Categories Earnings Call Transcripts, Energy, Industrials

Transocean Ltd. (NYSE: RIG) Q1 2020 Earnings Call Transcript

RIG Earnings Call - Final Transcript

Transocean Ltd. (RIG) Q1 2020 earnings call dated April 30, 2020

Corporate Participants:

Bradley Alexander — Vice President, Investor Relations

Jeremy D. Thigpen — President and Chief Executive Officer

Mark Mey — Executive Vice President and Chief Financial Officer

Roddie Mackenzie — Senior Vice President, Marketing, Innovation & Industry Relations

Analysts:

Ian MacPherson — Simmons & Company International — Analyst

Connor Lynagh — Morgan Stanley — Analyst

Taylor Zurcher — Tudor Pickering & Co. — Analyst

Gregory Lewis — BTIG — Analyst

Kurt Hallead — RBC Capital Markets — Analyst

Mike Sabella — Bank of America Merrill Lynch — Analyst

Sean C. Meakim — J.P. Morgan — Analyst

Presentation:

Operator

Good day, and welcome to the Q1 Transocean Earnings Conference Call. [Operator Instructions]

At this time, I would like to turn the conference over to Mr. Brad Alexander, Vice President of Investor Relations. Please go ahead, sir.

Bradley Alexander — Vice President, Investor Relations

Thank you, Valerie. Good morning, and welcome to Transocean’s First 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 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 get more participants an opportunity to speak on this call, please limit yourself to one initial question and one follow-up.

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

Jeremy D. Thigpen — President and Chief Executive Officer

Thank you, Brad, and welcome to our employees, customers, investors and analysts participating in today’s call. Before we dive into the results, I would just like to inform our listeners that we are continuing to work safely and remotely to do our part to prevent the spread of COVID-19. Therefore, please forgive us if the audio quality is different from speaker to speaker and if the Q&A section is a bit choppy as we are all on our remote phone lines.

As reported in yesterday’s earnings release, for the first quarter, Transocean generated adjusted EBITDA of $235 million on $807 million in adjusted revenue. While revenue efficiency for the quarter fell just short of our guidance of 95%, primarily attributable to our Norwegian operations, lower than guided costs across the enterprise, enabled us to deliver adjusted EBITDA results that exceeded our expectations.

These results are reflective of our first full quarter of operations from the Deepwater Corcovado and Deepwater Mykonos, which both commenced multiyear campaigns with Petrobras in Brazil during the fourth quarter of last year. Also in the first quarter, the Deepwater Asgard commenced her new contract with Beacon Offshore Energy in the U.S. Gulf of Mexico. With Beacon already exercising the first two options, she is now contracted to work into the fourth quarter of this year. The Transocean Leader started to campaign with Premier in the U.K. in March and it’s scheduled to remain on contract through the middle of the year.

Additionally, we have a number of contracts we previously announced that either have commenced or about to commence operations. In Canada, the Barents has commenced operations with Equinor. This initial campaign is expected to run into the third quarter of the year with the possibility that Equinor could exercise following options, extending her through the year.

In the U.K., we have worked with our customer — who is drilling with Pit 712 to delay their drilling campaign into the fall, allowing us to substitute for the 712 with either the Paul B. Loyd or Transocean Leader following their current campaign. As we have repeatedly demonstrated over the years, we will quickly and thoughtfully evaluate the future of the 712 and her value in our fleet.

The Discoverer Inspiration was just completed a successful five year campaign with Chevron has now become her contract — begun her contract with Tellus in the Gulf of Mexico. Her superior drilling performance with Chevron was instrumental in her contracting immediate follow-on work that keeps her working into the third quarter.

In Trinidad, the DD3 is in the process of going through acceptance testing with Shell. I want to commend our operations teams for their diligence in delivering top-tier performance to ExxonMobil in Equatorial Guinea, completing the mobilization to Trinidad and crewing this rig to assure we deliver the asset to our customer as expected despite the challenges presented by COVID-19.

The performance of the Transocean employees is not unique to our operations in Trinidad. I want to personally thank and recognize all of our offshore teams for their sacrifices, including many extended hedges, and our onshore teams for facilitating uninterrupted global operations and managing the vast array of COVID-19 challenges.

In every jurisdiction where we work, we have confronted and overcome obstacles, including but not limited to, travel bans and required quarantines to and from countries for crew changes, flight cancellation — flight cancellations and scheduling changes, obtaining critical inventory and parts, safety and health check of all personnel onboard, maintaining a safe work area and living quarters, while still following social distancing recommendations and where we required crew isolation and evacuation. I am beyond proud of the entire Transocean team and their efforts to ensure operations safely continue.

We have kept our fleet on contract and operated to Transocean’s high standards for safety, reliability and efficiency. Even in the instances where our customers or non-Transocean rig personnel were unable to reach the rig, including our only instance of a force majeure, which occurred in India and was resolved after approximately one week, we have kept our fleet operational for our customers. This is a direct result of the extraordinary efforts of our organization to charter flights and contract boats when conventional travel was unavailable. Locating both necessary accommodations to ensure employee had places to stay before and after crew changes. And closely coordinate with suppliers and freight forwarders to keep our rig stocked with necessary supplies.

Additionally, we have done this while keeping our onshore personnel throughout the world safe by following local protocols for social distancing and other precautions. Transocean’s onshore employees have been able to productively and successfully work remotely and will continue to do so until such actions are deemed no longer necessary by government and health officials. This is a reflection of our continued commitment to safety with our top priority remaining the health of our employees and our customers. With this, I say thank you to the entire team of Transocean.

Looking at our fleet, we’ve recently taken the action to responsibly recycle four older-stacked assets; the Polar Pioneer in the Songa Dee from our harsh environment fleet and the 711 and 714 from our Midwater fleet. All of these assets were at least 35 years old and with a significant cost required for thier respective reactivations coupled with the perceived future marketability of these less capable units, we determined that they no longer have sufficient option value to warrant retention. Needless to say, given the current uncertainty in the industry, we hope and expect to see similar moves across the industry.

I would now like to make a few comments about COVID-19 and its perceived impact to Transocean’s industry-leading $9.6 billion backlog. As I mentioned earlier, we do not have any rigs that are currently in a force majeure status as a result of COVID-19. As a reminder, the strength of our backlog enabled us to bolster our liquidity over the past few years by securitizing the two largest parts of our backlog; the combined eight contracts with Shell and Equinor. These contracts were strong, not just from a dayrate perspective, but the quality of the customers and the strength of the terms and conditions in the contract.

While we are and we’ll continue to do everything we can to prevent the spread of COVID-19 not just on these rigs, but on all of our rigs, we take comfort in the fact that these eight contracts provide for significantly longer remediation periods than a standard in the industry. I again like to emphasize, we will continue to remain vigilant and doing everything we can to keep our rigs COVID-19-free, and we’ll continue taking the necessary actions in that pursuit. I’d also like to take this opportunity to say that our customers have been extremely supportive and complementary of our efforts and our protocol throughout this pandemic, and have worked closely with us to safely continue to operate through this crisis.

Turning to our market outlook. In response to the steep decreases we’ve seen in oil prices in the past three months, customer budgets have been significantly reduced. Still while our backlog remains a source of strength, our near-term outlook for new work and escalating dayrates is obviously tempered. Having said that, we’ve been encouraged to see that our customers are not canceling projects that we’re likely to proceed earlier in the year, but rather looking to defer and postpone their sanctioning generally by nine months to 12 months.

When we look out over the next 18 months, we now see more than 80 projects with a total duration of almost 90 rig years. We fully recognize that the current oil price does not support commitment of these projects, but as oil prices recover, these offshore projects will once again become economically viable. And we continue to believe that offshore represents a better investment opportunity for our customer base than their onshore projects.

In response to the current market condition and similar to the steps we took during the previous downturn to preserve our margins, Transocean will take the necessary steps to reduce expenses commensurate with the decline in our fleet activity. Fortunately, through a purposeful and disciplined marketing strategy, we came into 2020 with only one idle rig and the remainder of our active fleet effectively fully booked in the first half of the year with some roll off thereafter.

We have taken the opportunity discussed previously with the 712 to transfer future work on to the Loyd or the Leader to allow us to more efficiently run our fleet. Where other similar opportunities present themselves, we would look to capitalize on these situations. In an effort to further manage our costs, we will also be decisive in immediately cold-stacking and in some cases recycling assets that do not have foreseeable contracting opportunities.

Additionally, as evidenced by our first quarter performance, we have already initiated actions to reduce other non-essential operating and SG&A expenses to reduce our support costs and defer all non-essential capex and internal initiatives. Our cost structure is scalable based on activity levels, and we will remain diligent in adjusting it as our drilling activity dictates.

As we await higher oil prices and the commencement of new projects, we are working diligently with our customers to have near-term options to best align our interests with theirs in an effort to keep our fleet active. Having said that, it is important for us to generate cash with any new contracts. Therefore, we will continue to exercise discipline in our contracting.

We are very happy that we started 2020 with almost 100% of our marketable fleet contracted into the back half of the year. This now affords us the opportunity to focus on operations with a number of months to strategically determine how to best manage our fleet. In the event, market weakness continues throughout the year, we will act decisively to ensure our fleet is either operational or stacked to protect our liquidity.

We’re also determining how best to manage the anticipated delivery of the Deepwater Atlas later this year. Despite the dislocation between oil supply and demand and the unprecedented decline in oil prices, there remain significant customer interest regarding the Atlas and her potential to become the industry’s second 20,000 psi ultra-deepwater drillship. As such, we will continue to work closely with our customers and the shipyard, which is currently challenged to meet its year end delivery schedule due to disruptions created by COVID-19 as we move closer to delivering this state-of-the-art asset to the industry.

In conclusion, we are disappointed that the broad recovery we were expecting at the beginning of the year is now likely to be delayed into 2021. However, we are committed to our customers and working with them to find the right contractual solution to enable their programs, while operating safely at the highest performance levels with the industry’s most capable assets.

We’ve positioned ourselves with the clear view of harsh environment in ultra-deepwater drilling and we’ll continue to strategically refine our fleet to further enhance our position. As such, we expect that our marketed fleet will remain industry’s most utilized as we successfully navigate this extended 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 first quarter results then provide guidance for the second quarter. Lastly, I’ll provide an update on our liquidity forecast through 2021. As reported in our detailed press release, for the first quarter of 2020, we reported a net loss attributable to controlling interest of $392 million or $0.64 per diluted share. After adjusting for unfavorable items associated with impairment charges on the previously announced floater retirements and loss on the retirement of debt, we reported adjusted net loss of $187 million or $0.30 per diluted share. Further details are included in our press release.

Highlights of the first quarter include, adjusted EBITDA of $235 million, reflecting the continued conversion of our industry-leading contract backlog to cash and our persistent focus on costs, fleet-wide revenue efficiency of 94%, reduced fleet-wide operating days of 2,419 for the quarter as compared to the fourth quarter of 2019 and a net decrease in long-term debt of approximately $117 million attributable to opportunistic open market repurchases and biannual amortization of our secured bonds, partially offset by the refinancing of 2023 priority guaranteed notes.

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During the first quarter, we had adjusted contract drilling revenues of $807 million, in line with our guidance. Operating and maintenance expense for the quarter was $540 million. This is below our guidance due to the timing of shipyard projects and in-service maintenance and the elimination or postponement of certain projects due to COVID-19.

General and administrative expense was $43 million for the quarter, which is slightly below our guidance due primarily lower legal, professional and advisory fees. As part of our long-term objective to optimize our balance sheet, we repurchased approximately $76 million of near-dated debt in the open market during the quarter at a cost of $55 million. This will also save us approximately $11 million in interest through maturity.

We ended the first 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 dedicated for rig service and $1.3 billion from our undrawn revolving credit facility. Consistent with last year and due to the timing of interest and tax payments and the unwinding of some accruals, we did not generate operating cash flow during the first quarter. But consistent with 2019, we fully expect to generate significant positive operating cash flow in the second quarter and full year 2020 as revenue recognition and generation and customer collections remained strong.

Let me now provide an update on our 2020 financial expectations. For the second quarter of 2020, we expect our adjusted contract drilling revenues to be approximately $785 million. The sequential decline reflects low activity as a result of the reduced duration of the Discoverer India’s contract coupled with the delay in transport of Skyros’ [Phonetic] drilling program from the 712 to either the Paul B. Loyd or Transocean Leader. This work is scheduled to resume in the second half of the year.

For the full year 2020, we now anticipate adjusted contract revenue of approximately $3 billion. The change from our previous forecast is due to contracts being deferred — contract adjustments recently negotiated with our customers. We expect second quarter O&M expense to be approximately $545 million. The slight increase quarter-over-quarter relates to the additional expenses incurred as a result of maintaining uninterrupted operations during the COVID-19 pandemic. These include, but are not limited to, overtime costs, charter flights and contract boats or crew changes, hotel cost for extended quarantine prior to and after crew rotations and certain logistical expenses.

Furthermore, we anticipate full year O&M expense of approximately $2 billion. Versus our prior guidance, this is approximately $100 million of net savings as a result of operating — activity-related operating expenses throughout the remainder of 2020, offset by approximately $45 million of anticipated costs associated with our responses to COVID-19. We expect G&A expense for the second quarter to be approximately $44 million. Additionally, our forecasted G&A expense for the year is now approximately $175 million, a $10 million decrease from our prior guidance.

Net interest expense for the second quarter is expected to be approximately $147 million. This forecast includes capitalized interest of approximately $12 million and interest income of $3 million. We anticipate full year net interest expense to be approximately $590 million, with $49 million of capitalized interest, $30 million of interest income. Capital expenditures, including capitalized interest for the second quarter are anticipated to be approximately $55 million. This includes approximately $32 million for our newbuild drillships under construction and $23 million of maintenance capex. For the full year, we expect capex to be approximately $840 million, which includes approximately $740 million for our two newbuild drillships and $100 million for maintenance. Our cash taxes for the second quarter are expected to be approximately $12 million and approximately $50 million for 2020.

Turning now to our predicted liquidity at December 31, 2021. Including our undrawn revolving credit facility and the potential securitization of the Deepwater Titan, our end of year 2021 liquidity is estimated to be between $1.2 billion and $1.4 billion. This liquidity forecast includes an estimated 2020 capex of $840 million, discussed previously and a reduced 321 capex expectation of $815 million. 2021 capex includes $750 million relative to our newbuilds and $65 million for maintenance capex. Please note that our capex projects excludes any speculative rig reactivations or upgrades.

In conclusion, while safety and operational integrity are our fine areas of focus, we are acutely aware of the rapidly changing offshore drilling environment. With that in mind, as we complete eight contracts, we will rapidly resize operations including overhead and G&A to reflect reduced operating fleet size.

I will now turn the call back over to Brad.

Bradley Alexander — Vice President, Investor Relations

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

Questions and Answers:

Operator

Thank you. [Operator Instructions] We will now take our first question from Ian McPherson of Simmons. Please go ahead.

Ian MacPherson — Simmons & Company International — Analyst

Thanks. Good morning, guys. Jeremy, I understand that there is — it sounds like you’re contemplating the possibility of flexing the Atlas towards maybe stretching that depending on your ability and the market conditions to do so, but it doesn’t look like that’s reflected in your capex guidance for this year. Can you just walk us through your decision triggers for keeping [Phonetic] that rig on schedule versus what levers you have to pass for that?

Jeremy D. Thigpen — President and Chief Executive Officer

Yeah. Good question, Ian. There are a lot of moving parts, as you can imagine. Of course, you’ve got both the Atlas and the Titan under construction at the moment. And the shipyards are challenged, they’ve been hit pretty hard with COVID-19, specifically in the shipyards which have caused some disruptions. They’ve had some disruptions from some of the equipment providers in terms of delays providing product. And so we’re doing our best to juggle both assets. Of course, the Titan already has the contract with Chevron, so we’re obviously mindful of that.

As I mentioned in my prepared comments, it’s quite honestly a bit surprising and pleasantly surprising to me to see that our customers who were previously interested in securing the Atlas and upgrading her to a 20,000 rig are still very much interested. I would say one of the customers is looking at potentially delaying the start of their program by a few months, but haven’t changed their resolve in terms of moving forward and our other customer wants to move forward at the pace originally — that they originally expressed before we were all hit with this pandemic.

And so we’re working both sides of it right now, Ian. My guess is that the delivery of the Atlas does slip a little bit. Whether that’s later this year or early next, to be determined. But we’re just working right now as best we can with customers, with shipyards and the OEMs to work on the timing of that.

Ian MacPherson — Simmons & Company International — Analyst

Okay. Got it. Well, I have to say, it’s been impressive to us to see that offshore contractors like you all have been able to continue operating through the past several months without a great deal of interruption. So I would echo your — kudos to your crews and your platform for keeping the rigs running. But it also seems to me that there is an added layer of costs for logistics, extra evacuations or isolating crews, etc. And although your O&M guidance for this year has come down a little bit, I imagine that’s a little bit activity related. Is there — has there been a squeeze in your margins associated with the disruption of this virus? And is any of that subject to negotiation for fall backs? How are you sharing that cost if it is in fact material to you?

Jeremy D. Thigpen — President and Chief Executive Officer

Ian, I’ll let Mark handle that. But I will tell you, we are incurring additional cost, as you rightly point out, and Mark can give more specifics. And ultimately, yes, we will be talking to our customers about recouping some of that or all of that. But go ahead Mark.

Mark Mey — Executive Vice President and Chief Financial Officer

No, that’s exactly right. Good morning, Ian. In my prepared comments, I actually mentioned that we anticipate about $45 million of additional cost this year, mainly around overtime, hiring charter flights or contract boats and hotel costs. Some of this is re-billable to the customers, some of it may be. We are still in negotiations with customers, but we haven’t landed on that yet. So you can expect to get a better update by the next quarter.

Ian MacPherson — Simmons & Company International — Analyst

That’s helpful. Well, good luck with everything. Thank you, guys.

Jeremy D. Thigpen — President and Chief Executive Officer

Thanks, Ian.

Operator

Thank you. We’ll move to our next question from Connor Lynagh from Morgan Stanley. Please go ahead.

Connor Lynagh — Morgan Stanley — Analyst

Yeah, thanks. I was wondering if we could discuss what your contract terms generally look like, and I appreciate I’m asking you to generalize over many different contracts. But it occurs to me that you have not really faced many contract cancellations unlike some of your peers. Can you just discuss generally what the terms of cancellation for convenience look like in most of your contracts?

Jeremy D. Thigpen — President and Chief Executive Officer

Yeah, sure. Let me just — they are different, as you probably point out, and it really matters as to whether we — when we negotiated the contract. So if you think about the eight contracts that I referenced in my prepared remarks that really make up the bulk of our backlog, especially from a cash flow perspective, those were negotiated before the initial downturn began in 2014 at a time when drilling contractors had far more leverage. But in terms of a little more specific, let me just hand it over to our Senior VP of Marketing and Contracts, Roddie.

Roddie Mackenzie — Senior Vice President, Marketing, Innovation & Industry Relations

Hi. Yes, so we have not seen the terminations that our competitors have seen and primarily that is due to stronger terms and conditions in the contracts. Even the contracts that we signed during the downturn, we’ve been pretty adamant that our customers cannot dissolve or get out of the contracts without some sort of compensation coming back to us. So where we’ve been, I guess particularly difficult on the terms and conditions is really to avoid the situation where we get spurious terminations that happen quickly, makes the customers think twice about whether it is necessary to terminate.

That combined with the stuff that Mark and Jeremy just went over in terms of our operations and our HR teams did a fantastic job making sure that we are able to continue operations. Essentially force majeure situations or not upon us, they may be upon the customers at which they decided they wish to terminate. But in all the cases of the contracts we have, there is certainly remedy periods and time to overcome those particular instances. All of they wished to terminate quickly then there is a pretty sizable payout attached with those contracts.

So really that’s the primary the crux of it. Yes, we may be a little bit difficult on the terms and conditions, but we do that to protect ourselves from dramatic swings in activity. We kind of wish that everyone else would do the same, but that’s up to them. But from our point of view, we do make sure our contracts are not easily cancellable.

Connor Lynagh — Morgan Stanley — Analyst

Makes sense. Thanks for the color. Maybe sort of shifting gears here on the cost side of things. It seems like you guys have been running pretty efficiently. And so I’m curious if activity comes down further beyond the variable cost affiliated with the rig itself, what options do you have to actually further reduce your operating costs? Can you walk through any opportunities there?

Jeremy D. Thigpen — President and Chief Executive Officer

Let me hand that one over to Mark.

Mark Mey — Executive Vice President and Chief Financial Officer

So as I mentioned on the — my prepared comments and Jeremy mentioned the same thing, we have some long-term contracts that we won through next year they year after that, the year after that. So you’re not going to see any changes, but that. But as we do have contracts that run-off later this year or next year, we will take action to rightsize the business to reflect the reduced footprint of the operating rigs. So I cannot get into an excellent numbers right now. But so far we have folks according a rig in a certain jurisdiction and there is no rig operating in that jurisdiction. Clearly, we’ll then have to make a decision with regard to how do we rightsize the organization, move those folks around or end up settling some of them in places where either part of country.

Connor Lynagh — Morgan Stanley — Analyst

Okay, I understood. Thanks for the color.

Operator

Thank you. [Operator Instructions] We’ll take our next question from Taylor Zurcher of Tudor Pickering Holt. Please go ahead.

Taylor Zurcher — Tudor Pickering & Co. — Analyst

Hey, good morning. Thank you. Jeremy, you talked about working with some of your customers that have near-term options, but also in the initial stages of the downturn, we tend to see a bunch of blend and extend type arrangements, this downturn seems to be a bit different where liquidity is at such a huge premium for frankly every offshore driller out there. And so I’m curious if you could just share what your appetite would be for blend and extend type arrangement moving forward?

Jeremy D. Thigpen — President and Chief Executive Officer

I’ll start and then I’ll hand it over to Roddie for his thoughts. I will just offer some color on the market. This has been a very interesting couple of months. I would say at the outset of this pandemic, the number one focus area for us and our customers and all the other service providers was how do we make sure to maintain safe and healthy operations on the rig. And so everybody really came together around that. And then once our customers started to feel comfortable with — and I mentioned, they’ve been very complementary the way we’ve handled this and the team deserves, I mean not me, the operations team, the HR team, the travel team deserve a lot of kudos. They just did — just some Herculean work. But once our customer started to get comfortable that we had this fairly well contained and we have proper protocols in place, then it started to — the conversation started to shift toward, hey, could you help give us a little relief. And relief was different for everybody, whether that was a reduced dayrate for a period of time or a blend and extend type of conversation. And now I think we’re getting to the point where people are really — customers are especially really starting to feel the pain and that’s where you’ve seen some early terminations from some of our peers over the course of the past week or so.

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So I think the conversations are starting to morph as we get further along in this crisis, and we start to see how it ultimately plays out. But Rod, I don’t know if you want to share any additional color on what you’re hearing specifically as it relates to potential blend and extend opportunities and how we’re approaching that?

Roddie Mackenzie — Senior Vice President, Marketing, Innovation & Industry Relations

Yeah. So we have seen that, which is encouraging actually, because it means that there is additional work to be performed for several of the operators. So we have a couple of requests to do that. But let me assure you, we will not be taking on any blend and extend so that the extension equivalent dayrate would be cash breakeven or something like that. I mean we really view that no more than ever, your costs should include all overheads, all amortization of shipyards, all things associated with mobilizations and none of those should be given away for free.

We are very disciplined, as Jeremy said before, that we never did that in the downturn, we always try to maintain that we would have cash flow positive contracts, not just from a local opex point of view, but from a corporate opex point of view as well. So we kind of feel no more than ever that essential for drillers if they wish to have any degree of viability to ensure those costs are fully captured and remunerated. So yeah, blend and extends are possible, but you’re not going to see them at a bargain basement numbers from our point of view.

Taylor Zurcher — Tudor Pickering & Co. — Analyst

Okay. That’s really helpful. A follow-up. I wanted to ask about Brazil, obviously we’ve seen a big capex reduction announcement from Petrobras, and a bit unclear, at least to me, what that means for their planned rig needs over the next, at least a year. At the same time, a lot of the IOCs had acquired acreage there, frankly haven’t really gotten going down in Brazil yet and probably will need to at some point in the future. So just curious if you could give us a little bit of an outlook at least over the next 12 months for what you’re seeing inherent in Brazil?

Jeremy D. Thigpen — President and Chief Executive Officer

Okay. I’ll start and then hand it over to Roddie again. But I would say it’s not exclusive to Brazil. I mean if you look at the current environment and the dramatic drop in oil prices and the continued uncertainty about the timing that we will contain COVID-19 globally and get the economy going again and create demand again for oil and gas. I think everything is going to get pushed to the right for a period of time, and I don’t think Brazil’s any different.

I think we’ve already seen some tenders delayed from Petrobras. We’ve seen the IOCs who are still moving forward, but have kind of stalled a bit as they wait to see how this unfolds. I think around the globe and in every geo market, for the most part, you’re going to see a bit of a delay. But Roddie, I don’t know if you want to add anything specific to Brazil on that?

Roddie Mackenzie — Senior Vice President, Marketing, Innovation & Industry Relations

Yeah, sure. I mean in relation to the offshore drilling rigs, our part of the business saw a huge contraction over the last few years in Brazil. So when you talk about the overall capex cuts within Petrobras, it’s interesting to note that they haven’t really had many terminations of existing drilling contracts because they were — they had essentially got to a low ebb of contracts. And in fact, right now, there’s four major tenders out there at the moment that depending on how you count it, could be anywhere from eight to 10 rig years awarded to in excess of 20 rig years.

So it’s interesting that Petrobras has not canceled very many contracts. They are still continuing on with these tenders. And we kind of feel that our end of the business is not going to be dramatically negatively impacted in Brazil because it really was negatively impacted in the few years prior. So we still think that there’s going to be contracts awarded.

What I’d probably see is that there are several rigs that are coming off contract in Brazil in the next year or two. And it’s more likely that those rigs would be extended rather than seeing a significant influx of rigs. Reasons simply being that there is no money to bring rigs into Brazil unless it’s fully compensated by the operators at this time. So moving rigs into Brazil, mobilizations and then of course complying with local standards is pretty significant rig-by-rig.

So it’s our view that none of the contractors will be willing to subsidize that anymore. And we would expect that the local rigs are already in there with pickup a lot of the work. And any rigs coming from outside would be pretty significant dayrates. So it might be a little bit of time before we see a significant influx again, but it’s certainly not all doom and gloom on the drilling rig outlook in Brazil. In fact, it’s probably neutral compared to where it was.

Taylor Zurcher — Tudor Pickering & Co. — Analyst

Got it. Well, thanks for the answers, guys.

Operator

Thank you. We’ll move to our next question from Greg Lewis from BTIG. Please go ahead.

Gregory Lewis — BTIG — Analyst

Yes. Thank you, and good morning, everybody.

Jeremy D. Thigpen — President and Chief Executive Officer

Good morning.

Gregory Lewis — BTIG — Analyst

Jeremy, I guess just bigger picture question. I mean, clearly the last couple of years were challenging, but whether it’s two to three, four years from now, what make it through this in terms of the offshore rig market? So just kind of curious, given what you’ve seen over the last one or two years, as you think about what maybe like a normalized floater market looks like, if that’s even the right word. As we think about — I mean clearly rig retirements are going to happen again, they’ve already started, the market is still heavily oversupplied. I know it’s still early in this selling cycle to think about whether it’s how many rigs do we think needs to be retired this time around or what — how you think about normalized. Just kind of curious if you could give us any color around that?

Jeremy D. Thigpen — President and Chief Executive Officer

Yeah, sure. You know what, Greg, I don’t think our position has changed. Over the last five years, we have set about reshaping our fleet. And as kind of the premise behind that, it was — listen, we want to own the highest quality assets in the ultra-deepwater and harsh environment space because that’s where we think we can differentiate ourselves. And then we started to think about, okay, with these more efficient assets, are we going to need as many as we did during the last peak. And if you remember back in 2014, I think the total contracted floater fleet was approaching 260 floaters, something in that range. And we took the position that we’re never going to get back to that. That the industry with these new more efficient assets, mainly need 180 to 200, on the high-end maybe 220. And so we really started to shape our fleet with that in mind. And if you look at what we’ve done over the course of last five years with respect to the multiple retirement as well as the acquisitions and the newbuilds that we’ve introduced to the fleet, that’s really how we’ve been building Transocean.

So we’ll get through this pandemic. We’ll hopefully get back to some more normalcy, global economies tick-up, demand picks up, oil and gas — oil prices go back up into the, pick a number, $50, $60 range and rigs start to go back to work. We still think somewhere around a 180 of total floater, contracted floater count still feels about right. In fact, entering this year, we felt pretty good that we were going to start making our way toward that. I think we ended the year with about 150 floaters under contract, somewhere in that range or future contracted. And we saw demand on the horizon in 2020, 2021 and 2022 that could easily guess it’s the global fleet up to a number if that’s approaching 180. And so if things get back to normal, not all use their quotes as I say normal, we think we could easily see a fleet growing to that again. And really we take comfort in knowing that we’ve got — certainly all of our assets fall into that top 180. And so it should be fully utilized.

And with that, I’ll — let me hand it over to Roddie for any of his comments on that.

Roddie Mackenzie — Senior Vice President, Marketing, Innovation & Industry Relations

Yeah. I think I’d also add to that that we are encouraged to see that some of our competitors are finally acknowledging that they need to cold-stacked rigs and not keep them in the active supply. And I think we all know that cold-stacked rigs for any length of time makes some prime candidates for recycling. So while we were seeing utilization numbers climbing, obviously with the cancellations that have been suffered by many, we’re going to see that dip. But I think pretty quickly you might see that utilization numbers rebound because these rigs will be removed from supply.

So look, we applaud that, but also — I think that also bodes really well for the future viability of the business as people are now going to be looking at the ability to reactivate is no significantly diminished. If the dayrates don’t support it, there is not going to be spare cash, especially for those distressed contractors to basically put all those into the mix to try and grab market share at any cost. So we expect that some of that behavior will now be abated significantly and it will just be done through necessity.

So I think there could be a silver lining to this, but less rigs working means that they have to be working at better economics and no more disastrous free mobes and upgrades and also maybe some tightening of contract assurance. If you’re going to give away the rigs at the bargain basement prices, you would hope to at least had some certainty around collecting those revenues. So there could be some hard learned lessons here that perhaps we lift the entire industry in terms of economic returns on contract assurance, but yeah.

Gregory Lewis — BTIG — Analyst

Perfect. Let’s hope so. And then just, Roddie, I guess while I have you on the phone, this one is for you. You mentioned the 80 projects, the nine rig years. The rough math is, average year of one year. Is there any way to kind of shift through that? And really what I’m trying to get at is, as we think about those, is that going to translate into the basically 80 rigs working or really buried in those 80 projects, is there a lot of short-term work, is there any kind of multiyear term work if you skew it that way. Any kind of color you could give around that would be super helpful? Thanks.

Roddie Mackenzie — Senior Vice President, Marketing, Innovation & Industry Relations

Yeah. I’d say I think what I was talking about was the Brazil campaigns there. Yeah, the answer to the duration is that all of them are multiyear campaigns. I think even the shortest is going to be at least 12 months. But again, the idea about the short-term campaigns, it really is kind of moving away a little bit because typically the short-term campaigns were the ones that were exploration in nature. And then with success, those would lead on to development campaigns, which tend to be a lot longer.

So I think what we’re seeing at the moment is that the contracts that continue actually happened to be the development campaigns because they are related to increasing production. I think in the near-term, the retraction in the market, you will see will be primarily around exploration type activities. So I’d actually say you would see less short-term contracts right now because that’s where a lot of the terminations have come from.

Gregory Lewis — BTIG — Analyst

Okay. Thank you very much for — sure.

Jeremy D. Thigpen — President and Chief Executive Officer

Yeah. So Greg, just to add to that. When we — when I was mentioning the 80 different campaigns in the 90 rig years in my prepared remarks, that was really split across the globe. And I think obviously Norway continues to be, at least pre-pandemic, continues to be a very active spot with a lot of future activity on the horizon, but we were also seeing a tremendous pick up in the Gulf of Mexico, both the U.S. and Mexico side, Brazil and West Africa. The Gulf Triangle, if you will.

I think of all those programs that are still on the horizon, as we mentioned, they’ve just been pushed to the right a little bit in some areas. My personal belief is that West Africa is going to get hit hardest as a result of this pandemic as they’re really struggling to contain it whether it’d be a lack of medical resources or lack of social distancing [Indecipherable] but we think that area is really going to struggle. And so the delays there may be a little bit more than what we might see in other parts of the world.

Gregory Lewis — BTIG — Analyst

Perfect. Thank you everybody.

Operator

Thank you. We’ll move to our next question from Kurt Hallead of RBC. Please go ahead.

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Kurt Hallead — RBC Capital Markets — Analyst

Hey, good morning, everybody. Hopefully all your families are healthy and safe.

Jeremy D. Thigpen — President and Chief Executive Officer

Thanks. Likewise, Kurt.

Kurt Hallead — RBC Capital Markets — Analyst

Thanks. I appreciate that. So Jeremy, it appears that number of your competitors could be heading for Chapter 11 protection in the not too distant future. It sounds very clear to me based on the commentary from the press release and on the conference call here that Transocean is on very strong footing from a financial standpoint. Just kind of curious, in your mindset, when you think about the competitive landscape going forward and with some of your competitors are potentially going through a capital restructuring coming out with let’s say less encumbered balance sheets, do you think that that puts those companies on a better competitive footing or do you still feel very confident that from an operational and financial standpoint you guys will still lead the way through the next cycle phase?

Jeremy D. Thigpen — President and Chief Executive Officer

Thanks, Kurt. Good question. And what I can say is, we’ve already been through this. I mean we’ve had multiple competitors that have already gone through restructuring. One of them we acquired in Ocean Rig, but Pacific Seadrill, Vantage, all went through it. And what we saw in that experience is that our customers clearly demonstrated a favoritism, if you will, a preference for the more established drillers with the more solid balance sheets. And our thought is that they recognize that those companies had the cash to invest in the training of the people and the proper maintenance of the assets and that they were a lower risk option than a otherwise risky venture.

And so what we saw during that first phase of restructuring a couple of years ago was that we want a disproportionate number of contracts. And so my expectation would be that as our competitors go through that restructuring phase that once again our customers will look to the low risk option, which is Transocean both from an operation standpoint, but also from a balance sheet standpoint. And so my expectation would be that we would be able to grow market share at premium dayrates during that period of time.

Now, once our competitors come out of restructuring and had the opportunity to demonstrate that they can still safely, reliably, efficiently operate, they will have a lower cost base, we recognize that. But my guess is they won’t come through restructuring without any debt and probably not a lot of cash. And so they’re going to need to as per dayrates that help them generate enough cash to continue to invest in their business and service their maturities, which are likely to be pushed out, but they’re still going to have them.

And so we don’t — we’re not at this stage overly concerned about it because what we’ve seen play out in the past, didn’t support that it gave any of those restructuring competitors a competitive advantage. And Mark, I don’t know if you want to add anything to that?

Mark Mey — Executive Vice President and Chief Financial Officer

No, I think that’s right. Jeremy. And yes, our debt complex is trading hopefully low now as well. So as I said previously, we’ve been opportunistic in the past, we’ve been aggressive in the past and you can expect us to look at this and this take opportunity at this time as well to do something or gets stacked.

Kurt Hallead — RBC Capital Markets — Analyst

Awesome. That’s great color. Thanks. I appreciate that. Follow-up I had would be for Mark. In the liquidity forecast that you’ve provided for the end of 2021, Mark, does that include any draw on the revolver?

Mark Mey — Executive Vice President and Chief Financial Officer

Yeah. The forecast is 1.2 to 1.4. The midpoint obviously is 1.3, which happens to be the amount of our revolver. So if that forecast ends up being accurate then there is no need to draw on the revolver by the end of 2021.

Kurt Hallead — RBC Capital Markets — Analyst

Perfect. Thanks for that clarity. I appreciate it.

Operator

Thank you. We’ll move to our next question from Mike Sabella of Bank of America. Please go ahead.

Mike Sabella — Bank of America Merrill Lynch — Analyst

Hey, good morning, everyone.

Jeremy D. Thigpen — President and Chief Executive Officer

Good morning.

Mike Sabella — Bank of America Merrill Lynch — Analyst

So I know, you guys have been talking a lot about getting cost down, that’s obviously a big focus and there were some discussion around getting costs down off of the rig. I was wondering if we could kind of move onto the rig. Like, are there any strategies you guys are undertaking that could help bring down opex at the rig level maybe through automation or renegotiating contracts with vendors that can pull costs down there?

Jeremy D. Thigpen — President and Chief Executive Officer

Yeah. So as you know, since late 2014, 2015, we have aggressively look for every opportunity to safely reduce our cost structure, both on the rigs and onshore. And I think the team has done a fantastic job of rightsizing the business to the new reality. Obviously, we’re going to go through that process again given the impact that COVID-19 has had on oil prices and the business at large.

I would say offshore, as it comes to our major spend components from an equipment standpoint, we structured long-term what we call care agreements, healthcare agreements with all of our major OEMs across the entire rig. So every major component we have long-term agreements with already pre-defined pricing that we obviously negotiated at a pretty steep discount. And so there’s not a lot that can be done with those. Those are in place. They’re multiyear. And really, honestly, having been an OEM myself, I know there’s not a lot more for those guys to give. And so not a lot we can do there.

If you look at the other big spend components on the rig, you’re really talking crew and fuel. So from a crew standpoint, we continue to look at optimal crew sizes. We have worked very closely with one of our customers in the Gulf of Mexico to significantly reduce the number of personnel required on the rig. It’s a tremendous savings, which mostly goes to our customer. Nevertheless, it makes our offshore operations lower cost, and therefore, projects more economically viable. So we have undertaken efforts to reduce the size of the crew on — especially on our big dual activity seventh-gen rig.

And then on the fuel side, last year, we introduced the industry’s first hybrid power system onboard a floating asset and that was on the Transocean Spitsbergen. We are collecting data from that right now. We’re about four months in. And we are showing signs of a pretty meaningful fuel reduction, which obviously not only reduces our cost, but also reduces our carbon footprint and makes us more an environmentally-friendly, if you will, in the delivery of our service.

And so those are really the big buckets. So is there opportunity? Yes. Is it is going to be a game changer? Probably not because we’ve already rigged most of that low-hanging fruit. But let me turn it over to Roddie for some additional comments on that.

Roddie Mackenzie — Senior Vice President, Marketing, Innovation & Industry Relations

Yeah. You asked about things like automation on the rigs. And what I’d point out is, there are opportunities there, but we carefully analyze that on an ongoing basis. We actually have several projects on the go at the moment to assess the viability of increasing automation on the rigs. But the truth of the matter is, it involves investment, it involves buying equipment and it involves taking time out and install things. So the reality of the situation is, unless those things that are being compensated directly, it’s unlikely to see a wholesale move towards significant automation without an injection of capital from the end user ultimately, which is going to be the customers.

So right now, clearly, they’re not thinking about that. We keep these projects on the back burner. We keep thinking about that kind of stuff, but certainly we will not be investing heavily in these kind of technologies without a decent return.

Mike Sabella — Bank of America Merrill Lynch — Analyst

That’s great. Thanks. And then just a quick follow-up, if I could. We just talked for a bit about working capital, are there levers you guys are planning on pulling this year to free up some cash from working capital? And Mark, if we could just kind of talk through how you see working capital in the liquidity forecast that you gave?

Mark Mey — Executive Vice President and Chief Financial Officer

Yeah. So we have an ongoing initiative right now with regards to looking across our fleet for inventory to be shared amongst rigs. We’ve initiated that last year. [Indecipherable] recently. So the rig needs something which things the central facility to see whether the material is there. If it is, I think it’s up to that rig. We’ve also, as we always are, we’re very focused on revenue collections. So I feel like our team focus has a target of 75 days and we have 77 days for this quarter and we’re vigilant with regard to chasing that. So those two items are clearly what we’re looking at when it comes to working capital. But beyond that, there is so much else we can do on that front at this stage.

Mike Sabella — Bank of America Merrill Lynch — Analyst

Great. If you could just — to Mark, real quick. The $45 million I think you’ve budgeted for kind of call it special COVID-type costs. Can you just talk us through the shape of that spend? I’m assuming it’s pretty 2Q heavy, but just want to understand that?

Mark Mey — Executive Vice President and Chief Financial Officer

Yeah. It’s mainly a second quarter with some of it’s spilling over into the third quarter.

Mike Sabella — Bank of America Merrill Lynch — Analyst

That’s great. Thanks so much guys.

Operator

Thank you. And we will move to our next question from Sean Meakim of J.P. Morgan. Please go ahead.

Sean C. Meakim — J.P. Morgan — Analyst

Thank you. Jeremy, you’ve given out some plans to scrap rigs, your peers are starting to do the similar thing. As you noted earlier, there’s less cash in the system to fund long-term stacking programs compared to maybe in the 2015 or 2017 downturn. Can you maybe just give us a sense of how much floater supply you think could come out permanently over the next 12 months to 18 months?

Jeremy D. Thigpen — President and Chief Executive Officer

It’s difficult to say. Sean, we’ve never been overly hung-up on the total number of floaters that reside in a database. We had been more concerned about those that are active or could become active and marketable with some investment from either ourselves or from our peers. And so we’ve got this Investor Relations presentation, and I think we had this slide in just about every deck, but it kind of shows what we think is contracted supply, marketable supply, what it’s going to — how many rigs need between $5 million and $25 million and which rigs need more than $25 million in order to reactivate.

And as you look through that schedule, I think we’ve identified 40 to 50 rigs that we don’t think we’ll ever get another contract just because one, they’re older, technically less capable and/or is going to require a massive reactivation to get them back up and running. And so I don’t think this changes that story. I think maybe some of our competitors just finally throwing the towel and say, okay, we’ll officially scrap it now. But really, I’m not as concerned about the total number of suppliers as I am Transocean have in the best available assets in the industry.

And so it will certainly bring down the total supply number. We’ve already seen — I mean, we’ve announced some recent retirements that some of our peers had as well. And my guess is you’ll see more of that as we work through the next several months.

Sean C. Meakim — J.P. Morgan — Analyst

I appreciate that. That makes sense. So then just in other words, thinking about it then if we go through another 12 months to 18 months of relatively low level of — levels of activity, perhaps again lower than where we were coming into 2020, how many more of those rigs could push over the edge versus that 40 to 50 that you mentioned previously?

Jeremy D. Thigpen — President and Chief Executive Officer

Sorry. Ask it again.

Sean C. Meakim — J.P. Morgan — Analyst

So the question would be, the 40 or 50 rigs you’ve identified as being unlikely never come back, how much of that number increase if we go through in a 12 month to 18 month period with activity levels at or below where we were coming into 2020?

Jeremy D. Thigpen — President and Chief Executive Officer

Yeah. It’s a good question. I don’t know if that number necessarily increases, but it probably pushes some rigs far, even far right before they can actually come out with the reactivation because the dayrates just won’t be there to support it. And so I think what you’ll find is a much smaller active fleet globally and that those rigs that do stay active start to really push dayrates up in a meaningful way before anyone can afford to reactivate any of the assets they’re going to be cold-stacked during this latest downturn.

Sean C. Meakim — J.P. Morgan — Analyst

Right.

Mark Mey — Executive Vice President and Chief Financial Officer

And the cost directed at those rigs — cost as well will go up dramatically.

Sean C. Meakim — J.P. Morgan — Analyst

Yeah, I think that’s right. Okay. Thank you very much.

Operator

Thank you. That is all the time we have for questions. Mr. Alexander, at this time, I’d like to turn the conference back to you for any additional or closing remarks.

Bradley Alexander — Vice President, Investor Relations

Thank you, Valerie, and thank you to everyone for your participation 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 second quarter 2020 results. Have a good day.

Operator

[Operator Closing Remarks]

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