Transocean Ltd  (NYSE: RIG) Q4 2019 Earnings Call Transcript

Transocean Ltd  (NYSE: RIG) Q4 2019 Earnings Conference Call

February 18, 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 and Industry Relations

Analysts:

James West — Evercore ISI — Analyst

Connor Lynagh — Morgan Stanley — Analyst

Gregory Lewis — BTIG — Analyst

Taylor Zurcher — Tudor, Pickering, Holt & Co. — Analyst

J.B. Lowe — Citi — Analyst

Mike Sabella — Bank of America Merrill Lynch — Analyst

David Smith — Heikkinen Energy Advisors. — Analyst

Kurt Hallead — RBC Capital Markets — Analyst

Chris Snyder — Deutsche Bank — Analyst

Presentation:

Operator

Ladies and gentlemen, good day, and welcome to the Quarter Four 2019 Transocean Earnings Conference Call. [Operator Instructions]

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

Bradley Alexander — Vice President, Investor Relations

Thank you, David. Good morning and welcome to Transocean’s fourth quarter and year-end 2019 earnings conference call. A copy of our press release covering financial results, along with supporting statements and schedules including reconciliations and disclosures regarding non-GAAP financial measures, are posted on our website at deepwater.com.

Joining me on this morning’s call are Jeremy Thigpen, President and Chief Executive Officer; Mark Mey, Executive Vice President and Chief Financial Officer; and Roddie MacKenzie, Senior Vice President of Marketing and Contracts.

During the course of this call, Transocean management may make certain forward-looking statements regarding various matters related to our business and company that are not historical facts. Such statements are based upon the current expectations and certain assumptions and are therefore subject to certain risks and uncertainties. Many factors could cause actual results to differ materially. Please refer to our SEC filings for more information regarding our forward-looking statements, including the risks and uncertainties that could impact our future results. Also, please note that the Company undertakes no duty to update or revise forward-looking statements.

Following Jeremy and Mark’s prepared comments, we will conduct a question-and-answer session. During this time, to 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 everyone participating in Transocean’s fourth quarter and full year 2019 earnings call. I’d like to start today’s call with a recap of 2019. As reported in yesterday’s earnings release, for 2019, the Company generated adjusted EBITDA of $979 million on $3.3 billion in adjusted revenue, resulting in an industry-best adjusted EBITDA margin of 30%.

As I’ve stated many times previously, Transocean is acutely focused on enhancing the quality of our fleet; driving operational excellence through continuous improvements in safety, uptime and drilling efficiency; expanding our position as our customers’ universal first choice through relationships, exceptional operating performance and the introduction of new technologies; and extending our liquidity runway by adding to our industry-leading $10.2 billion backlog, converting the maximum percentage of that backlog to cash and prudently bolstering our balance sheet through timely transactions. In 2019, we again took actions to further each of these objectives.

Looking first at our fleet, in August, the Transocean Norge entered our active fleet, commencing her maiden contract with Equinor Norway. This high-specification harsh environment asset is the sixth floater we now have working for Equinor, and we will soon increase that total to seven when we commence the contract for the Barents in Canada, quite a testament to the relationship we have built with the industry’s largest harsh environment operator. As a further example of the strength of the relationship and Transocean’s ability to successfully deliver newbuilds to the industry, we are proud to report that Equinor has already exercised the Norge’s first two options.

Speaking of newbuilds, we are now approximately a year and a half away from the introduction of the world’s first 20,000 PSI capable ultra-deepwater drillship. Construction on the Deepwater Titan has progressed as planned, and we look forward to delivering this drillship to Chevron for her maiden contract commencing in 2021. This five-year contract will allow Chevron to construct and ultimately produce the first fields in this extremely high pressure area of the lower tertiary in the deepwater Gulf of Mexico. The desire to exploit this basin is driven by the exceptional returns Chevron anticipates, with development cost for this first field, Anchor, now estimated to be as low as $20 per barrel.

As reported in our last call, we continue to explore opportunities that would make our final newbuild asset, recently named the Deepwater Atlas, the world’s second 20,000 PSI drillship. With multiple operators requiring a rig for their ultra-high pressure properties in the Gulf of Mexico, the Atlas, with its 3 million pound hook load derrick, is ideally suited.

In addition to these newbuilds, we’ve also reactivated and deployed two previously stacked assets. During the fourth quarter, we completed the first reactivations of assets acquired in the Ocean Rig transaction, the Deepwater Mykonos and the Deepwater Corcovado. Both rigs have commenced drilling operations in Brazil for Petrobras and are contracted well into 2021 with options that extend into 2023. We now have three revenue-generating assets in Brazil, enabling us to spread our shore-based costs, increasing our efficiency in country.

In furtherance of our fleet strategy, we also announced the retirement of six older, less marketable assets during the year. As such, we exit 2019 with 47 floating rigs, of which 44 are either ultra-deepwater or harsh environment assets. As we close 2019, we are proud to have assembled the industry’s most capable fleet of rigs, operated by its most experienced crews. This ideally situates us for the ongoing market recovery.

Moving from fleet quality to operational excellence, I’m pleased to report that in 2019, we delivered another year of strong uptime performance across our global fleet, with uptime of almost 97% and revenue efficiency exceeding 97%. While our ultimate goal is to deliver 100% uptime for our customers, we take pride in these numbers, which reflect improvements on both metrics from our 2018 results and continuing multi-year trend of exceptional performance.

As we strive to drive operational excellence through improvements in safety, uptime and drilling efficiency, I’d like to spend a few moments discussing some of the differentiating technologies that we are delivering to the industry. Automated Drilling Control, or ADC, Halo Guard, aShear and hybrid onboard power represent a few of the technologies that focus on the important aspects of drilling more efficient wells with high rates of penetration; ensuring the safety of our crews, assets and the environments in which we operate; and reducing fuel consumption, carbon footprint and emissions.

Starting with ADC, this system captures critical downhole information while drilling. Through the use of real-time data telemetry and a combination of software applications, ADC enables more efficient well construction. In short, ADC is the first step towards automating the well bore construction process and makes the entire process safer, faster and more reliable. ADC is in the process of being deployed on six of our rigs drilling for Equinor in Norway, and we are actively evaluating the deployment on other rigs in our fleet.

Halo Guard is a Transocean patented system designed in collaboration with two of our suppliers that prevents dangerous impacts between moving equipment on the drill floor and our personnel working in the vicinity of that equipment. Using position sensors and cameras operating with visual recognition technology, the Halo Guard system sends a warning signal to personnel when they are dangerously close to moving equipment. If the individual fails to remove him or herself from harm’s way, the system will ultimately halt the piece of moving equipment to prevent injury to the individual. Halo Guard is currently being piloted in the Gulf of Mexico. Once proven, we intend to deploy this system across our fleet.

AShear provides unmatched shearing capability in the event of a well control incident. No matter what may be encountered in the well bore, including casing, joints and/or tools, aShear possesses the capability to slice objects in a matter of milliseconds, allowing a blowout to be addressed instantaneously. Needless to say, we are excited about aShear as this game-changing technology provides a level of assurance and enterprise risk reduction not previously available in the offshore drilling industry. The technology is depth-agnostic and is retrofitable to existing BOP stacks. aShear has been successfully tested offshore, and we are now working with the regulators and several customers to deploy multiple units this year.

The last technology I will discuss is hybrid onboard power. This first of its kind solution both reduces fuel consumption and emissions, while providing a secondary safety source of power in the event of a complete loss of functionality of the rig’s engines. The system also eliminates peak power demands on the diesel generators through the use of stored energy, allowing the engines to run in a steadier state. This reduces engine wear while increasing overall rig fuel efficiency. It also alleviates the need to run a precautionary additional engine as is current standard practice. The hybrid system is currently in operation on the Transocean Spitsbergen with applicability across many assets within our fleet.

Understandably, we are extremely proud to be developing and deploying technologies that continue to drive improvements in personnel safety, provide additional safeguards for our assets and the environments in which we operate, improve drilling efficiency for our customers, and reduce our environmental footprint.

Turning back to 2019, Transocean won 28 floater awards, providing almost $890 million in incremental backlog. Importantly, since our last earnings call, we signed contracts totaling $250 million. And I’m pleased to report that for ultra-deepwater work not associated with previously priced options, the average fixture over that time frame was approximately $240,000 per day, an increase of approximately 75% from where we started 2019. I’m also pleased to report that these recent awards originated from a wide range of customers and span multiple offshore markets, reflecting the breadth of the ongoing recovery.

In the Gulf of Mexico, we signed a 100-day contract and a follow-on 74-day extension for the Deepwater Asgard with a new customer to Transocean, Beacon Offshore Energy, at an average dayrate of $225,000 per day. While we know that the value that we create with this industry-leading asset is worth far more than $225,000 per day, I want to congratulate our marketing team on their resolve as they rejected an offer to re-contract this rig for almost $30,000 a day less based upon their market intelligence and their confidence that better market opportunities were available.

We also signed a four-month contract for the sixth generation drillship, the Deepwater Inspiration, with Talos at a dayrate of $210,000 per day. Again, while we expect and will ultimately command a higher dayrate for this asset, we are pleased that this work immediately follows the completion of the Inspiration’s current campaign.

In Trinidad, we signed the DD3 to a one-year contract for $250,000 per day, plus mobilization. This contract will commence upon her completion of work in Equatorial Guinea in the second quarter. All of these fixtures reflect a tightening market for ultra-deepwater rigs we discussed during our third quarter call and demonstrate why we have confidence in getting a more appropriate value for the service we deliver with these high-specification assets.

Looking at the eastern hemisphere, Equinor has exercised its first two options to the Transocean Norge at $291,000 per day. Also in Norway, Conoco has signed a four-month contract for the Leiv Eiriksson, a fourth generation asset, at $235,000 per day, again, for work directly following its current campaign. And as we look at the Asia Pacific region, the KG2 has been contracted for six months, following its current job in Australia, by Woodside at a dayrate of $250,000 per day, plus mobilization. And we’re pleased that Petronas has exercised an option for the Deepwater Nautilus in Malaysia. Again, I’m very encouraged by these fixtures dayrates as they illustrate both the improvement we are seeing in the market and the discipline we’ve exercised in contracting. Most importantly, they demonstrate our customers’ desire to work with Transocean.

Looking now to the macro oil market, oil prices firmed during the fourth quarter of 2019 with Brent prices remaining solidly in the mid-to-upper $60 per barrel range. Break-even economics for the majority of our customers’ offshore projects continue to come in at or below $40 per barrel. And due to a lack of investment over the past five years, reserve replacement ratios continue to decline, boding well for sustainably increased activity offshore.

With all of these positive trends, I would be remiss not to acknowledge the risk of activity delays as a result of the coronavirus. Its near-term impact on oil demand and related effect on current oil prices impact our customers’ cash flow and therefore can result in delays in timing of anticipated project awards and commitments. While epidemics of this nature typically have short-term overall effects on energy consumption, there remain unknowns at this time that must be acknowledged.

Returning to the longer-term trends we continue to see in the market, a couple of other points remain critical. First, shale activity in North America continues to decline. Despite service pricing that is unsustainably low, North American rig activity fell 28% year-over-year in 2019. Additionally, oil supply growth from North America onshore activity in 2019 came in significantly below previous expectations. Further, this growth is expected to show material declines in 2020 and beyond. Empirically, we think this is more of a structural decline as lower-tier acreage is delivering lower rates of recovery than initially expected and decline rates on producing acreage are more significant than initially anticipated.

Second, the discipline that continues to be exhibited by the majority of producing nations is resulting in a much more balanced market. This is reducing the fear of a sudden and potentially lengthy decline in oil prices. As longer term consumption is likely to continue growing in excess of 1 million barrels per day, we believe that these factors should support and hopefully strengthen the recovery that we are already witnessing in the offshore market.

Starting with the Gulf of Mexico, as anticipated, we have witnessed significant tightening, as evidenced by the number of fixtures announced over the last few months. For the high-specification assets, we see a virtually sold-out market for the majority of 2020. In fact, we’ve been contacted by customers about bringing additional rigs into the Gulf to meet their demand. As our customers continue to realize the favorable economics offshore, we are witnessing a shift in focus towards the deepwater. The opportunities include greenfield development, tie-backs and exploration. In fact, some industry reports indicate deepwater exploration projects will outpace development in 2020 for the first time since 2014.

Specific to Transocean, we remain encouraged about the prospects for a second 20,000 PSI capable ultra-deepwater drillship. We continue to have advanced discussions with multiple operators regarding the need for another rig to operate in the lower tertiary and believe a final investment decision to proceed could come soon.

The Mexican portion of the Gulf also presents a significant area of potential for ultra-deepwater activity. Multiple operators continue to drill exploration wells, and we understand that the results are very promising. This should come with little surprise if the geology is very well understood based on activity that has occurred on the US side for many years. We drilled the first ultra-deepwater wells in Mexican waters for three customers beginning in 2019 and are very encouraged that a number of development opportunities that would require dedicated rigs on long-term fixtures appear to be materializing.

In the Caribbean, where several contracts were recently awarded in Trinidad, we believe the continued drilling success will lead to additional rigs. Beyond Trinidad, multiple campaigns in Guyana continue pointing towards incremental demand as new development opportunities materialize. In neighboring Suriname, we also see the potential for the rig count to grow, assuming recent well success is duplicated.

In Brazil, we expect to see a number of opportunities coming to tender for Petrobras, as well as several highly anticipated multi-year IOC programs. This demand will require incremental rigs in country, resulting in tighter utilization for ultra-deepwater drillships worldwide.

Looking at West Africa, we are pleased to see demand further materializing, starting with Angola, where we are now seeing several IOCs with multi-year programs out for tender. We think this could require at least three incremental rigs. Additionally, there are an increasing number of multi-year opportunities in Mozambique, Namibia and Nigeria to name a few, as several IOCs are looking to begin campaigns in the second half of 2020.

In Asia Pacific, the market remains tight as rigs in the region remain contracted and opportunities for new activity continue to emerge. This bodes well for a continued strengthening in utilization, and more importantly, dayrates. In particular, Australia remains the strongest market in the region where awards continue to support dayrates solidly in the mid-to-high $200,000 per day level. If the market continues to tighten in 2020, which we believe it will, rates should move towards $300,000 per day.

Turning now to the harsh environment market, the Norwegian North Sea continues its multi-year run of strength. In 2020, a number of new programs should keep the market fully utilized for the high-specification assets. As such, we would expect dayrates to continue to move higher. In Canada, the Barents will be kicking off her next campaign with Equinor in the coming weeks. She is contracted into the third quarter with options that could keep her on contract into the fourth quarter. As the highest specification asset in country, we will understandably look to keep the Barents in Canada beyond her current contract. However, if we are unable to secure a suitable fixture following her campaign with Equinor, we will consider returning her to Norway where market conditions remain extremely favorable for the high-specification harsh environment floaters.

In summary, we remain encouraged by the outlook for 2020 and beyond, but we recognize that the pace and shape of the ultra-deepwater recovery is dependent upon many factors that are outside of our control. Therefore, we will continue to focus our time and energy on best positioning Transocean to outperform throughout the cycles. Our focus on the high-specification assets serving the harsh environment and ultra-deepwater markets has proven wise as the bifurcation in both of these segments is increasingly evident. As important, our continued internal focus on opportunities to refine and improve our processes and procedures has enabled us to further distinguish Transocean from the competition as we continue to deliver wells in a manner that consistently beats our customers’ drilling curves and provide us a competitive advantage against other contractors.

I’m very proud of the way we continue to pursue, develop and embrace new technologies that improve both the efficiency and safety of our drilling operations, while furthering our sustainability through embracing the importance of ESG for Transocean, the places we work and the world. The ability of both Transocean and the offshore service industry as a whole to sustainably reduce break-even levels for our customers is de-risking their portfolios, playing a significant role in their generation of cash flow and furthering the opportunities for through-the-cycle investing that have been so elusive.

With a longer-term macro environment that is now reflecting a significantly more stable supply backdrop than we’ve seen in years and a resilient demand forecast, notwithstanding the immediate uncertainty surrounding the coronavirus and its short-term impact, we are optimistic about both the near and longer-term prospects for Transocean.

Before turning the call over to Mark, I would just like to thank the entire Transocean team for your performance in 2019. May our focus on safety, customer service, fleet quality, operational excellence and organizational efficiency continue to serve us well in 2020. 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 fourth quarter and our full year 2019 results, then provide guidance for the first quarter and full year 2020. Lastly, I’ll provide an update on our liquidity forecast through 2021.

As reported in our detailed press release, for the fourth quarter of 2019, we reported a net loss attributable to controlling interest of $51 million or $0.08 per diluted share. After adjusting for unfavorable items associated with impairment charges related to previously-announced floater retirements, the gain on termination of certain construction contracts and certain discrete tax items, we reported an adjusted net loss of $263 million or $0.43 per diluted share. Further details are included in our press release.

Highlights for the fourth quarter include: fleet-wide revenue efficiency of 96%, the fifth consecutive quarter of revenue efficiency at or above 96%; adjusted EBITDA of $223 million, reflecting the high conversion rate by industry-leading backlog to cash and our relentless focus on costs; cash flow from operations of $147 million, driven by strong revenue performance and stellar collection efforts.

During the fourth quarter, we had adjusted contract drilling revenues by $839 million. This was approximately $14 million above our guidance due to 54 more operating days during the quarter than forecasted, and a $12 million sequential quarterly increase due largely to the contract commencements for the Deepwater Corcovado and Deepwater Mykonos, along with a full quarter of operations for the Transocean Norge.

Operating and maintenance expense for the quarter was $575 million. The expected sequential increase is largely attributable to higher level of maintenance expenditures during the fourth quarter on the in-service fleet, along with a full quarter of operations for the Transocean Norge.

General and administrative expense was $54 million for the quarter. The sequential increase was primarily a result of increased legal, professional and advisory fees.

As part of our long-term objective to optimize our balance sheet, we repurchased approximately $50 million of near-dated debt in the open market during the quarter. This will save us approximately $14 million in interest to maturity. Furthermore, in early January, we opportunistically accessed the debt capital markets by issuing $750 million of priority guaranteed senior notes due 2027. Following this transaction, we called the remaining 2023 priority guaranteed notes of $714 million. These retirements will occur today. This transaction further extends our liquidity runway, while reducing the coupon on newly issued debt by 100 basis points.

Turning to cash flow and the balance sheet, we ended the fourth quarter with total liquidity of approximately $3.1 billion, including cash and cash equivalents of $1.8 billion and $1.3 billion from our undrawn revolving credit facility.

In summary, our 2019 results reflect another strong year of financial results. We generated $979 [Phonetic] million of adjusted EBITDA, resulting in $340 million of operating cash flow. We also achieved increased adjusted contract revenues of $100 million over 2018 with a total of almost $3.3 billion for the year.

Let me now provide an update on our 2020 financial expectations. For the first quarter of 2020, we expect our adjusted contract drilling revenues to be approximately $805 million. The sequential decline reflects 103 fewer operating days in the first quarter as compared to the prior quarter, mainly related to fewer operating days in Canada. For the full year 2020, we anticipate our adjusted contract revenue to be in line with 2019 at approximately $3.3 billion.

We expect first quarter O&M expense to be approximately $570 million. The first quarter is higher than our full year average quarterly run rate due to $12 million of other service costs associated with several SPSs, $10 million related to demobilization and second [Phonetic] cost for the Henry Goodrich in Canada, $8 million due to timing of extraordinary maintenance across our active fleet mainly related to the Invictus and Inspiration, and $5 million due to the completion of contract-specific upgrades for the Mykonos. We foresee quarterly O&M expense decreasing from the first quarter guidance in Q2 and further in the third quarter. Furthermore, we anticipate full year O&M expense to be around $2.1 billion.

We expect G&A expense for the first quarter to be approximately $48 million, in line with our 2019 average. Furthermore, we anticipate full year G&A expense to be approximately $183 million.

Net interest expense for the first quarter is expected to be approximately $154 million. This forecast includes capitalized interest of approximately $11 million and interest income of $8 million. We anticipate full year net interest expense to be approximately $573 million with $57 million of capitalized interest and $26 million of interest income.

Capital expenditures, including capitalized interest, for the first quarter anticipated to be approximately $120 million. This includes approximately $84 million for our newbuild drillships under construction and $36 million of maintenance capex. The full year, we expect capex to be approximately $857 million, which includes $762 [Phonetic] million for our two newbuild drillships and $105 million for operating fleet maintenance.

Our cash taxes are expected to be approximately $15 million for the first quarter and approximately $60 million for 2020.

Turning now to our predicted liquidity at December 31, 2021. Including our revolving credit facility and considering only one of our variable levers, 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 $857 [Phonetic] million, as discussed previously, and 2021 capex of $935 million. The 2021 capex includes $770 million related to the Deepwater Titan and $165 million for maintenance capex. Please note that our capex guidance excludes any speculative rig reactivations or upgrades.

Excluding our investment in two industry-leading drillships, we would be free cash flow positive in both 2020 and 2021. As it currently stands, we expect to be free cash flow positive in 2022, at which time, we’ll begin to meaningfully deleverage the balance sheet.

This concludes my prepared comments. I’ll now turn the call back over to Brad.

Bradley Alexander — Vice President, Investor Relations

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

Questions and Answers:

Operator

[Operator Instructions] Our first question will come from Mr. James West with Evercore ISI.

James West — Evercore ISI — Analyst

Hey, good morning, guys.

Jeremy D. Thigpen — President and Chief Executive Officer

Good morning, James.

James West — Evercore ISI — Analyst

So Jeremy, as we look at the global market right now for deepwater assets, you’ve got somewhat of a short squeeze underway in the Gulf of Mexico. We are seeing both Asia and West Africa starting to show signs of a nice inflection here. What’s the next step needed in your mind to move dayrates meaningfully higher off this mid-200s level?

Jeremy D. Thigpen — President and Chief Executive Officer

I think it’s just discipline across the space. I think we’ve demonstrated the contracting discipline here over the course of the last quarter, especially moving rates meaningfully higher than when we started the year. And I think it’s just a general understanding of the industry by all those involved and the availability of those high-specification assets. And as you say, especially in the Gulf of Mexico, we are largely sold out of high-specification assets. And that’s really when you start to see dayrates move. So I think it’s just a combination of awareness and then discipline.

James West — Evercore ISI — Analyst

Okay. And then maybe a follow-up on the 20,000 PSI potential for a second rig here. What’s the timing of that potential award once we know if you or others have received the award?

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

Hi, James. This is Roddie. Just to take follow-up on that one, we are essentially looking at a couple of awards should be made within — before the middle of the year. So, we’d expect to know the destiny of that around kind of May, June time frame. But there could be some activity earlier than that. We just wait to see who goes first, but certainly encouraging to see that that will happen fairly soon.

James West — Evercore ISI — Analyst

Okay, great. Thanks guys.

Operator

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

Connor Lynagh — Morgan Stanley — Analyst

Thanks. Good morning.

Jeremy D. Thigpen — President and Chief Executive Officer

Good morning.

Connor Lynagh — Morgan Stanley — Analyst

Just following off of James’ question there, could you walk us through, if you do get a 20,000 PSI award, how would that alter the capex profile for the Atlas? Would it change at all relative to your current expectations?

Mark Mey — Executive Vice President and Chief Financial Officer

Yes, Connor, this is Mark. It would increase capex this year by approximately $60 million.

Connor Lynagh — Morgan Stanley — Analyst

Okay. But no shift in terms of 2020 versus 2021 that you could forecast today?

Mark Mey — Executive Vice President and Chief Financial Officer

No.

Connor Lynagh — Morgan Stanley — Analyst

Okay, thanks. And then, maybe just a higher level one on your marketing strategy. So it doesn’t seem like you have a whole lot of space in the calendar for most of your active rigs right now. So could you help us think through what it would take to reactivate some of your stacked floaters and how you think about sort of relative priorities within those rigs?

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

So, we’ve stated a few different times that we’re not planning to reactivate rigs on spec. We’ll do so when the contracts support that, and we’re really getting closer and closer to that point. As you had asked before, you look at day rates moving up, that’s really helpful. And we’re 20% up basically between ’18 and ’19. And what we’ve seen so far in kind of the fixtures that we released, we’re another 20% higher again. So I think you need to see us probably move into the kind of high-200s, low-300s before you would contemplate reactivation. And typically, you’re going to see mobilizations paid with that that are going to cover a lot of that debt [Phonetic].

Mark Mey — Executive Vice President and Chief Financial Officer

And let me just add that we previously guided to about $50 million per rig. This is for our seventh-gen assets. So you would expect to see a term associated with that contract at the high-2s, low-3s to be able to pay that back and generate a certain amount of cash flow for the Company.

Connor Lynagh — Morgan Stanley — Analyst

All right. Appreciate the color.

Operator

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

Gregory Lewis — BTIG — Analyst

Yes, thank you, and good morning, everybody. I just wanted to follow up on, Jeremy, some of your comments. You kind of mentioned, you have the markets tight in the Gulf of Mexico. Maybe customers are thinking about trying to maybe get — force other rigs into the Gulf of Mexico. Has that resulted in any kind of extensions or in term? In other words, are we now seeing owners or customers looking at maybe kind of pushing out duration of contracts? Or are we kind of still too early days?

Jeremy D. Thigpen — President and Chief Executive Officer

We’re definitely starting to see longer terms across the space, and it’s — to your point, it is driven by the incremental demand that we’re seeing from our customers and their desire to lock up these assets for longer periods of time. So, we are definitely seeing terms lengthen, and we saw that throughout 2019.

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

Yeah, I think I’d add to that to say that on the database that we’re looking at, when you think about just firm term [Phonetic] only, we’re looking at least 30 prospects that are a year or longer. But it has been the experience over the last couple of years that most of the options are being picked up. So we also kind of slice this a couple of different ways and say, if 50% of the options out there are picked up, then we’re looking at closer to 50 projects that would last a year or longer. So that’s pretty encouraging in terms of durations, and I think it’s also demonstrating that activity is up. And while the operators are cautious as they get into this recovery, clearly, the number of options being taken demonstrate that there’s a lot of work out there that’s still unsatisfied.

Gregory Lewis — BTIG — Analyst

Okay, great. And then just one more from me on the North Sea, realizing obviously there’s a difference between operating in the South North Sea versus kind of the Norwegian area. You guys are positioned for both. I think one of the things that people have been thinking about is strength through the winter. And just as we look out and you have a few rigs rolling off later this year with openings, should we — I mean, is it shaping up now in the North Sea that we could actually see really strong activity and rig demand through winter? Or like, are we at that point yet where customers are just kind of going to be forced to kind of work at maybe not their ideal time?

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

Yeah, I think for the high-specification assets, you’re clearly seeing that you’d expect to get year-round work for them. On some of the lower spec kind of third and fourth gen rigs, the seasonality issue is kind of slowly being addressed. So I think what you’re going to see is, if there continues to be kind of a bifurcation between those two classes of rigs and there’s excess of seasonality on the lower tier vessels, I think a lot of them are going to be stacked and I think they’ll be taken off the supply, and I think as you saw one of our competitors recently announcing that they’re going to stack a rig that they couldn’t find work for. And that’s prudent. There’s no point in paying costs if you can’t get year-round work. So I think you’ll see, between the contractors, there’s probably some supply that will get taken out that would hopefully encourage folks to drill year-round, even in the kind of Southern [Phonetic] claims as you mentioned. But certainly, the high-spec looks good, and we’ll monitor closely on the lower spec stuff. And if we need to pull a little supply out to do that, then we’d try to make that happen.

Gregory Lewis — BTIG — Analyst

Okay, perfect. Thank you very much for the time.

Operator

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

Taylor Zurcher — Tudor, Pickering, Holt & Co. — Analyst

Hey, thank you, and good morning. You talked about a growing list of opportunities on the horizon. At the same time, there’s some incremental uncertainty as it relates to the oil macro with the coronavirus. And just curious, at least year-to-date, has some of these oil macro concerns had any noticeable impact on the timing of some of these tenders you’re bidding on? In other words, things that you’re bidding on earlier this year, have they pushed at all to the right as a result of some of the oil price weakness we’ve seen?

Jeremy D. Thigpen — President and Chief Executive Officer

No, not yet, Taylor. These are long-term plan projects, and our customers typically don’t have knee-jerk reactions to what they perceive to be short-term events. Now, if this lasts longer than anticipated and continues to grow in size and scale, then certainly, it could have an impact on our customer psyche. But at this point in time, we haven’t seen anything.

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

Yeah, I think I’ll just reiterate that the deepwater planning cycle is multiple years. So as Jeremy said, stuff that we are seeing move ahead is multi-year work that has been in the pipeline for some time. So hopefully that continues and it certainly seems to do.

Taylor Zurcher — Tudor, Pickering, Holt & Co. — Analyst

Okay. I just wanted to clarify one of the earlier questions. You talked about the Gulf of Mexico with some of the operators there asking for or inquiring about the potential to move rigs from other regions into the Gulf of Mexico, given how tight it’s been. Is what you’re implying that most of these rigs, at least the interest from customers, would they be rigs that are currently working in other regions? Or is it a mix of rigs that would currently be working in other regions with some of the idle seventh-gen assets that you have, namely some of the Ocean Rig assets you acquired?

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

Yeah, I think it’s the latter. Certainly of the active fleet, as Jeremy mentioned before, most of it is booked out in 2020. And that’s — precisely what their inquiries are around is looking at taking something that’s currently stacked and reactivating it. As we mentioned before, we’re being very disciplined in that approach to make sure that there is the term and the dayrate to support the investment. But we definitely think that’s going to happen in 2020.

Taylor Zurcher — Tudor, Pickering, Holt & Co. — Analyst

Okay, great. Thanks guys.

Operator

Thank you. Our next question comes from J.B. Lowe with Citi.

J.B. Lowe — Citi — Analyst

Hey, good morning, guys.

Jeremy D. Thigpen — President and Chief Executive Officer

Good morning.

J.B. Lowe — Citi — Analyst

Just a higher level question for me to begin with. We’ve heard from the larger service players in the space, there has been some, I guess, differing views on what they think that offshore activity can do in 2020 from a growth perspective, anywhere from the mid-single digits improvement on an activity level to high-single, low-double digits. I guess I’m just wondering what you guys are kind of seeing out in the field right now and what you guys are preparing for in terms of an activity improvement in 2020?

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

Yeah, so the way that we look at it here is, as the active supply begins to get sold out, then incremental supply is only going to be there when it’s supported by the economics. So the growth might not be significant. But just as an example, the projected investment for deepwater compounded annual growth rates are almost 10% each year through ’22 [Phonetic]. So 10% investment in offshore projects is pretty significant, and we certainly see several more rigs added to the current active supply. So cautiously optimistic that we will see rig counts increase through the year and then into ’21 and ’22 as well.

J.B. Lowe — Citi — Analyst

Okay, great. And I know, Jeremy, you made a comment on exploration activity really picking up. How does that affect you guys’ business? Is it more rig intensive on the exploration activity picks up? Just kind of how you guys think about that?

Jeremy D. Thigpen — President and Chief Executive Officer

No, it’s not more intensive necessarily. It’s just more demand, so more opportunities for us to put assets to work, and so it’s good to see that we’re seeing investment from our customers in exploration now, in addition to the development work.

J.B. Lowe — Citi — Analyst

Okay, great. And then, last one for me, just the obligatory M&A question. What are you guys seeing out there? Do you think more consolidation is needed? And if you could describe what your — the one-time SG&A costs were in the fourth quarter, that would be great. Thanks.

Jeremy D. Thigpen — President and Chief Executive Officer

Sneaked in a couple there. So in terms of the M&A landscape, we’ve been pretty consistent in our approach. We are only interested in the high-specification and harsh environment and ultra-deep floaters, and we are not interested in pursuing any kind of transaction that would negatively impact our liquidity. That doesn’t leave a whole lot options out there for us. And so, I think from our position right now, we’re happy with the work that we’ve done with the fleet, the acquisitions that we’ve made over the course of last couple of years and some of the rigs that we’ve retired. We feel like we’ve got the fleet that we want and need now. As market conditions change, obviously, we are always a stalking-horse, if nothing else, and we will see every opportunity that’s out there. But at this point in time, just nothing that fits our scope.

And Mark, the question on G&A?

Mark Mey — Executive Vice President and Chief Financial Officer

Yeah, J.B., I think I’ve given you the response that it’s legal, professional and advisory fees. I’m not sure there’s much more to add beyond that.

J.B. Lowe — Citi — Analyst

All right, great. Thank you.

Operator

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

Mike Sabella — Bank of America Merrill Lynch — Analyst

Hey, good morning all. So, Jeremy, really appreciate the rundown of all the new technologies on the rig. And so, when we kind of consider about getting paid for the technology offering, have you started to see any benefit from that? Or is that still kind of yet to come?

Jeremy D. Thigpen — President and Chief Executive Officer

It’s still too early on all of these technologies, quite frankly. We just deployed kind of the first addition of ADC and the hybrid power, and so we really don’t have all the data that we need for that. On the ADC that we are implementing on — across six assets with Equinor, we have seen real value from that. In fact, the customer will be paying us for the performance improvements that we will see by that technology. So we are encouraged about that. And it has been in the field on one of our rigs for well over a year now. And so, we have seen performance improvement there. But the other technologies are still too early.

Mike Sabella — Bank of America Merrill Lynch — Analyst

Is there an impact on cost? Or is it just getting paid for increased efficiencies?

Jeremy D. Thigpen — President and Chief Executive Officer

No, so there’s a bit of a mix actually. So certainly an impact on cost to the extent that we can deliver these wells in a more timely fashion. And so, that we’re certainly seeing with ADC. Some of the other technologies are really more around safe working environment. And so, to get the customer to pay for that either through incremental market share and/or increased dayrate, premium dayrate is really the objective.

Mike Sabella — Bank of America Merrill Lynch — Analyst

Perfect. And then, in the past, you guys have talked about the buy — potential buyout on the remaining interest in Norge. Can you just walk us through kind of current thought process around that, options and maybe potential timing?

Mark Mey — Executive Vice President and Chief Financial Officer

Yeah, so this is Mark. I don’t think we have progressed that any further at this stage. Clearly, we have backlog on that rig that runs through next year. I would assume that a buyout would be associated with a longer-term contract award. So, that would probably be a leading indicator to see us look at it taking full control that rig.

Mike Sabella — Bank of America Merrill Lynch — Analyst

Thanks guys.

Operator

Thank you. Our next question comes from David Smith with Heikkinen Energy Advisors.

David Smith — Heikkinen Energy Advisors. — Analyst

Hey, good morning, and thank you. So the high-spec seventh-gen drillships clearly bring value in the US Gulf, and a pretty solid dayrate momentum you’ve demonstrated there. As the rate momentum in the Gulf kind of continues, curious on how you think about that fleet outside of the Gulf in terms of whether you’re starting to or expect to see pricing competition between the higher-spec seventh-gen fleet versus the slightly older sixth-gen fleet and kind of how you think about that natural pricing dynamic?

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

Yes, first, about the market, so really we think about the Golden Triangle. So yes, the US Gulf of Mexico is looking really good. But I want to mention Mexico itself. There’s just discontinued operations in Mexico. We’ve seen multiple discoveries or certainly very positive well results. So if you look at 18 operators in Mexico in various different partnerships, so that part of the market, in addition to the US, is going to be really strong going forward. And don’t forget that’s still in kind of that first, second phase of the exploration, so there’s plenty of development potential on top of that.

And then, the other two legs of the Golden Triangle, we often talk about Brazil and West Africa. In West Africa, where there’s obviously individual challenges in different countries with different governments, the number of overall rigs looks like is moving up. There’s a couple of swing states and there could be pretty big — Nigeria, for example, if they can sort out the PSC discussions they’re having with the operators, then there is potential to consume several more rigs.

And kind of the final piece is Brazil. So we just continually see Petrobras coming out for tenders one, two, three rigs at a time, so very encouraging there. And as we kind of indicated over the past year or so, we see Petrobras replacing their current rig count with renewals, and then the IOCs are really the swing that’s pushing those numbers up. So you’ve got about 20 — just 20, 22 rigs working just now. We would expect that that’s going to get up into the 30s in ’21. So we’re really optimistic that Brazil could swing a big shift in demand for the ultra-deepwater ships that’s already improving. And of course, when you see that, then you’re going to see a lot of pricing increase. I think at the very beginning, you may see the first one or two that pick up these jobs might not get significant premium. But I think if you’re patient, then you’ll not only get your mobilizations paid for, but you should be able to command some pretty solid dayrates.

David Smith — Heikkinen Energy Advisors. — Analyst

All right. Thank you.

Operator

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

Kurt Hallead — RBC Capital Markets — Analyst

Hey, good morning.

Jeremy D. Thigpen — President and Chief Executive Officer

Good morning, Kurt.

Kurt Hallead — RBC Capital Markets — Analyst

I want to follow up on one of Mark’s comments. You referenced, I believe, that you’d be free cash flow positive in 2020, 2021 and 2022. I just wanted to kind of — is that free cash flow positive, is that after the capex numbers that you provided, Mark?

Mark Mey — Executive Vice President and Chief Financial Officer

No. I’ve actually differentiated between 2020 and 2021 saying that we would be if we did not have the two 20k rigs getting delivered in this year and later next year. So if you cancel capex, we are free cash flow positive in 2022 for the first time.

Kurt Hallead — RBC Capital Markets — Analyst

Okay, great. I appreciate that clarification. Then, Jeremy, in the past, you guys have provided some information about your rig rating system and what could be potentially in line to come back under the right circumstances. So when you kind of have refreshed that dynamic and you look at the prospects for maybe high $200,000 [Phonetic] or low $300,000 dayrate, what could be feasible in your mind in terms of number of rigs that could be activated over the course of the next, let’s say, 18 to 24 months?

Jeremy D. Thigpen — President and Chief Executive Officer

Within our own fleet, you’re asking?

Kurt Hallead — RBC Capital Markets — Analyst

Yeah, just within your own fleet, yes.

Jeremy D. Thigpen — President and Chief Executive Officer

Yeah, I think it wouldn’t be unrealistic to see a handful of those rigs get reactivated. And as Mark said earlier, we would target those that we acquired through the Ocean Rig transaction that are currently stacked in Greece. And so, that would be our first priority.

Kurt Hallead — RBC Capital Markets — Analyst

Okay, great. All right. That’s it from me. Thank you.

Operator

Thank you. Our final question comes from Chris Snyder with Deutsche Bank.

Chris Snyder — Deutsche Bank — Analyst

Hey, thanks for the time, guys. So just following up on the questions around the Atlas and the 20k PSI opportunities, you guys owe a sizable chunk, I think maybe in the ballpark of $600 million, to take delivery of this rig. So maybe in that context, what kind of rate would you guys need to go forward with delivery? Should we assume it at least in the mid-400s, which is where the Titan came in at?

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

I think we’re in kind of open tenders at the moment, so we’d rather not tip our hands. But you’ve seen where rates have been previously for 20k work. And we have described many times an improving market. So, put those two pieces of information together and see what you get.

Chris Snyder — Deutsche Bank — Analyst

Okay, fair enough. Then just for the follow-up question, you guys reactivated two of the Ocean Rig drillships last quarter. I believe they were stacked for like around 18 months. Can you maybe just provide a little more color on this process, any surprises along the way? And how, if at all, it changes, how you view additional reactivations across the fleet?

Jeremy D. Thigpen — President and Chief Executive Officer

Well, so if you’ll remember, they were — Ocean Rig was actively bidding those two into the Petrobras contract as we were going through the transaction. So we had very little visibility to the customer specification and some of the upgrades that Petrobras was requesting in those. So I think that piece of it was a bit of a surprise to us, the additional upgrades that Petrobras wanted as part of this campaign with these two rigs. Other than that, it was fairly straightforward.

Chris Snyder — Deutsche Bank — Analyst

All right, thanks for the time, guys.

Operator

Thank you. I’d now like to turn it back to Mr. Alexander for closing comments.

Bradley Alexander — Vice President, Investor Relations

Thank you, David, and thank you, everyone, for your participation on today’s call. If you have any further questions, please feel free to contact me directly. We look forward to talking with you again when we report our first quarter 2020 results. Have a good day.

Operator

[Operator Closing Remarks]