Transocean Ltd

NYSE:RIG

Earnings Call Transcript 2020-Q1

[Operator]

Good day, and welcome to the Q1 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 of Investor Relations. Please go ahead, sir.

[Brad Alexander, Vice President of 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 other 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 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 Thigpen, President, Chief Executive Officer]

Thank you, Brad, and welcome to our employees, customers, investors and analysts participating in today's call. Before we dive in to 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 session 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 operation, 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 multi-year campaigns with Petrobras in Brazil during the fourth quarter of last year.

Also in the first quarter the Deepwater Asgard entered into a 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 a campaign with Premier in the U.K. in March and is 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 are 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 a possibility that Equinor could exercise follow-on options extending her through the year.

In the U.K. we have worked with our customer Chrysaor who is drilling with a 712 to delay their drilling campaign into the fall, allowing us to substitute for the 712 with either the Paul B. Loyd or the 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 who has just completed a successful Five-Year campaign with Chevron has now begun her contract with Talos in the Gulf of Mexico. Her superior drilling performance with Chevron was instrumental and are contracting immediate follow-on work that keeps her working into the third quarter.

In Trinidad, the DD III is in the process of going through Acceptance testing we 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, anchoring this rig to ensure we deliver the asset to our customer as expected despite the challenges presented by COVID-19.

The performance of the transition of 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 cancellations and scheduling changes, obtaining critical inventory and part, safety and health check of all personnel onboard, maintaining a safe work area and living quarters while still following social distancing recommendations, and where required through isolations and evacuations.

I am beyond proud of the entire transition team and their efforts to ensure operations safely continue. We have kept our fleet on contract and operated to transition high standards for safety, reliability and efficiency.

Even in the instances where our customers or not-transitioned rig personnel are unable to reach the rig, including our only instance of the 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, located and book the necessary accommodations to ensure employees have places to stay before and after crew changes and closely coordinate with suppliers and freight forwarders to keep our rigs 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. For this I say thank you to the entire team at Transocean.

Looking at our fleet, we’ve recently taken the action to responsibly recycle four older stacked assets, the Polar Pioneer and the Songa Dee from our harsh environment fleet and the 711 and 714 from our mid-water fleet. All of these assets were at least 35 years old and with a significant cost required for their respective reactivation, 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 as it is perceived to impact the Transocean, 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 day rate perspective, but the quality of the customers and the strength of the terms and conditions in the contract. While we are and will 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 a significantly longer remediation period than is standard in the industry.

I would again like to empathize, we will continue to remain vigilant and doing everything we can to keep our rigs COVID-19 free and will 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 complimentary 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 this deep decrease we have seen in oil prices in the past three months, customer budgets have been significantly reduced. So while our backlog remains a source of strength, our near term outlook for new work and escalating day rates is obviously tempered.

Having said that, we've been encouraged to see that our customers are not canceling projects that were likely to proceed earlier in the year, but rather looking to defer and postpone their sanctioning generally by nine 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 represent a better investment opportunity for our customer base than their onshore projects.

In response to the current market conditions, and similar to the steps we took during the previous downtown 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 to discuss previously with the 712 to transfer future work on the Lloyd as a leader to last and more efficiently run our fleet. While other similar opportunities present themselves, we will look to capitalize on these situations. In an effort to further manage our costs, we will also be decisive and 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 commitment of new projects, we are working diligently with our customers who 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 fleets.

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 are 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 remained significant customer interests regarding Atlas and her potential to become the industry's second 20,000 psi ultra-deepwater drillship. That said 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 close to delivering the state of the art asset to the industry.

In conclusion, we are disappointed that the broad recovery [Technical Difficulty] are 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 as a clear leader in the environment in ultra-deepwater drilling and will continue to strategically refine our fleet to future enhance that position. As such, we expect that our marketed fleet will remain the industry’s most utilized as we successfully navigate this extended downturn. Mark?

[Mark Mey]

Thank you, Jeremy, and good day to all. During today's call I will briefly recap our first quarter results and then provide guidance for the second quarter. Lastly, I’ll provide an update on our liquidity forecast though 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 changes and the previously announced further 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 94.4%, 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 $170 million [ph] attributable to opportunistic open market repurchases and biannual amortization of our secured bonds, partly offset by the refinancing of our 2023 priority guaranteed notes.

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, which was 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 to 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 from maturity.

We are ending the first quarter with total liquidity of approximately $3 billion. Including unrestricted cash and cash equivalence of $1.5 billion and approximately $200 million of restricted cash dedicated for debt service and $1.3 billion from undrawn revolving credit facility.

Consistent with last year and with the timing of interest and tax payments and 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 in 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 lower activity as a result of a reduced duration of the Discoverer, India’s contract coupled with the delay in trends for the Chrysaor drilling program on 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 due to contracts being deployed and 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 for crew changes, retail costs 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, which is a result of 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. Recently 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 and $30 million of interest income.

Capital expenditures, including capitalized interest for the second quarter 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 of 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 projected 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 as discussed previously and a reduced 2021 CapEx expectation of $815 million. The 2021 CapEx includes $750 million related to newbuilds and $65 million for maintenance CapEx. Please note that our CapEx guidance excludes any speculative reactivations or upgrades.

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

I will now turn the call back over to Brad.

[Brad Alexander, Vice President of Investor Relations]

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

[Operator]

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

[Ian Macpherson, Simmons]

Thanks. Good morning guys. Jeremy, I understand that there’s – it sounds like you're contemplating the possibility of flexing the Atlas towards you know 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 accepting that rig on-schedule versus what levers do you have to [inaudible] for that.

[Jeremy Thigpen, President, Chief Executive Officer]

Yeah, good question. 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 them some disruption. They've had some disruptions from some of the equipment providers in terms of the delays providing products. And so we are doing our best to juggle both assets. Of course the Titan already has a contract with Chevron, so we are obviously mindful of that.

As I mentioned in my prepared comments, it's quite honestly been a bit surprising and pleasantly surprising to me to see that our customers who were previously interested in securing the Atlas and then upgrading her to a second 20K 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 result 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 work 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, the shipyards and the OEMs to work on the timing of that.

[Ian Macpherson, Simmons]

Okay, got it. Well, you know 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 with – you know 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's an added layer of cost for logistics, you know through evacuations or isolating cruise, etcetera, 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 disruptions of this virus, and is any of that subject to negotiations or fallbacks. How are you sharing that cost if it isn’t in fact material to you?

[Jeremy Thigpen, President, Chief Executive Officer]

You know, I’ll let Mark handle that, but I will tell you, we are incurring additional costs as you rightly pointed out and Mark can give more specific 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]

No, that’s exactly right. Good morning, Ian. In my prepared comment I actually mentioned that we anticipated about $45 million of additional costs this year, mainly around overtime, hiring chartered flights or contract boats, hotel costs. Some of this is re-billable to the customers, some of it maybe, 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]

That's helpful. Well, good luck with everything and thank you guys.

[Jeremy Thigpen, President, Chief Executive Officer]

Thanks Ian.

[Mark Mey]

Thank you.

[Operator]

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

[Connor Lynagh, Morgan Stanley]

Yes, thanks. I was wondering if we could discuss what your contract terms generally look like and I appreciate I’m asking you to generalize it with many different contracts, but it occurred to me that you have not really faced many contract cancelations 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 Thigpen, President, Chief Executive Officer]

Yes, sure. Let me just – they are different as you properly pointed out and it really matters as to whether we – when we negotiated the contracts. 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 specifics, let me just hand it over to our Senior VP of Marketing and Contracts, Roddie.

[Roddie Mackenzie, Senior Vice President of Marketing and Contracts]

Hi! Yes, so we have not seen the terminations that our competitors have seen and primarily that is due to stronger terms or convictions in the conditions. Now 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, you know I guess particularly difficult on the terms and conditions is really to avoid the situations where we get spurious terminations that happen quickly. It makes the customers think twice about whether it is necessary to terminate.

You know that combined with the stuff that Mark and Jeremy just went over in terms of our operations and our HR teams did you know a fantastic job at making sure that we are able to continue operations. Essentially force majeure situations are not upon us. They may be upon the customers at which they decide they wish to terminate, but in all the cases of the contracts we have, there's certainly remedy periods and a time to overcome those particular entities or if they wish to terminate quickly, then there's a pretty sizeable payout attached with those contracts.

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

[Connor Lynagh, Morgan Stanley]

It 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 you know the variable costs, the selling of the rig itself, what options do you have to actually further reduce your operating costs? There are any opportunities there?

[Jeremy Thigpen, President, Chief Executive Officer]

Let me hand that one over to Mark.

[Mark Mey]

So as I mentioned kind of on the market prepayments, and Jeremy mentioned the same thing, you know we have some long term contract that we run through the next year after that, so we’re not going to see any changes with that. But as we do have contracts that will run-off later this year or next year, we will take action to right size the business, to reflect the reduced footprint of the operating rigs.

So I cannot get into actual numbers right now, but into the fall we had folks supporting 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 right size those concessions [ph], move those folks around or end up sending some of them in cases where we depart a country.

[Connor Lynagh, Morgan Stanley]

Okay, I understood. Thanks for the color.

[Operator]

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

[Taylor Zurcher, Tudor, Pickering and Holt]

Hey, good morning, thank you. Jeremy you talked about working with some of your customer that have near term options, but also in the initial stages of a 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 arrangements moving forward.

[Jeremy Thigpen, President, Chief Executive Officer]

I'll start and then I'll hand it over to Roddie for his thoughts on that. We’ll 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 complimentary with the way we’ve handled it and the team deserves – I mean, not me. The operations team, the HR team, the travel team deserves a lot of kudos. They’ve just done, just some herculean work.

But once our customers started to get comfortable that we had this fairly well contained and with the 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 you know a reduced day rate for a period of time or you know a blend and extend type of conversation, and now I think we're getting to the point where people are really – our customers especially are 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.

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 of Marketing and Contracts]

Yes, we have seen that, which is encouraging actually, because it means that there is you know additional work to be performed for several of the operators, so we have a couple of requests to do that. But you know let me assure you, we will not be taking on any blend and extend that the extension equivalent day rate would be you know a cash breakeven or something like that.

I mean we really view that now more than ever your cost should include all overheads, all amortization of shipyards, all things associated with mobilizations and none of those should be given away for free. You know we’re very disciplined as Jeremy said before, but we never did that in the downtime. 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 now more than ever, it’s essential for drillers if they wish to have any degree of viability to make sure those costs are fully captured and remunerated. So yet blend and extend are possible, but you're not going to see them at bargain basement numbers from our point of view.

[Taylor Zurcher, Tudor, Pickering and Holt]

Okay, that’s really helpful. And in my follow-up, I wanted to ask about Brazil. Obviously we've seen a big CapEx reduction announcement from Petrobras. A bit unclear it’s to me, what that means for the planned rig needs over the next, at least year? At the same time, a lot of the IOCs that 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 in here and in Brazil.

[Jeremy Thigpen, President, Chief Executive Officer]

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's going to get pushed to the right for a period of time and I don't think Brazil’s any different.

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

[Roddie Mackenzie, Senior Vice President of Marketing and Contracts]

Yes, sure. I mean in relation to the offshore drilling rigs, you know our part in 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 they haven't really had many terminations of existing drilling contracts, because they had essentially got into a low ebb of contracts and in fact right now there's four major tenders there at the moment, but you know depending on how you count it, it could be anywhere from eight to 10 rig years awarded to you know in excess of 20 rig years.

So it's interesting that Petrobras has not cancelled 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 say 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, the reason simply being that there's no money to bring rigs into Brazil unless its 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. We’d pick up a lot of the work and any rigs coming from outside would be at pretty significant day rates. 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 and Holt]

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.

[Greg Lewis, BTIG]

Yes, thank you and good morning everybody.

[Jeremy Thigpen, President, Chief Executive Officer]

Morning!

[Greg Lewis, BTIG]

Jeremy, I guess just you know bigger picture question. I mean [inaudible] you know a couple of years are challenging, but whether its two to three, four years from now, we’ll make it through this in terms of the offshore rig market.

So just kind of curious, given what we've seen over the last you know one to two years, as you think about what may be like a normalized slate of the market looks like, if that’s even the right word, as we think about – you know I mean clearly regular timings are going to happen again and they’ve already started, you know and the markets still have a little bit of supply. I know it's still early in this cycle to think about you know whether – how many rigs do we think need to be retired this time around or how you think about more life. Just kind of curious if you can give us any color around that?

[Jeremy Thigpen, President, Chief Executive Officer]

Yes, sure. You know what Greg, I don’t think our position has changed. Over the last five years, we’ve said about reshaping our fleet and as kind of the premise behind that, it was – listen, we want to own the highest quality asset 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 or 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 may only need 180 to 200, on the high end maybe 220, and so we really started to shape our fleet with that in mind. If you look at what we've done over the course of the last five years with respect to the multiple retirements, as well as the acquisitions and the new built that we’ve introduced to the fleet, that's really how we've been building Transocean.

So, you know we get to this pandemic. We’ll hopefully get back to some more normalcy. Global economies pick up, demand picks up, oil prices go back up into the – you know pick a number, $50, $60 range and rigs start to go back to work. We still think you know somewhere around you know 180 of total floater, contractor float accounts still feels about right. In fact entering this year we felt pretty good that we were going to start making our way towards that.

I think we ended the year with about 150 floaters under contract somewhere in that range or are future contracted and we saw demand on the horizon in 2020, 2021 and 2022. That could easily get the global fleet up to a number that’s approaching 180 and so you know if things get back to normal and all units are equipped with as I say normal, 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.

With that, let me hand it over to Roddie for any of his comments on this.

[Roddie Mackenzie, Senior Vice President of Marketing and Contracts]

Yes, I think I’d also add to that and that you know we’re encourage to see that some of our competitors are finally acknowledging that they need to cold stack rigs and not keep them in the act of supply. And I think we all know that you know cold stacked rigs for any length of time makes them 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 reviving, 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 has now significantly diminished. If the day rates don't support it, there's not going to be spare cash, especially for those distressed contractors to basically throw those into the mix, to try and you know 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 you know less rigs working means that they have to be working at better economics and no more disastrous fee modes [ph] and upgrades.

And also maybe some tightening of contract assurance. You know if you're going to give away the rigs at the bargain basement prices, you would hope you at east have some certainty around collecting those revenues. So there could be some hard learned lessons here that perhaps would lift the entire industry in terms of economic returns and contract assurance, but yeah.

[Greg Lewis, BTIG]

Yeah, perfect! Let’s hope so. And then just Roddie, you know while I guess I have you on the phone, this one’s for you. You mentioned the 80 projects, the nine rig years [inaudible] you know outage year of one year. Is there any way to kind of sit through that and really what I'm trying to get at is you know as we think about those, that can translate into basically 80 rigs working or really buried in those 80 projects has been a lot of short term work. Is there any kind of multi-year term work that would skew it that way? Any kind of color you could give around that would be super helpful. Thanks.

[Roddie Mackenzie, Senior Vice President of Marketing and Contracts]

Yeah, actually I think what I was talking about was the Brazil campaigns there. The answer to the duration is that all of them are multi-year campaigns. I think even the shortest one is going to be at least 12 months. But again, the idea about the short term campaigns really is kind of moving away a little bit, because typically these short term campaigns were the ones that were exploration in nature and then you know with success those would lead on to development companies which tend to be a lot longer.

So I think what we're seeing at the moment is the contracts that continue actually happen 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 as you say, you would see less short term contracts right now, because that's where a lot of the terminations have come from.

[Cross Talk]

[Greg Lewis, BTIG]

Thank you very much. Sure.

[Jeremy Thigpen, President, Chief Executive Officer]

Yeah, so Greg just to add to that, when we – when Rod was mentioning the 80 different campaigns, short term campaigns and the 90 rig years and I think it was [Technical Difficulty] that was really spread 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 [Technical Difficulty] 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, that’s the gold 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's going to get hit hardest as a result of this pandemic as they are really struggling to contain it, you know whether it be a lack of medical resources, a lack of social distancing, just [Technical Difficulty] but just we think that areas really been struggling, so the delay there may be a little bit more than what we might see in other parts of the world.

[Greg Lewis, BTIG]

Thank you everybody.

[Operator]

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

[Kurt Hallead, RBC]

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

[Jeremy Thigpen, President, Chief Executive Officer]

Thanks. Likewise Kurt.

[Kurt Hallead, RBC]

Thank you, I appreciate that. So Jeremy, it appears that a 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, you know in your mindset, when you think about the competitive landscape going forward and that some of your competitors are potentially going through a capital restructuring and 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? Thank.

[Jeremy Thigpen, President, Chief Executive Officer]

Thanks Kurt. Good question and what I can tell you 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 in 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 sheet 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 an otherwise risky venture.

And so what we saw during that first phase of restructuring a couple of years ago was that we won 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 day rates during that period of time.

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

And Mark, I don't know if you want to add anything to that?

[Mark Mey]

No, I think that's right Jeremy. And look, our good 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 take this opportunity this time as well to do something and [Inaudible].

[Kurt Hallead, RBC]

That's great color. I appreciate that. The follow-up I have would be for Mark. You know in the liquidity forecast that you provided for the end of 2021. Mark, does that include any draw on the revolver?

[Mark Mey]

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

[Kurt Hallead, RBC]

Alright, 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]

Hey, good morning everyone. So I know and you guys have been talking a lot about getting cost down, so obviously a big focus and there was some discussion around you know getting cost 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 you know OpEx at the rig level, you know maybe through automation or renegotiating contracts with vendors, you know that can pull cost down there.

[Jeremy Thigpen, President, Chief Executive Officer]

Yeah, so as you know since late 2014, 2015 we have aggressively looked for every opportunity to safely reduce our cost structure, both on the rigs and on shore and I think the teams done a fantastic job of right sizing 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 you know oil prices and the business at large.

I would say offshore as it comes to you know our major spend component, 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 predefined 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 are multi-year 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 adding more 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, but nevertheless it makes our offshore operations lower costs and therefore projects more economically viable. So we have undertaken efforts to reduce the size of the crew, especially on a 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 transition to Pittsburg and we are collecting data from that right now. We're about four months in and we are showing signs of pretty meaningful fuel reduction, which obviously not only reduces our costs, but also reduces our carbon footprint and makes this more an environmentally friendly if you will in the delivery of our service.

And so those are really the big bucket, so is there opportunity? Yes. Is it 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 of Marketing and Contracts]

Yeah, you asked about you know things like automation on the rigs and what I’d point 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 to install things.

So the reality of the situation is unless those things 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 are not thinking about that. You know 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]

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 leverage you guys are planning on pulling this year to free up some cash from working capital? And Mark, you know it we could just kind of talk through how you see working capital in the liquidity forecast that you gave?

[Mark Mey]

Yeah, so we have an ongoing initiative right now with regard to looking across our fleet for inventory to be shared amongst rigs; we shared that last year. We’ve automated it recently, so if a rig needs something, it pings the central facility to see whether the material is there. If it is, then it gets shipped to that rig. We’ve also, as we always are, we are very focused on revenue collections. So I think our team will focus at a target of 75 days and we have 77 days for this quarter and we are vigilant when its regard to chasing that. So those two items are clearly what we are looking at when it comes to working capital, but beyond that, there is so nothing much else we can do on that front at this stage.

[Mike Sabella, Bank of America]

If you can, just two more real quick. The $45 million I think you budgeted for, you know kind of call special COVID type costs. Can you just talk through the shape of that spend and I’m assuming it’s pretty 2Q heavy, but I just want to understand it?

[Mark Mey]

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

[Mike Sabella, Bank of America]

That’s great. Thanks so much guys.

[Operator]

Thank you. And we’ll move to our next question from Sean Meakim with JP Morgan. Please go ahead.

[Sean Meakim, JP Morgan]

Thank you. Jeremy, you even have some plans to scrap rigs. Your peers are saying the same. As you noted earlier, there's less cash in the system, the firm’s long-term stacking programs compared to maybe even 2015 or 2017 downturn. Can you maybe just give us a sense of how much floater supply you think would come out permanently over the next 12 to 18 months?

[Jeremy Thigpen, President, Chief Executive Officer]

It is difficult to say. Sean, we’ve never been overly hung up on the total number of floaters that reside in a database. We have 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, how may 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 will ever get another contract, just because one, they are old, they are technically less capable and/or is going to require a massive reactivation fee 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 saying okay, we’ll officially scrap it now, but really I’m not as concerned about the total number of supplies and about the transition that happen to the best available asset 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, some of our peers have as well, and I guess that you'll see more of that as we work through the next several months.

[Sean Meakim, JP Morgan]

I appreciate that; that that makes. So then just in other ways talking about then, if we go through another 12 to 18 months of relatively low 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 or 50 that you mentioned previously?

[Jeremy Thigpen, President, Chief Executive Officer]

Sorry, ask it again.

[Sean Meakim, JP Morgan]

So the question would be the 40 or 50 rigs you’ve identified as being unlikely to every come back, how much does that number increased if we go through another 12 to 18 month period with activity levels at or below where we were coming into 2020.

[Jeremy Thigpen, President, 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 farther to the right before they can actually come out with the reactivation, because the day rigs 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 day rates up in a meaningful way, before anyone can afford to reactivate any of the assets that are going to be cold stacked during this latest downturn.

[Mark Mey]

And the cost to activate those rigs, that cost as well will go up dramatically.

[Sean Meakim, JP Morgan]

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.

[Brad Alexander, Vice President of 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]

This concludes today's call. Thank you for your participation. You may now disconnect.