Transocean (RIG) Q2 2020 Earnings Call Transcript

Transocean (RIG 2.16%)
Q2 2020 Earnings Call
Jul 30, 2020, 9:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

Ladies and gentlemen, good day, and welcome to the second-quarter 2020 Transocean earnings conference call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Brad Alexander, vice president, investor relations.

Please go ahead, sir.

Brad Alexander -- Vice President, Investor Relations

Thank you, David. Good morning, and welcome to Transocean's second-quarter 2020 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, president and chief executive officer; Mark Mey, executive vice president and chief financial officer; and Roddie Mackenzie, senior vice president of marketing and contracts.

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 the current expectations and certain assumptions and are therefore subject to certain risks and uncertainties. Many factors could cause actual results to differ materially. Please refer to our SEC filings for more information regarding our forward-looking statements, including the risks and uncertainties that could impact our future results.

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

I'll now turn the call over to Jeremy.

Jeremy Thigpen -- President and Chief Executive Officer

[Inaudible] As we have since the beginning of the pandemic, we're continuing to work safely and remotely to do our part to prevent the spread of COVID-19. Therefore, please forgive any challenges associated with maintaining audio quality from speaker to speaker during this call. As reported in yesterday's earnings release, for the second quarter, Transocean delivered adjusted EBITDA margins of 42.5%, by generating $418 million of adjusted EBITDA on $983 million in adjusted revenue. Despite the unprecedented challenges associated with COVID-19, our experienced and committed teams delivered outstanding operating performance, driving a sequential improvement in our revenue efficiency to 97%, resulting in better than forecast revenue and EBITDA.

I want to take a moment to express my deepest gratitude to all of the men and women at Transocean, who are working through these most difficult times. Our crews have shown tremendous strength and resilience throughout this pandemic, and I would like to acknowledge the personal sacrifices that they continue to make each and every day to keep our rigs operating safely [Inaudible] our customers. Additionally, I would like to recognize and thank our shore-based teammates who have adapted well to working remotely. And despite the inconvenience and distractions associated with working from home, they have not missed a beat in supporting our operations and our customers.

Through the third quarter and the balance of the year, we will continue to take every precaution to keep our crews [Inaudible] second-quarter activity in addition to keeping our previously active fleet operational, we also initiated a number of new programs that contribute to our almost $9 billion of backlog. In Canada, the Transocean Barents kicked off a multiple program with Equinor. We expect to run through the third quarter. In Trinidad, the DD3 commenced a one-year contract with Shell in May.

[Inaudible] successful campaign in Equatorial Guinea with ExxonMobil. And depending on the success of this program, we are hopeful we can keep the DD3 working in-country beyond this current term. [Inaudible] 10-month drilling campaign [Inaudible] fleet. Just last quarter, we [Inaudible] through the success of the drilling program and the improvement in oil prices allow us change course and exercise an option for an additional well, which kept the India drilling into July.

Unfortunately, despite the success of the campaign, we see no near-term prospects for the India and are therefore in the process of cold stacking the rig. Moving to Asia, the DD1 completed her first full quarter of work on a campaign with Chevron in Australia, which remain [Inaudible] into the fourth quarter. In Malaysia, the Nautilus commenced activity with Petronas that is scheduled to continue into the first quarter of next year. Turning to the contracting front.

With the continued uncertainty regarding global energy demand and correspondingly challenged oil prices, contracting activity has been predictably disappointing. However, we are very encouraged to have executed a drilling contract for the industry's second ultra-deepwater 20,000 psi capable drillship, the Deepwater Atlas, with Beacon Offshore Energy for the highly anticipated Shenandoah project in the Gulf of Mexico. The Atlas will be the industry's most capable ultra-deepwater drillship when delivered and will include, among other upgrades, a three million pound hoisting system. The Shenandoah project is subject to a final investment decision by Beacon, which we expect by March of next year.

Prior to that time, we do not expect to incur any additional material expenditures for equipment purchases associated with the program. Conditioned upon sanction, the program and services would include the drilling and completion of four wells, which would involve commencing drilling operations in the first quarter of 2022 and should keep the rig under contract into the third quarter of 2023, resulting in a total contract value of approximately $250 million. Beyond the Shenandoah project, we are actively engaged in conversations with customers for additional opportunities in the Lower Tertiary of the Gulf of Mexico that will require a ship with the Atlas' enhanced capabilities. Importantly, these projects had expected start dates that should closely follow Shenandoah.

And since Transocean will be the only drilling contractor with the assets and experience to successfully execute in this most challenging of ultra-deepwater environment, we will be very well positioned to secure future contracts for the Atlas. Looking now at upcoming market opportunities. The contracting environment has improved marginally from when we last spoke three months ago, and oil prices were largely at or even below $20 per barrel. While oil prices are still not where we want or need them to drive demand, we saw emerging as we exited 2019, the recent recovery in oil prices to approximately $40 per barrel has encouraged our customers to begin revisiting the projects that we initially expected to start in 2020, but are now likely pushed into 2021.

In the U.S. Gulf of Mexico, a 10-well project starting in 2021 was just awarded by an independent producer. In Brazil, Petrobras has recently requested bids for two rigs both with terms of approximately three years for activity kicking off early next year in the Campos and Santos Basins. Additionally, we could see some further movement from IOCs in country following ExxonMobil's recent contracting of a drillship for initial drilling in the Santos Basin.

Furthermore, we believe Equinor is considering awarding a four-year contract in Brazil in the coming months, which could begin operations at the end of 2021. Speaking of Equinor, you will know that they recently awarded a multiyear fixture for a high-specification harsh environment semi in Norway. While the contract day rate was a step down from recently awarded fixtures, given the drop in oil prices and continued market uncertainty, we were encouraged to see base day rates remaining near $300,000 a day, with fairly significant upside opportunity tied to performance bonuses. Additionally, with the Norwegian government's recent enactment of favorable tax incentives for oil and gas operators related to offshore investments, we anticipate this market will stabilize and respond favorably to the investment incentive.

In Africa, we soon expect to see the first multiyear ultra-deepwater drillship award in Mozambique. We also think it is very likely we will see an 18-month award in Angola this year. Activity for both of these awards would begin in 2021. In Asia Pacific, we anticipate a five-well contract will be awarded this year for work offshore Australia, with activity commencing in 2021.

Additionally, we have been pleasantly surprised to see the emergence of a few opportunities for shorter duration work in other countries throughout the region. So while we are certainly disappointed that the ultra-deepwater recovery has been once again delayed, we take comfort in our almost $9 billion backlog, and we are becoming encouraged by various opportunities we see emerging in 2021 looking at our rigs, we continue to see the benefits of maintaining a young high-specification fleet as we continue to operate significantly more floaters than any other contractor. Consistent with our well-defined asset strategy, we have recently taken action to responsibly retire the semisubmersible Development Driller II and the Sedco 712. Beyond the asset ages, we continue to employ an objective criteria focused on cash flows when evaluating our fleet composition.

When the costs associated with maintaining, reactivating and/or operating an asset outweigh our view of its cash flow potential, we take prudent actions to remove the asset from our fleet. Despite our increased optimism, we remain pragmatic and recognize the challenges the industry and more specifically Transocean will continue to face in the near to medium term. As we entered the year, we were optimistic that the ultra-deepwater offshore recovery was beginning to take shape. However, as a result of the pandemic, the current demand for hydrocarbons has fallen significantly, thus impacting offshore contracting activity.

As a result, after thoughtful consideration, we recently took difficult decision to once again materially reduce our shore-based support costs, which Mark will address in his comments, to more closely reflect what we anticipate being our contracted rig fleet over the coming months. I would like to stress that personnel reductions are without question the most difficult decisions we make as an organization as our team is irrefutably the most qualified and capable group of people within the industry. We embarked on this global reduction in force, purely as a result of the unprecedented and unforeseen circumstances. We hope that we will be in a position to welcome many of these teammates back to Transocean as the offshore market recovers, and we have solid visibilities to sustainable growth.

I'd now like to take a -- to provide a few comments regarding the state of the market from our perspective as the leading offshore drilling contractor. As you know, a number of other contractors have either formally started the restructuring process, or taken steps that indicate that they are likely to do so in the near term. Given our strong backlog, strong operating performance and timely balance sheet transactions over the past several years, Transocean is not facing the distractions and challenges associated with the restructuring. As he does every quarter, Mark will provide an update on our liquidity runway and expectations in a few minutes.

As we watch the transformation of our industry unfold, we think that there's some very favorable data points in relation to Transocean, which I would like to detail. When the downturn began almost six years ago and many of our competitors went through their first restructurings, our customers, as you might expect, became more focused on the financial stability of drilling contractors and their other service providers. During this time, Transocean was able to further its position as the undisputed leader in ultra-deepwater and harsh environment drilling. As the second phase of contractor restructuring is now beginning to occur, we anticipate our position will continue to serve us well on the contracting front with the more active IOCs and NOCs preferring strong counterparties to safely, reliably and efficiently deliver their projects.

Different than doing the first group of restructurings, activity has fallen to unprecedented levels, which will result in extensive rig stackings and recyclings throughout the industry as we believe the cost to keep uncontracted rigs crude and in operating condition is prohibitive. As a result, marketable supply of rigs is likely to fall at a pace similar to the contracted rig count. Therefore, when oil prices stabilize at more favorable levels, an inflection in rig contracting should have an almost immediate and positive impact on dayrates due to the shortage of marketable rigs and the significant expense associated with reactivating stacked assets. At Transocean, we have strategically assembled the largest and most competitive floating fleet in the industry with the industry's most experienced crews.

We maintained the most contracted rig fleet with the strongest and most lucrative backlog, providing us with the visibility to future cash flows that we need to continue to invest in the training of our crews and the maintenance of our assets. As such, we are best positioned to survive this latest challenge and benefit from the eventual market recovery. In conclusion, we have accepted that a full-scale recovery in the deepwater offshore market will not begin before 2021. However, as the recent increase in oil prices has brought projects back into the fold, it has given us confidence that our customers will be ready to increase their offshore activity as oil prices continue to stabilize and become more supportive.

In the interim, we are committed to our customers to working with them to find the right contractual solution to enable their drilling programs, while operating safely at the highest performance levels with the industry's most capable assets. We are proud to have positioned ourselves as the clear leader in harsh environment and ultra-deepwater drilling and will continue to strategically refine our fleet to further enhance that position. As such, we expect that our marketed fleet will remain the industry's most utilized as we successfully navigate this downturn. 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. Lastly, I will provide an update to our liquidity forecast through 2021. As reported in our detailed press release, for the second quarter of 2020, we reported a net loss attributable to controlling interest of $497 million or $0.81 per diluted share.

After adjusting for unfavorable items associated with the impairment charges related to previously announced total retirements, we reported an adjusted net loss of $1 million. Further details are included in our press release. Highlights for the second quarter include: adjusted EBITDA of $418 million, reflecting strong fleetwide revenue efficiency, accelerated cost control actions and a legal settlement. Also due to early discussions with customers, agreements were reached regarding responsibility for costs related to COVID-19.

As a result of these arrangements, we mitigated what could have been a more negative impact on our quarterly financial performance. Fleetwide revenue efficiency exceeded 97%. This represents a 3% increase from our first-quarter results. We generated $41 million of free cash flow, which represents a sequential increase of $196 million.

It should be noted that this does not include $46 million related to the legal segment of a dispute that was paid in the first week of July. Consistent with our guidance, we generated approximately $87 million in cash from operations, an increase of $137 million quarter-over-quarter. During the second quarter, we generated adjusted contract drilling revenues of $983 million, driven primarily by strong revenue efficiency across the fleet and a legal settlement. Also in the quarter, the positive impact of early termination revenue from the Paul B.

Loyd was largely offset by the Deepwater Skyros remaining on standby rate for most of the quarter and delayed starts for the Deepwater Nautilus for DD3 due to COVID-19 travel restrictions. These delayed starts resulted in a lower-than-forecasted number of operating days during the quarter. Regarding the previously mentioned settlement, we recognized $177 million, representing net present value of $185 million settlement, adding equal installments of $46 million on July 1, 2020, June 1, 2021, June 1, 2022, and January 15, 2023. Additionally, we recognized approximately $20 million in legal fees in the second quarter associated with the settlement.

Operating and maintenance expense in the second quarter was $525 million, which is below our guidance due to the timing of certain shipyard projects and in-service maintenance and lower-than-expected costs associated with COVID-19. During the quarter, we recognized approximately $30 million of expenses related to COVID-19, of which approximately $10 million of these costs are reimbursable by our customers. Turning to the segments of cash flows and balance sheet. We ended the second quarter with total liquidity of approximately $3 billion, including unrestricted cash and cash equivalents of $1.5 billion and approximately $200 million of restricted cash for debt service and $1.3 billion from our undrawn revolving credit facility.

Furthermore, we forecast positive operating cash flow for the remainder of the year. As Jeremy mentioned, during the quarter, we undertook a difficult decision to reduce our shore-based workforce to fully reflect our expected operating activity for '20 and '21. As a result of these decisions, we will save approximately $80 million annually. Furthermore, we recognized severance charges of approximately $12 million in the quarter.

Let me now provide an update on our third-quarter financial expectations. For the third quarter of 2020, we expect our adjusted contract drilling revenues to be approximately $800 million, reflecting revenue efficiency of 95% fleetwide. This reflects lower activity at six rigs expected to complete their drilling campaign, including the KG2 finishing its contract with Chevron ahead of schedule and remaining warm stacked until their next fixture planned to start in November for Woodside. Furthermore, the Discoverer India, Discoverer Inspiration, Transocean Barents, Transocean Leader and Transocean Arctic will be completing their respective contracts during the quarter.

Except for the Inspiration, which we will warm stack in the U.S. Gulf of Mexico, we will cold stack these rigs. The Inspiration is well positioned for further midterm work in the Gulf of Mexico. This activity reduction is offset by a full quarter of operations on Deepwater Nautilus, the Leiv Eiriksson and the DD3, together with the Skyros drilling operations at four-day rate in July.

We expect third quarter O&M expense to be approximately $500 million. The quarter-over-quarter decrease also relates to a lower operating activity discussed above, including our estimates of approximately $14 million related to COVID-19 expenses and $6 million related to severance costs. These COVID-19 costs include, are not limited to, overtime paid, charter flights and boats for crew changes, extended quarantine prior to crew rotations and certain other logistical expenses. We expect G&A expenses to be approximately $45 million.

This includes approximately $1 million related to severance payments. Net interest expense for the third quarter is expected to be $150 million. This forecast includes capitalized interest of approximately $13 million, interest income of $1 million. Capital expenditures, including capitalized interest for the third quarter, anticipated to be approximately $80 million.

This includes approximately $50 million for our newbuild drillships under construction and $30 million of maintenance capex. Our cash taxes for the third quarter are expected to be approximately $12 million. Turning now to our projected liquidity at December 31, 2021. Including our undrawn revolving credit facility and potential securitization of the Deepwater Titan's contract with Chevron, our end of year 2021 liquidity is estimated to be between $1.2 billion and $1.4 billion.

This liquidity forecast includes an estimated remaining 2020 capex of $170 million and a 2021 capex expectation of $1.5 billion. The 2021 capex includes $1.4 billion related to our newbuilds and $100 million for maintenance capex. Please note, our capex guidance excludes any speculative rig reactivations or upgrades. In conclusion, while safety and operational excellence remain our primary areas of focus, we are acutely aware of the extreme dislocation in the energy business and especially oilfield services, including offshore drilling.

We recognize that our customers have significantly reduced their 2020 budgets, which eliminates the potential to recontracting rigs, complete any contracts this year. However, the potential longer-term hydrocarbon supply constraints implied by our customers' exploration and development projects encourages optimism and will remain constructive for 2021 and beyond in anticipation of a gradual increase in demand for energy and oil prices as the global conditions improve. Even so, we will continue to proactively manage our balance sheet and capital expenditure requirements while exploring all opportunities to reduce our costs. I'll now turn the call back over to Brad.

Brad Alexander -- Vice President, Investor Relations

Thank you, Mark. David, we're now ready to take questions. [Operator instructions]

Questions & Answers:

Operator

[Operator instructions] Our first question comes from Ian MacPherson with Simmons.

Ian MacPherson -- Simmons Energy -- Analyst

Thanks. Good morning everybody. Jeremy, I wanted to see if I could dig in on a little more detail on the Atlas opportunity. You said the initial 4-well program would be, I think you said, Q2 of '22 through the middle of '23.

Is the $250 million award to be finalized over an 18-month specific term? Or is that not the correct interpretation?

Jeremy Thigpen -- President and Chief Executive Officer

I'll start, but Roddie, why don't you correct me? It is well driven, and we anticipate that to take about 17 months.

Ian MacPherson -- Simmons Energy -- Analyst

OK, well driven. And will you -- are you contemplating any priced options?

Roddie Mackenzie -- Senior Vice President of Marketing and Contracts

No, that is correct. Yes, well driven. And the details of options and expected durations we're kind of not really going to talk about that until FID is made. But yes, it's certainly a very positive data point for us at the moment.

Ian MacPherson -- Simmons Energy -- Analyst

Absolutely. So congrats and good luck getting that over the finish line. And then also, I wanted to see if you can speak to the remaining capex as the rig will be spec'd and how much if any of that is included in the '21 capex that Mark just described, the 1.4 billion newbuild capex that will fall next year?

Jeremy Thigpen -- President and Chief Executive Officer

I'll defer to Mark on that one. Mark, you might be muted.

Mark Mey -- Executive Vice President and Chief Financial Officer

Yes. Could you ask that question again, please?

Ian MacPherson -- Simmons Energy -- Analyst

Yes. So I wanted to see how much remaining capex for the final build-out of the Atlas in total? And then how much of that might be included in the 1.4 billion newbuild spending that you outlined for next year?

Mark Mey -- Executive Vice President and Chief Financial Officer

So the 1.4 billion is almost equally spread between the two rigs. And except for some well control equipment, all of it is included in the 1.4 billion.

Ian MacPherson -- Simmons Energy -- Analyst

So the rig will be effectively fully built out or budgeted for within next year's spending?

Mark Mey -- Executive Vice President and Chief Financial Officer

Correct, yes.

Ian MacPherson -- Simmons Energy -- Analyst

Got it. OK. Thanks guys. Look forward to getting update on that one.

Mark Mey -- Executive Vice President and Chief Financial Officer

Thank you.

Operator

Thank you. Our next question comes from Connor Lynagh with Morgan Stanley.

Connor Lynagh -- Morgan Stanley -- Analyst

Yeah, thanks. Morning guys. There's a lot of questions out there as to what the impact of these bankruptcies across the industry are going to be. two sides of the question for you.

Are you concerned about your competitive position as competitors reemerge with clean balance sheets? On one hand, it would argue for them having a lower cost structure. On the other hand, bids at sub $200,000 a day suggests interest expense and return on capital weren't really major factors in bidding behavior. So where do you think that shakes out?

Jeremy Thigpen -- President and Chief Executive Officer

Yes. So it's interesting. And all I can do is look back at what we've seen recently and kind of walk through that and assume that that will replicate itself as we go through the second wave. If you think back to the first wave, you had companies like Pacific and the Seadrill and Ocean Rig and Vantage go through restructuring.

Out of all four of those, only Ocean Rig came out with a clean balance sheet. The rest came out with still pretty considerable debt, and so that would be one piece of it. I don't expect these companies to come out completely clean. I think they're still going to have quite a bit of debt.

It will be pushed to the right and certainly be reduced from what it is today. And I doubt that they're going to come out with a lot of cash. And as you well know, it takes a lot of cash to operate and maintain these assets and certainly a lot of cash to reactivate them. So I'm not sure that they're going to be in a much better position than we are, first of all.

So I'll just detect that one now. The other thing we saw was when these companies were going through the restructuring process, we increased our market share. And I can't tell you it was because our customers were definitely choosing the more financially stable, less distracted organization, but it sure showed up in the way that we won contracts because we were not below better during that time. So I think at least in the interim period, I think we have a decided advantage because we're not facing that uncertainty in those distractions.

And then we'll just see how these companies come out of the restructuring process.

Connor Lynagh -- Morgan Stanley -- Analyst

Got it. You alluded to the second part of my question, which is everyone is in cash preservation mode right now. It seems like cold stacking is the obvious preferred option for most rigs that are going idle. How should we think through the cost of reactivating rigs that maybe really never came back this cycle? Or were -- was cold stacked early in the cycle? And how do you think about how the cost curve of those idled assets is changing over time?

Jeremy Thigpen -- President and Chief Executive Officer

We've been on record saying this quite some time. No asset is the same and no preservation techniques are the same. And we've looked at different rigs anywhere ranging from 20 to 25 million on the low end to an excess of 100 million on the high end. So if you just wanted to take the midpoint of that, it's a really significant investment to bring one of these assets back online.

And if you look at the kind of contracts that have been awarded recently with respect to dayrate and term, there aren't many that would justify it. And so as we said in the prepared comments, is we see rigs roll off contract. And I think over the course of this year and next, we expect 89 to 90 rigs to roll off contract? Those rigs go to cold stack because people can't afford to keep them active in crude. It's a pretty big check that one has to write in order to reactivate those assets.

And the dayrates today and the terms today won't support it. So we think supply and real marketable supply and demand should come together pretty quickly.

Roddie Mackenzie -- Senior Vice President of Marketing and Contracts

I was just going to add to that. I think we saw in the bidding behavior that, for rigs that were rolling off contract, some of our competitors being bidding at extremely low rates. But certainly, in the public tenders where you can see what the rates were, any of the rigs that did require reactivation or were being mobilized from significant distance, the numbers are quite different. And of course, with there being very little cash on hand among those that have low active rig counts, we think that's going to be a key theme going forward, that as soon as that hot supply is taken by the next uptick, the rates just simply have to move to cover the expenses that Jeremy was talking about, reactivations and equipment upgrades and what have you.

So yes, there may still be a little bit of softness in some of the rates in the near term. But certainly, there's no other place for them to go, but up.

Connor Lynagh -- Morgan Stanley -- Analyst

Got it. And I was just going to sneak in one more. If you guys could look in your crystal ball, how many rigs, would you guess, leave the marketed floater supply over the next year or two here?

Jeremy Thigpen -- President and Chief Executive Officer

If you look at the 89 or so floaters that are rolling off contract over this year and next, there are, let me see here, 21 rigs that are over 30 years old. You would think and hope that at least those 21 never see the light of day again. I think there are another 20 or so that are between the ages of 11 and 22, 23. Those are probably at risk, too.

So there could be good 30, 40 rigs that don't ever see contract again.

Roddie Mackenzie -- Senior Vice President of Marketing and Contracts

Yes. I think too, we've been doing the -- we've been in the downturn long enough that I think everybody has very solid experience of what it looks like to stack a rig and the condition that the rig is in to bring it back up. So I just think there's going to be far fewer of these speculative reactivations where we've seen some folks lose a ton of money on that. So yes, I think it actually bodes pretty well going forward that as Jeremy says, of those recontracting necessities, the older ones are just not going to survive.

Connor Lynagh -- Morgan Stanley -- Analyst

Appreciate it. I'll turn it back.

Operator

Thank you. Our next question comes from Taylor Zurcher with Tudor, Pickering, Holt & Company.

Taylor Zurcher -- Tudor, Pickering, Holt, and Company -- Analyst

Hey, good morning and thank you. Jeremy, I wanted to touch on some of your comments on the marketing outlook. You ticked through a number of long-term contract opportunities in Brazil, Africa and Australia. In this sort of market, all those opportunities are going to be fairly lucrative for not only you, but for the rest of your peer group.

And so, Roddie, you touched on some of the pricing behavior right now. I'm curious if you could frame where you think maybe qualitatively pricing shakes out for that sort of work, just given it's really long-term work. And if you think any of the T&C in some of these contracts as it relates to mode payments and things like that might change a bit relative to where they were entering 2020, given the downturn that we've sort of entered over the past few months?

Roddie Mackenzie -- Senior Vice President of Marketing and Contracts

Yes. I think you asked specifically about Brazil. You mentioned that. So Brazil is a great example.

It's actually the one region that is showing an uptick in expected awards this year compared to where it was before, but, of course, they were dealing with different issues prior. But Petrobras alone looks like they're going to contract four to five rigs that -- out of the three tenders they have open at the moment. And we actually expect that for starts in '21, there could be as many as 12 rig years awarded fairly soon, and that includes not just Petrobras, but Karoon and Equinor and Total. But that looks pretty interesting because there's a big push on things like the Búzios field.

There's a significant increase in orders of FPSOs. So that's going to drive rig demand for sure. And how that relates to the pricing? So as you point out, mobilizations and upgrades are very important considerations. And I think what you'll see is that those that have assets in the region very close, perhaps already up to the requirements that are in Brazil or have been out fit specifically for the Petrobras specification, I think you may see some of them still being quite competitive.

But after that, it actually is driven by the necessity of spending money on the rigs and having to recover that. And the interesting thing about those prospects is that they're all reasonably long term. So to us, it's a little counterintuitive to take your asset and book it for two or three years without any return on investment. So certainly, we would expect that not only are the activation costs and the mobilization costs covered in those contracts, but in addition to that, there should be a little bit of upside in it, too.

So in summary, really, I think you'll see the rigs that are hot and ready on the spot may still go a little bit cheap. But after that supply is taken, that we expect that to be soaped up in '21 then should be much more interesting toward the end of '21 and into '22.

Taylor Zurcher -- Tudor, Pickering, Holt, and Company -- Analyst

OK. That's helpful. And the one market I didn't hear much about is the North Sea. Could you just give us a flavor of where you see that market trending over the next 12 to 24 months? And maybe just kind of parse the market between the higher end six gen assets and some of the non six gen assets? I know you have a couple of those rigs rolling off in the next few months.

And so just curious what your take on that market is over the next one to two years?

Roddie Mackenzie -- Senior Vice President of Marketing and Contracts

Yes. So let me deal with the U.K. side first. So a little bit lower specification on the assets.

But really, the U.K. is dominated by the independents. And of course, the uncertainty brought by COVID and the oil price war make -- getting funding for them is tough, right? So certainly, when they do have funding, they're going to be very cautious about how they spend that. So really what's happened in the U.K.

side of things is that a lot of the stuff has been pushed out. So you're basically sitting on a significant number of prospects that are drilled ready, but are struggling for lack of funding. So in the meantime, what's happened on that side of the North Sea is that a lot of rigs have been scrapped. We've seen some extensive cold stacking of rigs.

So the active supply has basically been cut in half. So you're going from about 15 rigs down to seven or eight rigs. So again, going through the reactivation cost and expectations of making some margin going forward, the -- as COVID does subside, and we hope that happens sooner rather than later, you will see these guys being able to get some funding. And when that does happen, the number of available rigs for the North Sea is not going to be that many.

And then when we think about Norway, which is the higher spec that you alluded to there, we -- as Jeremy mentioned, it was good to see fixtures being made. Equinor are pretty active. But Norway has really moved beyond COVID now. I mean they're really back up and running.

Schools are all back in. People are back in offices and Equinor is very active. Not just Equinor, but we're hearing that the likes of Lundin, Wintershall once we get through the IPO, Neptune, etc. They have the better part of perhaps a dozen prospects that expect to move forward.

And a lot of that has been driven by the tax breaks. So again, great to see the Norwegian government essentially stimulating investment by putting together a tax relief package that has really cut breakevens by as much as 40%. So even mature fields like Troll breakevens and now in the 20s instead of the 40s where they were before. So -- but that's all just really positive.

So we really think on the high-spec side, the Norway side of things, that demand just picks up steadily through the rest of this year as everybody gets to grips with the tax relief package. And it could be a very tight market in '21.

Taylor Zurcher -- Tudor, Pickering, Holt, and Company -- Analyst

All right, super helpful response. Thank you.

Operator

Thank you. Our next question comes from Greg Lewis with BTIG.

Greg Lewis -- BTIG -- Analyst

Yes, thank you and good morning everybody. I guess my first question is a follow up to, I think, Connor's question around some of the stress from some of your competitors in the market. Roddie, as you are out there realizing that there's not a lot of activity out there, has it started to come up in conversations, given the fact that relationships matter? That hey, we traditionally use company A, and we use you guys as well. But just given the fact that we don't know what company A is going to look like in any fashion, whether it's going to be acquired, whether it's going to be unwound, is there any sort of, hey, we need to keep some viable companies up there and maybe that's going to drive a little bit more work through Transocean's doors?

Roddie Mackenzie -- Senior Vice President of Marketing and Contracts

Yes, for sure. I mean, if we look back at the second half of 2019, we were actually very successful in breaking into several new customers. And we're very happy to report that our operations team have absolutely nailed it. So the customers that are getting a taste of Transocean for the first time are seeing that we really are delivering value that the well times are tumbling and, of course, the return on investment for the operators is looking better and better.

I'm not saying that's unique to us, but certainly, we're able to demonstrate that we are right up there. So I think where you may have seen customers that hadn't used us before, those that are using us just now are extremely pleased. So again, hats off to the ops team. They've done a fantastic job.

And then, of course, with our long-term customers, we're executing extremely well, as can be seen in the revenue efficiency numbers. But not only that, the way that the teams have dealt with COVID almost uninterrupted operations, I mean, only a few instances where rigs went on standby for a short period of time. But I mean, been able to keep operations running worldwide during the pandemic is just outstanding. And it comes just through a tremendous focus on planning and being proactive and doing that kind of stuff.

So look, we really believe that there's a lot of value in that. We have some of our customers telling us we know that you guys are a bit more expensive. You perhaps deserve that premium. They're almost cautioning us not to be too expensive.

But we're proud to say that we're able to get a premium, but I think we delivered tremendous value for that premium. And actually, I wouldn't describe it as a premium, I would describe as saving for the operators.

Greg Lewis -- BTIG -- Analyst

OK. Great. And then just kind of for Jeremy or Mark, a little bit bigger picture question, more around capital allocation. Any -- as we look across the capital structure, and obviously, there's bonds in the back end that are trading at huge discounts, but there's also some in the near-term that are trading at discounts, and cash is key.

But are there -- is there any arbitrage opportunity as you kind of look at your equity versus your debt, where you could kind of take advantage to kind of push -- solidify Transocean liquidity position, balance sheet position a little bit more? It looks like there should be.

Jeremy Thigpen -- President and Chief Executive Officer

I'll defer to Mark on that one.

Mark Mey -- Executive Vice President and Chief Financial Officer

Yes. Greg, as you know, we've been very proactive over the last several years in managing our balance sheet. We've raised over $3.5 billion. We've refinanced over $2 billion of debt.

We've done tenders on a regular basis. We've done open market repurchases virtually every quarter. So we look at every opportunity to lengthen our runway, to look at our near-term maturities, make sure we've got liquidity available to address that. And that is going to change now.

We're going to continue to do that and to write our bonds are trading at deep discounts. But our equity is trading at pretty low price as well. So it's very difficult to go out here and say, we want to issue several hundred million dollars of equity to buying debt when both sides of the equation are deeply discounted at the moment. But that being said, we will continue to look at interesting ways in which we can extend the runway and keep the company operating at a very high level of excellence.

Greg Lewis -- BTIG -- Analyst

OK, hey guys, thank you very much. Have a great day.

Mark Mey -- Executive Vice President and Chief Financial Officer

Great.

Operator

Thank you. Our next question comes from Mike Sabella with the Bank of America.

Mike Sabella -- Bank of America Merrill Lynch -- Analyst

Hey, good morning everyone. I was just kind of thinking maybe we could talk for a little bit more about the upgrade of the Atlas and just kind of walking us through that decision. So really kind of maybe what are the options for you or kind of really any of your peers to upgrade kind of an existing rig instead of taking a newbuild? And then maybe kind of what -- on the flip side, what you could have reasonably expected from the shipyard if you were decided to just delay or cancel delivery of that rig?

Jeremy Thigpen -- President and Chief Executive Officer

So let me start -- I'll start with the last piece first. There really was no opportunity to cancel the rig. Contractually, we were committed. And so we've obviously thought about every possibility over the course of the last five years during this downturn and recognizing that this was a significant capex for us here as we roll into 2021 -- 2020, 2021.

So that was kind of off the table for us. So with respect to the upgrade itself, there's more than just buying the 20,000 pressure control equipment to upgrade one of these assets to be able to drill and complete effectively in the Gulf of Mexico. The higher hook load, which we mentioned on the call, we mentioned several times before, is of paramount importance. The larger deck that both of these rigs, the Titan and the Atlas, have are ideal for large completion work.

There's several other features, attributes that have been added to these rigs to make them really optimal for these 20,000 projects in the Lower Tertiary. So are there other assets that are out there for us or our competitors that could be upgraded? Yes, but significant cash bringing one of these assets into a shipyard, upgrading the hook load capacity, upgrading the mud system, buying the -- acquiring the 20,000 pressure control equipment and associated plumbing, everything else that goes with it. That's really -- as we look at our competitive landscape, there's not really a viable option out there because everybody is so desperate right now with respect to their cash position. So we feel like we're in a very unique situation, having the only two 20,000 capable assets in the industry.

So now we feel good about it. We're excited to have the drilling contract, although conditional, with Beacon and their partners. And we see other opportunities. We've been in active conversations with other customers about follow-on work after the Shenandoah project.

So still a few things left to be done, but excited about the opportunity.

Mark Mey -- Executive Vice President and Chief Financial Officer

Mike, this is Mark. As Jeremy indicated, all the other upgrades have to occur to the rig. We took this decision 12 to 18 months ago to go ahead and prepare the rig for a 20,000 psi BOP. So those costs have all been included in the numbers I mentioned earlier.

Ian asked the question earlier, does it include everything? I said that except for some well control equipment. And the reason I'm not specific on that is because the contract that we've signed is conditional, and it has some items that need to be agreed upon, including some of the well control equipment. So once we get a better handle as to what that is, we'll be able to give you a better estimate as to what that costs. But the vast majority of the other costs associated with this -- all of it is included in the 1.4 billion.

Mike Sabella -- Bank of America Merrill Lynch -- Analyst

That's great, guys. That was very helpful. And then just a follow-up. So we recently saw a contract disclosed by a peer in the Gulf of Mexico, kind of, 450 days at 180,000 per day going out to 2022.

I was wondering, just as we all try to figure out what the dayrate curve looks like. Assuming you all were a part of the bidding process on that rig, was it really kind of the front end that you didn't like the rate or the back end as well? And then just kind of what does that indicate for where you guys think rates could go out into 2022?

Jeremy Thigpen -- President and Chief Executive Officer

We've been very vocal especially over the last couple of quarters with respect to the fact that we need to enter into contract that generate positive cash flow from operations. And that means not only covering our rig specific cost, but covering our corporate overhead. We have to generate cash as do all of our competitors. And so that's how we are approaching our response to tenders.

And Roddie, I don't know --

Roddie Mackenzie -- Senior Vice President of Marketing and Contracts

Go ahead. Yes, sure. I'd also add. You asked about the front end and the back end.

The truth of the market is on that one there's a fairly significant period to lapse before that campaign starts. So in our view, trying to beat that kind of a rate, if you also have an asset that's not going to do anything for six to nine months ahead of it. And as Jeremy said, if you're honest about what your overhead is, then clearly, that doesn't really work for us. I guess it may work for others, but there's just not going to be any cash generated from it.

And it's been our stated policy for quite some time is that we will not enter into contracts that are just treading water or still reducing our liquidity. So yes, we were involved in that. Great operator. We've worked for them very well in the past, but that was not the kind of rate level we were willing to look at.

Mike Sabella -- Bank of America Merrill Lynch -- Analyst

That's great, thanks a lot everyone.

Operator

Thank you. Our next question comes from Kurt Hallead with RBC.

Kurt Hallead -- RBC Capital Markets -- Analyst

Hey, good morning. Just initial follow-up here for Mark. When you provided the liquidity guidance out going forward, that 1.2 to $1.4 billion range. I was just curious as to whether or not that you anticipate having to tap into your revolver to maintain that liquidity level?

Mark Mey -- Executive Vice President and Chief Financial Officer

Kurt, our revolver is $1.3 billion. So it's right in the middle of the range. So if we hit the middle of the range, the answer is no, but there's a potential that we dip into it by as much as 100 million.

Kurt Hallead -- RBC Capital Markets -- Analyst

OK. That's fair enough. I appreciate that. And then just a follow-up on the cash flow dynamic here.

You kind of provided your capex numbers for the back half of the year, and you indicated you'd be positive from cash from operations. Given the overall level of capex in the back half, would you anticipate that you could potentially be free cash flow positive in the back half of the year?

Mark Mey -- Executive Vice President and Chief Financial Officer

It'll be close, Kurt. We do have $170 million in capex for the second half of the year. It should be close

Kurt Hallead -- RBC Capital Markets -- Analyst

OK. And then just one follow-up for Jeremy. You guys talked about the difficult decision to have to reduce cost and reduce some personnel. Kind of on a broader dynamic around cost reductions, given the dynamics that have occurred over the course of the year, has there been any opportunity potentially to reduce, No.

1, your daily operating cost? And secondly, have you been able to negotiate better terms with vendors to be able to reduce your overall cost, let's say, on the newbuild Atlas, for example?

Jeremy Thigpen -- President and Chief Executive Officer

So constantly looking for opportunities to drive cost out of the system, out of our operations, out of our shore-based support, Kurt, as you know, but we've been at this now pretty diligently since the start of the downturn, let's call it, late '14, early '15. And so we've captured all of the low-hanging fruit and then some. We certainly work with customers to optimize the crews that we have on each of our assets. And we've done that on several assets where we've been able to pretty substantially reduce crew size without negatively impacting performance.

In fact, we've seen safety, performance and reliability improve in most of those cases. And so constantly looking for opportunities. With respect to our supplier base, our supply partners, we've entered into -- and this is probably two years plus now -- entered into these long-term care agreements with all of our major suppliers and equipment providers on every major piece of equipment on our assets. And so those are long-term relationships, long-term contracts where we negotiated fairly significant discounts a couple of years ago.

Obviously, we continue to go back to our vendors for support, given these challenging times. But I think the incremental savings are going to be pretty de minimis, not overly material.

Kurt Hallead -- RBC Capital Markets -- Analyst

Great, thanks for that.

Operator

Thank you. Our final question will come from Sean Meakim with JP Morgan.

Sean Meakim -- J.P. Morgan -- Analyst

Thanks, good morning. Maybe just to follow-on the Atlas discussion and the Beacon contract. The numbers look pretty good. But it seems like there's pretty limited visibility on follow on opportunities.

North Platte seems like the other big piece of the puzzle. It's unclear maybe the likelihood or timing of that one. Are we missing some others out there from a 20,000 perspective? And just how do you think about follow-on opportunities as you try to secure cash payback on that rig without a big anchor type contract?

Roddie Mackenzie -- Senior Vice President of Marketing and Contracts

So there are other opportunities that are out there. There's -- basically, as we talk to the customers that are engaged in these kind of fields -- in fact, you could probably go, Google some of the really interesting stuff about how many of these high-pressure fields that are in the Gulf of Mexico. The operators that are engaged in that are wide ranging. So everyone from Chevron and the Beacon or the Shenandoah group.

I mean, on top of that, yes, there's Total. There's also more requirements for some of the bigger guys as well. So even Chevron, Shell, these folks are all talking about the possibility of incremental demand in that area. Now of course, right at this minute, in the midst of COVID, there's some uncertainty about timing of those kind of things.

But -- so needless to say that there are additional opportunities. And without going into the details of the Beacon arrangement, we're -- we've put that in such a way that allows us to move forward with minimal risk to not recovering the investment that we'll make in the well control equipment. But on top of that being able to capitalize on the upside on the other side of it, having, as Jeremy said, the most capable rig in the world and being 20,000 outfitted and ready for when that happens. So recontracting risk, we think, is pretty low because the recontracting wouldn't take place for at least another three or more years.

So certainly, there's plenty of fields that require this equipment in the Gulf of Mexico. And we think three to four years is plenty of time for the efficiencies of deepwater to come through, and we're already seeing how well we're performing versus shale and other places. But as time moves on and we continue this fantastic drive on efficiency, I think, there's lots of opportunities there for it, and we kind of feel that we should be able to take advantage of that first-mover position.

Sean Meakim -- J.P. Morgan -- Analyst

Got it. I think you've framed that really well. Then, Jeremy, you certainly have an advantage in bending right now as your peers restructure. But unfortunately, there's quite a limited opportunity to press that advantage given the lack of tenders.

So the goal since the early days of the last downturn was for you to be the last man standing. Seven years post peak, you're about there. And you made all the right moves in the interim to position yourself there. So you called it right.

But even with restructuring, there's a huge capital hold in the sector. So just does your view on being the last man standing change? Is there a shift in strategy on capital structure if deepwater activity stays pretty anemic for the next 12 to 18 months?

Jeremy Thigpen -- President and Chief Executive Officer

No, it doesn't change. I think -- I mean, ultimately, as you well know, we're going to need some help from the market at some point in time, but we maintain a five-year forecast and continue to look at our liquidity position under various different scenarios in terms of utilization and dayrate and feel comfortable with our near to midterm. Obviously, if we get three years out plus and the market hasn't started to recover and dayrates haven't started to recover where we can generate some significant cash flow from operations, then obviously, we're going to be like everybody else that's going through the process right now. We have -- we are the last man standing.

We have done -- I think made all the right moves, both from a fleet operation and balance sheet perspective. And we'll continue to pull every lever we can to extend that liquidity runway and keep moving on.

Sean Meakim -- J.P. Morgan -- Analyst

Fair enough. Thanks a lot Jeremy. I appreciate.

Operator

Thank you. I'd like to turn it back to Mr. Brad Alexander for closing comments.

Brad Alexander -- Vice President, Investor Relations

Thank you, David, and thank you to all participants on today's call. If you have further questions, please feel free to contact me. We look forward to talking with you again when we report our third-quarter 2020 results. Have a good day.

Operator

[Operator signoff]

Duration: 59 minutes

Call participants:

Brad Alexander -- Vice President, Investor Relations

Jeremy Thigpen -- President and Chief Executive Officer

Mark Mey -- Executive Vice President and Chief Financial Officer

Ian MacPherson -- Simmons Energy -- Analyst

Roddie Mackenzie -- Senior Vice President of Marketing and Contracts

Connor Lynagh -- Morgan Stanley -- Analyst

Taylor Zurcher -- Tudor, Pickering, Holt, and Company -- Analyst

Greg Lewis -- BTIG -- Analyst

Mike Sabella -- Bank of America Merrill Lynch -- Analyst

Kurt Hallead -- RBC Capital Markets -- Analyst

Sean Meakim -- J.P. Morgan -- Analyst

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