rig years that are out there and as prospects, since Q4 that has increased 50%. But that's a big, big movement in our business.

So in terms of the regions, yes, I think, we're just seeing across the board be yes, there's one or two places that they're still shorter terms. But I think because of the place that we're in the industry and the call and oil and gas to increase production, I think there's just a significant move toward delivering developments and kind of getting on with it, so to speak. So we are seeing, an Africa, there certainly multiyear deals out there. In the U.S.

Gulf of Mexico, that's what you're going to see going forward, I think, was very much kind of well to well, base stuff. But obviously, with the last couple of fixtures out there, I think you're going to see a year being added to rigs, two years, and in some cases more. But the one that's really moved the needle was Brazil. So Petrobras are really getting after it now.

So when they have the assets that they need the assets that they want and they certainly have the prospects and the developments that take multiyear requirements. So, I think we had commented on this before, and certainly in Jeremy's prepared remarks, but there are, there's still a huge amount of unsatisfied demand in Brazil at the moment just on the tenders that are out there today. So I think you'll probably see most of the longer-term stuff coming out of Brazil. And of course, we're very pleased to see that, with the last couple of announcements we've had, we've been able to move those data rates up so that we're in a position now that it is interesting to pick up long-term work because the day rates really support very high EBITDA margins.

Greg Lewis -- BTIG -- Analyst

OK. Great. Thank you for that. And then just, Jeremy, in your prepared remarks and I don't know if Roddie wants to respond to this question.

But I think in your prepared remarks, you mentioned about the potential for, kind of best, maybe even some of the best-in-class rigs leaving the North Sea market. As we look across your fleet, you definitely have some high-quality rigs that could probably go earn more money elsewhere outside the North Sea given where rates are, which had, I guess tightens the North Sea market further. Is that -- and I guess we saw that Stena IceMAX rig in Canada, is that, like, could we see Transocean move rigs out of the North Sea to other markets here, where maybe just the profitability is just a little bit better?

Jeremy Thigpen -- Chief Executive Officer

Of course. Yeah. I mean, we explore every opportunity out there to maximize value with our assets, there's absolutely no doubt. I will say, to the extent that we can command appropriate day rate in the Norwegian market.

We would prefer to keep our asset and our crews there because mobilization and recruiting always introduces some risk, but we look at every opportunity to maximize value. And, of course, we've looked at opportunities outside of Norway with some of the assets that are currently there. And we'll continue to explore those opportunities as they arise. I was just going to add to think, especially when you see some of the assets that are idle at the moment, you're definitely going to see competitors moving some of those rigs out, primarily as you described, because they can make a better margin, so higher cost and in Norway combined with kind of near-term softness in that market.

You're going to see these guys move from, perhaps making 30%, 40% EBITDA moving into West Africa, moving into parts of Asia, and the Golden Triangle and be able to push that up to 50%, 60% evidence. So, yes, there's clearly a case for that to happen, and I think we're probably not the only ones talking about that.

Greg Lewis -- BTIG -- Analyst

And so and just in just following up on that, and then I'll be quiet. I guess what we've seen over the last 18 months has really been a drillship renaissance in rates and anything moving out of the North Seas is the semi. As we think about that, like it sounds like, based on your comments, that thing that spread between drillships and semis looks ready to converge. Is that kind of a fair way to think about it?

Jeremy Thigpen -- Chief Executive Officer

The reason, I think, there's basically a lack of drillship availability. And what you have to remember is a lot of what we describe as the harsh environment assets were designed, and in many cases outfitted to work in ultra deepwater. So they are very capable, very multifaceted machines. And to your point earlier, I do think when some of these rigs move out of Norway, highly regulated and move into some places that are a little easier to do business, and support much higher EBITDA margins.

I don't think they go back. I'll be quite honest. I think once you see some of these rigs move out there, they'll be out for many, many years.

Greg Lewis -- BTIG -- Analyst

OK. Great. Thank you all for the time. Have a great day.


Thank you much, Mr. Lewis. We'll now go to David Smith calling in from Pickering Energy Partners. Please go ahead, sir.

David Smith -- Pickering Energy Partners -- Analyst

Hey. Good morning and thank you for taking my question. Historically, when we see day rates moving up, contract terms and conditions are also improving in the background. So I'm curious if you can give us any color around EMCs, particularly around bonus opportunities, non-productive time allowances, and cancellation provisions.

Jeremy Thigpen -- Chief Executive Officer

Yeah. So, I think that is, yes, generally the case. Certainly, the kind of the fringe benefits, if you would or they are, you'll probably see where certain services may have been rolled into the day rate before they're now being called out separately. So, that's good to see and that's often why we have the discussion about the clean rate and then the compounded rate.

But certainly, in terms of bonuses, yes, that's very much a thing to play. I think you're going to see, especially in Norway in the next little while, several contracts that increase their bonus potential on them. So not only do you see a higher base dairy on the rig, but you also see a higher bonus opportunity. And most recently, we signed a couple ourselves on some of the ships that have very substantial bonus opportunities, and we're kind of excited to see how that goes.

But I think it's just a way of operators being able to provide some extra value to us and themselves in a market that's really getting tight. So, yes, you are seeing improved terms and conditions in contracts and increases and bonuses.

David Smith -- Pickering Energy Partners -- Analyst

Thank you.

Keelan Adamson -- President and Chief Operating Officer

I was just going to say that we all had to give away during the downturn, customer wouldn't pay for reactivations mobilization, we're starting to see that now. Couldn't get downtime banks waiting on weather was an issue. And so, and our customers just pushed a lot of risk on to us on the other drilling contractors and so clawing all that back during this time is really been part of our key focus in addition to increasing the day rate.

David Smith -- Pickering Energy Partners -- Analyst

I really appreciate the color. Follow-up is just, curious on what you're seeing around customer interest and exploration, especially for the IOCs, if it's still mostly near field exploration or if you're seeing any growing interest in frontier exploration?

Jeremy Thigpen -- Chief Executive Officer

Yeah. No, I think we are. And actually, I think you saw on the downturn, there was a big focus on immediate production measures. So, a lot of work overwhelming stimulus wells, those kind of things.

Now, we're seeing a steady increase in everything else. So certainly, we are seeing more explanation, we basically are getting to the point that, the major operators are essentially liquidating their assets as they produce without replacing reserves. So, we've talked about this for quite some time, but reserve replacement ratio is going down. We've noted that some of the majors Exxon recently, were quite vocal about that, that they simply have to start exploration again and doing a lot of replacement of reserves and getting those assets back on the balance sheet.

So, yes, definitely more explanation, more delineation wells than we had in the downtime, probably for many, many years.

David Smith -- Pickering Energy Partners -- Analyst

Thanks again and congratulations on the quarter and the solid contract.


Thank you, Mr. Smith. We'll now go to Fredrik Stene calling in from Clarksons Securities. Please go ahead, sir.

Fredrik Stene -- Clarksons Platou Securities -- Analyst

Hey, guys, and I think I've to equity the rest of the people here that you had the fare very impressive contract here, And I think that should give a definitely investor sound, some ether on the cash flow that they're going to generate going forward. But my question relates to the North Sea since a lot of the older stuff has been covered already. You said that in your prepared remarks, you could look at the market that could be sold out in 2024. And there are several reasons for that, particularly some assets that might leave the area.

But I think for your sake, what I usually call for Equinor rig the enabler encouraging during to Equinox. At least from my side and the discussions that I've had with investors, the bonds and then the depth tied to those rigs is something that people would also like clarity on in addition to the ERCF. So, I was wondering if you could provide any color as to, are you having discussions with Equinor now, when would it be fair to potentially see an update around contract extensions on those rigs? And do you have anything you could share on rate levels or term that you think would be fair to sue for such extensions on that quartet?

Jeremy Thigpen -- Chief Executive Officer

Yes. Hey, look, so, on the contract side, I'll cover them for pass over to Mark. But yes, we're obviously not going to reveal what we're working on this. We are in discussions with Equinor for extensions on some of those rigs, and when you talk about the near-term softness, that's the reason that these rigs are going to leave the market.

And our case, we're looking to keep them there as Jeremy and Keelan had mentioned before, we much prefer to keep our crews in Norway together. But we're, we're confident you're going to see a few fixers come out in the next month or two that's going to help clarify that situation. But on the market side, I think we're in discussions with Equinor but also several other end players. And as we mentioned before, the rigs are very capable to work outside of Norway as well.

Mark Mey -- Executive Vice President and Chief Financial Officer

The first week any kinds of contract in December of this year. So we have -- what's the other ideas and how to secure those rates in different ways? So I think we have options. And I just request that you be a little patient.

Fredrik Stene -- Clarksons Platou Securities -- Analyst

I will be patient for sure, Mark. Thank you. Just another one from me as well, in terms of potential reactivation. So I think we're going into territory now let's just say we're the economics, at least of the activation starts to make sense.

And one thing is the supply chain issues that might limit the amount of time it takes them out. But if you were to reactivate some of these rigs, and kind of off the top of my head, I would say that the cause of the lack of rigs in Brazil could potentially be opportunities for stack capacity as well. Do you have any, I know that are differences between the assets here, but do you have any product quality prioritized list of which rigs you would prefer to take out first if you have the opportunity?

Jeremy Thigpen -- Chief Executive Officer

Yes. Clearly, we do. We have three, seven gen rigs currently in Greece. We have a one stag radian in West Africa.

So rigs that are warmer have will get first priority followed by the highest specification that's like the seven gen rigs in Greece.

Fredrik Stene -- Clarksons Platou Securities -- Analyst

OK. Thank you very much. I think that's all for me. This time I'm looking forward to following you over the next few months.


Thank you, sir. Today's last question will be coming from Mr. Karl Blunden calling you from Goldman Sachs. Please go ahead, sir.Karl BlundenHi.

Good morning. Thanks for the time. Congrats on the contract and liquidity progress. Just a question on the new contracts from last night, with those, allow you to raise incremental secured debt and further augment the liquidity position you have right now?

Jeremy Thigpen -- Chief Executive Officer

Yes, sir. On the Conqueror for those two years, I think combining that rig with another rig could provide an opportunity to raise additional secured debt against that. On the Petrobras 10,000, no, that is a seller lease agreement already back in that rig contracts. So now that rig is collateral for existing transaction.

Karl Blunden -- Goldman Sachs -- Analyst

And just to follow up. I think you mentioned some of this briefly in the prepared remarks. But should we still expect some concrete news on the Petrobras eight rig tender in the near-term and just kind of any thoughts on your involvement in that? It would be very helpful.

Keelan Adamson -- President and Chief Operating Officer

So, there's several tenders out there that are skilled to be awarded. And then you've got the what they what they describe as the full tender that bids for that go in, I think in about two weeks' time. So, you'll see that when the bids go and they get opened right away because it's kind of like a public tender. So pretty quickly, you'll be able to see the rate levels of all the different players.

I don't think there are that many rigs that will be immediately available in country. So, expect to see several from outside. And with the constraints, as we've mentioned before about reactivating rigs moving them into country will be interesting to see just how many rigs out there and what kind of rate levels that are. It's obviously a very big tender in terms of the number of rigs.

So we're kind of excited to see that. And certainly we will play our part in that and hope to be successful to varying degree, but we'll have to wait and see, but you should find out in about two weeks.

Karl Blunden -- Goldman Sachs -- Analyst

Got it. Thanks so much.


Thanks so much, sir. Ladies and gentlemen, that will conclude today's question-and-answer session. I would like to turn the call back over to Ms. Johnson for any additional or closing remarks.

Thank you.

Alison Johnson -- Investor Relations

Thank you, George. And thank you everyone for your participation on today's call. We look forward to talking with you again when we report our third quarter 2022 results. Have a good day.


[Operator signoff]

Duration: 0 minutes

Call participants:

Alison Johnson -- Investor Relations

Jeremy Thigpen -- Chief Executive Officer

Mark Mey -- Executive Vice President and Chief Financial Officer

Thomas Johnson -- Morgan Stanley -- Analyst

Roddie Mackenzie -- Senior Vice President of Marketing, Innovation, and Industry Relations

Keelan Adamson -- President and Chief Operating Officer

Greg Lewis -- BTIG -- Analyst

David Smith -- Pickering Energy Partners -- Analyst

Fredrik Stene -- Clarksons Platou Securities -- Analyst

Karl Blunden -- Goldman Sachs -- Analyst

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