Transocean Ltd (RIG) 2022 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to Q2 2022 Transocean Earnings Conference Call. For information, today's conference is being recorded. At this time I'd like to turn the call over to your host Ms. Allison Johnson for investor relations. Please go ahead, ma'am.

Thank you, George. Good morning, and welcome to Transocean 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-AP financial measures are posted on our website @deepwater.com. Joining me on this morning's call are Jeremy Thigpen, chief executive officer, Keelan Adamson president, and chief operating officer Mark May 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 SCC 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 our order, 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.

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 is the most promising it has been in many years.

Globally, we continue to face an energy crisis resulting from years of underinvestment and oil and gas reserve 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 the consequence, the long term replacement of hydrocarbon reserves has consistently fallen short at production levels and have consequently depleted global inventories driving barrel and end product crisis to near record highs. This consistent short fallen production leads us to conclude that we are in the early stages of a sustainable recovery.

Now to our results in a summary of global offshore drilling markets and fixtures. As reported in yesterday's earnings release for the second quarter transaction delivered adjusted EBITDA of $245 million on $722 million in 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 up time in excess of 96% and revenue efficiency of 97.8%, which was supported by strong contractual bonus conversion. Not withstanding our solid operating performance and the backdrop of a strengthening offshore drilling market illustrated by our recent fleet status report in 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 in our recent fixtures. We continue to see steady improvement in (inaudible) dates, 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 in 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 NPD, 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 Spitzbergen at a rate of $3500 per day, extending the current firm term through June, 2023. We also signed a nine-well contract with Elanor for the transition Spitzbergen 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 Anyo energy and Harbor energy for the Paul B. Lloyd 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 customer's 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 on 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 KG one 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 an 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 is the latest catalyst for recognition of this critical situation, it opened the entire world 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 plus agreed to moderately increase production at the behest of large oil consuming countries chiefly the United States. OPEC plus producers, however, appeared to have little or no spare capacity raising the question of whether these actions will reduce short and long term oil prices or simply contribute to sustained volatility. Indeed, one of the leading energy research consultancies estimates, the spare capacity within OPEC plus 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 would decline by 9 million barrels per day by 2025 and 20 million barrels per day are 41% by 2030.

Additionally, according to rise (inaudible) energies 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 BP's most recent statistical review of world energy 63% of global electricity is generated by fossil fuels with over a quarter 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 EMP 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 and 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 drill ship utilization remaining above 90% and we believe further tightening is on the horizon. In June (inaudible) revised its year over year offshore Deepwater EMP investment growth projection to 28%, which is double its March projection driven by higher service costs and additional anticipated requirements in Brazil, Giana, 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 a competitor's asset with nearly 90 million in upfront payments to partially cover mobilization, reactivation and upgrade costs bringing the total equivalent day rate above $600,000 per day. A move we take is recognition by one of our largest customers that the market is growing increasingly tight for the highest specification drill ship fleet. The latest projection by firmly 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 convince between now and 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 multi-year agreements in the US Gulf of Mexico. Some of which have not appeared on any of the ENSO reports today.

There have also been constructive developments in the 20K market. As you likely know, shell recently assumed 51% ownership of the project formally known as north plat, which they have since renamed Sparta. The agreement for another drilling contractor's vessel that was initially contracted by total energies for north plat was recently terminated and we believe we are now very well positioned to secure this work if and when the project is retendered. As a reminder, in addition to the 20K well control equipment that will be installed on the Deepwater Titan and the Deepwater Atlas, both rigs are also outfitted with industry leading 1700 short term hoisted 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 US Gulf of Mexico in Q4, where contract preparations will be completed prior to commencement of our maiden 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 in incremental Deepwater rig demand. Specifically in Brazil, there are 10 opportunities comprising in excess of 21 rig years of demand. One of these opportunities is the Petrobras multi-year 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 its 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 commenced within the next 18 months. A number of these programs are multi-year opportunities with multiple NOCs and IOCs, as an example, E&I is currently tendering for two rig lines each at 18 months commencing between Q1 and Q2 next year. Similarly, Shell is looking to secure an asset for 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 rig 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 three rigs. Additional demand in India 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 and sanctioning and contracting activity anticipated by year end as 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% from 82% last quarter. It's important to note that we also expect to see several of those assets leave the harsh environment market for higher margin work in benign environments, which will further strain supply. Consequently, we believe rates in Norway will continue the upward trajectory we've seen with our recent fixture on this (inaudible). In fact, the latest third-party projections suggest we could see base day rates, excluding bonus potential exceed $400,000 per day in 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, imbalances. 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 strengthen our balance sheet, we reaffirm the message we have conveyed for the last several years. Liquidity and de-leveraging is a 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 stacked 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 it 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 our 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 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 indicated offshore drillers will continue to play a vital role in the production of hydro carbons for the foreseeable future. For transaction, 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 fleets 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 US 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 improves 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 additive suggests fuel consumption can be reduced by up to 6%, depending upon engine loads. To date, we have worked with two customers in the US Gulf of Mexico to adopt and implement the additive and are in conversations for additional implementations.

In conclusion, our industry leading back law, 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 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 leveraging our balance sheet to safeguard and create value for our shareholders. I'm now turn the call over to Mark. Mark?

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

As reported in our press release, which includes additional detail on our results for the second quarter of 2022, we reported a net loss (inaudible) controlling interest of %68 million or 10 cents per (inaudible) 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 close at our results, during the second quarter, we delivered adjusted (inaudible) revenues of $722 million at an average day rate of $358,000. Revenues above our previous guidance and reflects better than forecast at uptime, higher bonus conversion and higher reimbursables. Operating and maintenance expense in a second quarter was $433 million. This is less than guidance, primarily due to timing or certain maintenance activities.

Turning to cash flow and the balance sheet with the second quarter with total liquidity of approximately $2.5 billion, including unrestricted cash and cash equivalent of approximately $729 million, approximately $400 million of unrestricted cash for debt service and $1.3 billion from our (inaudible) evolving credit facility. Before I update guidance, I'm pleased to share that we have closed an amendment to our evolving credit facility, extending its maturity through June of 2025. The extended RCF has 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 amended facility also permits us to increase the aggregate amount of (inaudible) by up to $250 million.

I'll now provide an update on our expectations for our third quarter and full year financial performance. For the third quarter of 2022, we expect adjusted drilling contract drilling revenue to be approximately $670 million based on an average fleet wide revenue efficiency of 96.5%. The quarter of a quarter decrease is largely interpretable to low utilization (inaudible) time on the Asguard development rule of three in the balance. For the full year 2022, we're anticipating adjusted contract drilling revenue to be approximately $2.6 billion down from our prior guidance by $100,000,000 due to the additional adult time mentioned above. To provide context for thefore mentioned adult time, not that is not a result of a lack of contract drilling opportunities as our recent fleet status report and the $1.2 billion of contract back (inaudible) yesterday, but rather primarily a result of supply chain challenges faced by our customers. For example, in the Gulf of Mexico, several operators have been struggling to access tublus and consumables while they work with such 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 not alter our mid to longer term outlook, we expect third quarter O&M expense to be approximately $464 million. The quarter of a quarter increase is primarily applicable to timing of maintenance projects across the fleet.

For the full year 2022, we anticipate O&M experience to be approximately 1.7 billion. We continue to experience pressure on employee costs and increased pricing from our vendors, significant portion of our (inaudible) expenditures fall under our comprehensive services agreements. These CSA contained provisions, capping annual inflation and limit exposure to rising costs. Additionally, our 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 result in labor inflation over the next 12 to 18 months, we expect gen 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. 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 capitalized interest, our forecast will be approximately $150 million for the third quarter. This represents approximately $100 billion for our new build (inaudible) predominantly the 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, projected to be approximately $1.1 billion reflecting $550 million dollars remaining capacity of our revolving credit facility and including restricted cash of approximately $280 million dollars, which is primarily reserved for debt service and anticipated secured financing of our second eight generation draw ship deport Titan. This liquidity forecasting includes an estimated 2022 capital expenditures and capitalization of $1.2 billion and a 2023 CapEx expectation of $200 million. The 2022 CapEx includes $1.1 billion related to our new builds and $60 million for maintenance CapEx. As always our guidance excludes speculative reactivations or upgrades.

In conclusion, strengthening the balance sheet and extending our liquidity runway remain our priority. The extension of our evolving credit facility is the first in a series of actions we will take to address our balance sheet and financial flexibility. We also anticipate to continue to utilizing our open end to market equity offering program, which we have received aggregate cash proceeds of $ 367 million as of June 30th, as you're probably aware our first and highly successful ATM equity program is limited to $400 million. We fully anticipate renew authorization for another $400 million. As always you can expect us to continue to (inaudible) capital and opportunistically access capital markets as, and when we believe it makes sense. (inaudible) have now comfortably surpassed level nessesary to generate cash flow sufficient to meaningfully support to leveraging our balance sheet over time. This remains our primary priority and as we execute accordingly creates value for shareholders. This concludes my prepared comments and I'll turn call back over to Alison.

Thanks Mark. George. We're now ready to take questions as a reminder to the participants, please limit yourself to one initial question and one follow up question.

Thanks so much Ms. Johnson. Ladies, gentlemen, if you have any questions, please press star one on your telephone one keypad at this time. Today's first question is coming from Mr. Thomas Johnson, calling you from Morgan Stanley. Please go ahead. Your line is open, sir.

Hi, thanks. Good morning and congratulations on (inaudible) 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 and when the day rates are actually printed to the public. Just to help the sell side, place expectations on where day rates could be going specifically on the drill ship side of things, A could you give us some timeframe for when negotiations were taking place for the two most recent contracts announced and B, could you update us on how conversations are going to customers, relative to the day rates you just disclosed. Thanks.

Hey, this is Roddie. I'll take that one. Look appreciate the compliment there, but I think what I'd first like to say is that you, those may look 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. Yes, they look 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. It used to be that you saw, six, nine months sometimes between when we were answering tenders and when a fixture would be made, that's not the case no. The majority of the negotiations we're involved in are direct negotiations and not part of a tender. Then 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. I think you're going to see an acceleration there because especially for the high specification units there simply is very little availability. That bodes very well.

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 right iron for their prospects so, of course, having higher specification units is important in that realm. 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. That means reactivations and moving cold assets back into the market, which obviously it's not as desirable as picking up one of the highest spec rigs in the world it's hot and already performing very well.

Great. Then just staying on the topic of reactivation, I think last quarter you stated that reactivations would likely take 12 plus months given supply chain lead times. I guess, could you just update us on reactivation timelines where the biggest constraints on the supply chain are, and maybe how labor availability is going to play a role in limiting the number reactivation that competevely take place over the next 24 months?

Yeah. Thomas, this is Kelan and a very good question. I think our guidance remains the same. We're probably looking at over 12 to 18 months for a reactivation based on the limitations in the supply chain at this time. Obviously, we're hoping that that will improve as this situation stabilizes. From a labor point of view, that is something that the industry is used to. 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. We have access to people. We can recruit and develop those people in a very timely fashion. 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.

Hey, I was going to supplement that just with a comment that as we look at the latest projections from firmly the discussion is just for sixth and seventh gen rigs that you're expecting to see something 15 to 20 floater reactivations in the next year and a half. Well, we know that's not possible. To Kelans 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 was.

Yeah. The positive side of all that is our customers are starting to recognize that which feeds directly into 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 they're 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 and they're going to have to pay more for it because they'll have to pick the reactivation and the upgrade and the mode. All of that bodes well for us in continued progression and day rates.

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

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

Hey, thank you. Good morning everybody. Yeah, congratulations. I think sometimes we forget when the market's rolling high or how quickly it can roll higher. I guess Roddie, this is probably for you, as you think about the different basins, and just piggybacking on the press releases from last night, is there any way to characterize the type of duration demand you're seeing and different basins IE, as we look at opportunities in West Africa, are those more term duration work versus say what you're seeing in maybe the Gulf of Mexico, any way to parcel that out, where as we look ahead, could we see some more multiyear contracts or is it really broad based?

Yeah, so I'll deal with the broad based first because that's the easy bit. If we compare the number of rig years that are out there as prospects since Q4 that has increased 50%, so that's a big movement in our business. In terms of the regions yeah, I think we're just seeing it across the board. Yeah, there's one or two places that they're still shorter terms, but I think because of the place that we're in, in the industry and the call and oil and gas to increase production, I think there's just a significant move towards delivering developments and getting on with it, so to speak. We are seeing in Africa, there's certainly multi-year deals out there, in the US Gulf of Mexico, that's what you're going to see going forwards. I think it was very much well to well based 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 in some cases more. The one that's really moved, the deal is Brazil. Petrolbras are really getting after it now. When they have the assets that they need, the assets that they want they certainly have the prospects and the developments that take multi-year requirements. I think we had commented in this before, and certainly in Jeremy's prepared remarks that there's still a huge amount of unsatisfied demand in Brazil at the moment just on the tenders that are out there today. 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 day 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.

Okay, great. Thank you for that. Then just Jeremy and your prepared remarks. 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 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 then that I guess tightens the North Sea market further and I guess we saw the STENA ICEMAX rig in Canada is that could we see transition move rigs out of the North Sea to other markets here where maybe just the profitability just a little bit better?

Yes. Of course Yeah. 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 recurring always introduces some risk, but we look at every opportunity to maximize value. Of course, we've looked at opportunities outside of Norway with some of the assets that are currently there and will continue to explore those opportunities as they arise.

I was just going to add, I 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 in Norway combined with 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% EBITDA. Yes, there's clearly a case for that to happen and I think we're probably not the only ones talking about that.

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 drill ship, Renaissance and rates. In anything moving out of the North Sea is a semi. As we think about that it sounds based on your comments like that spread between drill ships and semis looks ready to converge, is that a fair way to think about it?

Yes, I think it is I think there's basically a lack of drill ship availability and what you have to remember is a lot of what we describe as the harsh environment assets we're designed and in many cases outfitted to work in ultra-deepwater. So they are very capable, very multifaceted machines. 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 or be quite honest. I think once you see some of these rigs move out, they they'll be out for many years.

Okay, great. Hey, thank you all for the time. Have a great day.

Thank you, Mr. (inaudible). We'll now go to Mr. David Smith calling in from Pickering Energy Partners, please go ahead sir.

Hey, good morning. Thank you for taking my question.

Go ahead

Thank you. Historically, when we see day rates moving up contract terms and conditions are also improving in the background. I'm curious if you can give us any color around TNCs, particularly around bonus opportunities, non-productive time allowances, and cancellation provisions.

Yes. I think that is yes, generally the case certainly the fringe benefits if you would are there 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 the bonus potential on them. Not only do you see a higher base day rate on the rig, but you also see a higher bonus opportunity. Most recently we signed a couple ourselves on some of the ships that have very substantial bonus opportunities. We're 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. Yes, you are seeing improved terms and conditions and contracts and increases and bonuses.

Thank you.

I'll just add to that just -

Yes.

I was just going to say some of those things 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 bags waiting on weather was an issue and our customers just pushed a lot of risk onto us and the other drilling contractors. Clawing all that back during this time is has really been part of our key focus in addition to increasing the day rate.

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 your field exploration or if you're seeing any growing interest in frontier exploration.

Yes, no, I think we are actually I think you saw on the downtown, there was a big focus on immediate production measure. A lot of work over Wells stimulus, Wells, those kind of, things. Now we're seeing a steady increase in everything else. Certainly we are seeing more exploration. We basically are getting to the point that the major operators are essentially liquidating their assets as they produce without replacing reserves. We've talked about this for quite some time about reserve replacement ratios going down. We've noted that some of the majors Exxon recently were quite vocal about 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. Yes, definitely more exploration, more delineation Wells than we had in the downturn probably for many years.

Thanks again, and congratulations on the quarter and the solid contracts.

Thank you, Mr. Smith. We'll now go to Mr. Frederick Sten calling in from Clarkson securities. Please go ahead sir.

Hey guys. I think on the equity the rest of the people here that you had a very impressive contract here and I think that should give definitely investors some on the cash flow that you're going to generate going forward. My question relates to the North Sea since a lot of the other 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 the four Equinor rigs, the enabler encourage endurance and Equinox, at least from my side and the discussions that I've had with investors the bonds and the depth prior to those rigs is something that people would also clarity on in addition to the (inaudible). So I was wondering if you could provide any color as to are you having discussions with Equinor or now when would it be fair to potentially see an update around contract extensions on those rigs? Do you have anything you could share on rate levels or term that you think would be fair to assume for such extensions on that quater?

Yeah. Hey look. So on the contract side, I'll cover that before, pass it over to Mark, but yeah, we're obviously not going to reveal what we're working on, but we are in discussions with Equinor for extensions on some of those rigs and when you talk about the near terms softness, that's the reason that these rigs are going to leave the market. In our case, we are looking to keep them there as as Jeremy and Kelan had mentioned before. We much prefer to keep our crews in Norway together, but we're confident we're going to see a few fixtures 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 players. As we mentioned before, the rigs are very capable to work outside Norway as well.

Fredrick, you're aware that the first rig or any kinds of contract in December of this year so we have time, we also have other ideas on how to secure those rigs in different ways. I think we have options and I just request that you'd be a little patient. That's all

I will be patient for sure Mark. Thank you. Just another one from (inaudible), in terms of potential reactivations I think we're going into territory now, as you say, where the economics at least of reactivation starts to make sense. One thing is the supply chain issues that might limit the amount of time it takes to take them out, but if you were to reactivate some of these rigs and off the top of my head, I would say that the lack of rigs in Brazil could potentially be opportunities for stack capacity as well, do you have any I know there are differences between the assets there, but do you have any prioritized list of which rigs you would prefer to take out first if you have the opportunity?

Clearly we do. We have three seventh gen rigs currently in Greece. We have a (inaudible) in West Africa. Rigs are warmer, that will get first priority followed by the higher specification that just like the seventh gen rigs in Greece.

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

Thank you, so much sir. Today's last question will be coming from Sir Carl London[?], calling you from Goldman Sachs. Please go ahead, sir.

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

Yes, Carl. On the the Conqueror for those two years, I think combining that rig with another rig could provide us opportunity to raise additional secured debt against it. On the Petrobras 10,000. No, that is a seven lease agreement already back in that rigs contract. No that rig is collateral for existing transaction.

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

Yeah, I'll take that one. Yes. There's several tenders out there that are still to be awarded. Then you've got the, what they describe as the pool tender that bids for that go in and thinking about two weeks time. You'll see that when the bids go in, they get opened right away because it's a public tender. 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. With the constraints, as we've mentioned before, about reactivating rigs, moving them into country it will be interesting to see just how many rigs are there and what rate levels there are. It's obviously a very big tender in terms of the number of rigs. We're excited to see that. Certainly we will play our part in that and hope to be successful to availing degree. We'll just have to wait and see, but we should find out in about two weeks.

Perfect. Thanks so much.

Thank you much, sir. Ladies and gentlemen, now we conclude today's (inaudible) session, to turn the call back over to Ms. Johnson for any additional close remarks. Thank you.

Thank you, George. 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.

Thank you very much Maa'm. Ladies and gentlemen, that will conclude today's conference. Thank you so much for your attendance. You can now disconnect. We wish you a very good day. Goodbye.