Transocean Ltd (RIG) 2018 Q4 法說會逐字稿

Good day, and welcome to the Quarter Four 2018 Transocean Earnings Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Bradley Alexander. Please go ahead, sir.

Thank you, Molly. Good morning, and welcome to Transocean's Fourth Quarter 2018 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. Please also 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. (Operator Instructions)

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

Thank you, Brad, and welcome to everyone participating in Transocean's Fourth Quarter and Full Year 2018 Earnings Call.

I'd like to start today's call with a recap of 2018. As reported in yesterday's earnings release, for 2018, the company generated adjusted normalized EBITDA of $1.1 billion on $3 billion in adjusted normalized revenue, resulting in an industry-best adjusted normalized EBITDA margin of 36%. As you well know, for the past 3-plus years, Transocean has been 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 and extending our liquidity runway by adding to our industry-leading backlog, converting a higher percentage of that backlog to cash and prudently bolstering our balance sheet through timely transactions.

In 2018, we took several steps to further each of these objectives. Looking first at our fleet, we added 20 assets with an associated $4.5 billion of backlog through 2 corporate acquisitions and added another high-specification harsh environment floater through the formation of a strategic joint venture.

In January, we closed Songa Offshore, the first of our 2 corporate acquisitions. Through this transaction, we acquired 7 rigs, including 4 high-specification harsh environment semisubmersibles on long-term contracts with Equinor. These assets were backed by almost $4 billion of high-margin contracts extending into 2024. This acquisition was strategically important to us as it enhanced our harsh environment fleet, added scale in the strengthening market of Norway, increased our exposure to a target customer and through its significant backlog, provided visibility to strong future cash flows, which as you know, is critical in the current market.

Our second acquisition was Ocean Rig, which we just closed in December. With this acquisition, we added 13 rigs to our fleet and almost $750 million of backlog. The Ocean Rig fleet consisted of 11 high-specification ultra-deepwater ships that are less than 8 years old, including 2 of the most technically capable rigs in the industry, which are still under construction. This transaction was strategically important to us as we acquired more of the high-specification ultra-deepwater assets that our customers prefer, providing us the opportunity to capitalize on what we believe to be the beginning of a market recovery in the ultra-deepwater space. In between these 2 corporate transactions, we formed a joint venture to acquire the high-specification harsh environment semisubmersible, the Transocean Norge. As all of our top tier harsh environment assets were already contracted, the investment in the Norge provided us with the opportunity to further increase our exposure to the continued recovery in the Norwegian market.

We just recently took deliveries of the Norge and are in the process of mobilizing her to Norway, where she will commence operations on our maiden contract working for Equinor. We currently expect the Norge to go on contract in July, at which point Transocean will have 8 active rigs operating in the Norwegian waters.

Also in furtherance to our fleet strategy, we announced the retirement of 8 older, less marketable assets in 2018 and just recently announced our intention to retire the Ocean Rig Paros; and as of yesterday, we have decided to also retire the Ocean Rig Eirik Raude. During our initial due diligence of Ocean Rig, we inspected their asset and assumed that the reactivation costs associated with the Paros and the Raude would be prohibitive.

As such, we ascribed virtually no value to them in our purchase price. Now after spending a bit more time assessing each rig, we believe that the reactivation cost for the Paros could approach $250 million, with the Eirik Raude likely to exceed $100 million. As such, we will now move forward with recycling these assets in an environmentally responsible manner. The removal of these 2 rigs from our fleet will bring our total number of recycled assets since the start of the downturn to 49. Through the continued execution of our strategy to assemble the most capable fleet of assets, we now have 53 rigs, with an estimated backlog of $12.2 billion. 49 of these rigs or approximately 92% are considered high-specification ultra-deepwater and/or harsh environment assets.

The type of floating rigs with the strongest long-term demand characteristics and is therefore, the greatest opportunity for dayrate escalation.

Moving from fleet quality to operational excellence, I'm pleased to report that in 2018, despite 2 extended downtime events to start the year and the 1 extended weather-related downtime event to end the year, we managed to deliver another year of strong uptime performance across our global fleet, with uptime greater than 96% and revenue efficiency exceeding 95% for the fifth consecutive year. While our ultimate goal is to deliver 100% uptime for our customers, given the headwinds we faced in 2018, which I will now outline, I'm pleased with the result.

In 2018, we welcomed a newbuild, the Deepwater Poseidon into our fleet and commenced operations in the Gulf of Mexico. We also reactivated 3 rigs, mobilized 5 rigs to new jurisdictions and/or new customers and added almost 4,000 new employees, primarily through our strategic corporate acquisitions or to support new operations in new markets. So delivering 90% uptime for the year was quite an accomplishment. More importantly, we delivered this uptime performance while keeping our people safe, navigating the entire calendar year without a lost time incident. I'd like to take this opportunity to thank the entire Transocean team for its unwavering commitment to delivering exceptional uptime performance for our customers while striving to maintain an incident-free environment all the time and everywhere.

Part of our uptime success in 2018 can be attributed to our OEM health care contracts, which cover the most critical components on our rigs. These agreements support our goals of reducing operating costs and more importantly, continuing to improve equipment reliability and safety.

As we move into 2019, we will continue to explore opportunities to leverage our OEM relationships as well as our proprietary data analytics tools to better evaluate the real time health of our equipment. Due to the improved visibility we are now afforded, we can quickly detect degradation of components or systems, such that we identify potential failures in a more timely manner and proactively schedule maintenance to avoid unplanned downtime events.

In addition to improving equipment reliability and uptime in 2019, we intend to expand our capabilities to deliver even greater drilling efficiency for our customers. As many of you know, we are now 2 years into the launch of our proprietary efficiency dashboard. As a result of this dashboard and the improvements that we have made to it over the past 24 months, we have increased the efficiency and consistency of our operations across crews and rigs, meaningfully reducing the time required for our customers to construct their wells. In fact, the tool has proved so successful that one of our IOC customers has opted to discontinue its long-standing relationship with a third-party providing commercial rig performance monitoring services in favor of supplementing their own internal performance monitoring tools with our efficiency dashboard, and we are in conversations with other customers who are seriously considering a similar transition.

Needless to say, we do this as a true testament to the value of the tool, our customers' confidence in its accuracy and capabilities and their trust in Transocean. In addition to focusing on process improvements utilizing the efficiency dashboard, we are also beginning to leverage digital twin technology to perform rig floor machine analytics to help us bridge the gap between actual and optimal machine performance across our rig fleet. Through this process, we will continue to reduce the time required to construct a well while driving further consistency of performance across our global fleet.

And finally, we recently announced that we have entered into an agreement with Equinor to install automated drilling control systems on 5 additional high-specification harsh environment semisubmersibles currently on contract in Norway. Since 2017, we have operated the ADC system on the Transocean Enabler, and the improvements that we have realized in drilling efficiency, well quality, well integrity and safety have been material.

As such, we will soon be deploying the ADC system on the Spitsbergen, the Encourage, the Equinox, the Enabler and the Norge as we continue our quest to deliver safer, higher-quality and lower-cost wells to our customers.

Through the ongoing enhancement of our fleet and continuous improvements in safety, reliability and drilling efficiency, we believe that we will further advance our position as our customers' universal first choice. As evidence that our strategy is working, despite the challenging market conditions in 2018, Transocean won 37 new floater contract awards, far more than any of our competitors. This represents a 44% increase year-over-year. Furthermore, these awards contributed over $1.8 billion to our industry-leading backlog. This is more than twice the backlog we added in 2017 and our largest total since 2014. Of particular significance is the 5-year, $830 million contract we signed with Chevron in late December to construct, deliver and operate the industry's first ultra-deepwater 20,000-psi drillship. The drillship incorporates state-of-the-art technology, including 20,000-psi blowout preventers, a derrick with gross hoisting capacity of 3.4 million pounds, a variable debt load capacity of 24,000 metric tons and an enhanced dynamic positioning system.

Additionally, during 2018, we were pleased to sign master service agreements with Equinor, ExxonMobil and ConocoPhillips. And unsurprisingly, all quickly led to contracts that further contributed to our backlog. After signing the MSA with Equinor, we exercised multiple options for the Transocean Spitsbergen and secured the maiden contract for the Transocean Norge. In the case of ExxonMobil, we reactivated the semisubmersible Development Driller III, which is currently on its way to Equatorial Guinea to begin its campaign. And I'm pleased to report that just yesterday, ExxonMobil exercised its first 6-month option on this contract. And assuming they exercise their remaining 2 options, this rig would remain on contract for the next 2 years with escalating dayrates that would generate significant cash flow.

Finally, after signing the MSA with ConocoPhillips, we've booked some relatively long-term work for the Transocean 712 in the U.K.

Focusing specifically on the fourth quarter, in addition to the 5-year contract for the 20,000-psi drillship with Chevron, we added fixtures for the KG2 in Australia, where Chevron required a second rig for their Gorgon Stage 2 campaign. We also earned an extension on the Discoverer India with CNR in the Ivory Coast, picked up a contract with BP in UK for the Paul B. Lloyd, added 2 short-term fixtures for the Arctic in Norway and secured options for the Leiv Eiriksson in Norway and the 712 in the UK. And just recently, we secured a new 120-day contract for the Transocean Leader with Premier in the UK, with an estimated $30 million in backlog. And we're awarded additional options on the Leiv Eiriksson in Norway with Lundin and the Ocean Rig Poseidon in Angola with Eni.

Looking now to the macro oil market, the end of year decline in oil prices certainly dampened the enthusiasm that we built throughout the first 3 quarters of 2018. However, it's important to remember that much of what drove that enthusiasm around the long-awaited market correction remains unchanged. Breakeven economics for our customers' offshore projects are now consistently below $50 per barrel, with the most eminent project at or below $40 per barrel. Due to a lack of investment over the past 4 years, reserve replacement ratios continue to decline. And our customers have generated significant cash flows from operations, which they can use to service debt, return capital to shareholders and if they so choose, invest in longer-cycle projects, including long-delayed greenfield projects, which help to drive incremental demand.

Per respected independent industry group, in 2019, as many as 90 offshore project FIDs could materialize. This would represent a significant increase from the 51 FIDs that were sanctioned in 2018 and further supports our contention that the offshore market is in the early stages of a recovery.

Across the global market and across our broad customer base, we continue to see multiple opportunities in the ultra-deepwater market. In the U.S. Gulf of Mexico, we are excited about the greenlighting of the 20,000-psi work for Chevron. This contract represents the culmination of multiple years of planning and dedication by both Transocean and Chevron and is a project that they see as vital to their longer-term production. This, however, may be just the beginning for high-pressure ultra-deepwater production. There are additional opportunities requiring 20,000-psi rated equipment in the lower tertiary area of the U.S. Gulf of Mexico. Therefore, we would not be surprised to see incremental demand for this game-changing technology in the months and years to come.

Additionally, for the first time in years, we are engaged in conversations with multiple customers around upcoming projects in the U.S. Gulf of Mexico that would actually require incremental rigs returning to work in this critically important market.

In Mexico, we're proud to have drilled the first ultra-deepwater well for an international operator, BHP in the Trion field with the Deepwater Invictus. And we have recently mobilized our second ultra-deepwater drillship, the Deepwater Asgard, into the region for Murphy. Additionally, it's likely that we will move 1/3 of our drillships into this previously untapped portion of the Gulf of Mexico to begin drilling for a super major before the year ends. In Brazil, we're pleased to see Petrobras tendering multiple projects with start dates beginning as early as the second half of 2019. We are hopeful to win some of this work and have multiple rigs drilling for Petrobras by year-end.

We are also encouraged to see incremental demand in the region being driven by the international players, which are starting to move forward with their programs.

Moving to West Africa, as evidenced by the extension on the India in the Ivory Coast, the new contract for the DD3 in Equatorial Guinea and the conversations that we continue to have with customers in the area, it is clear to us that demand is picking up and larger-scale opportunities are emerging. While projects in West Africa are always more sensitive to oil prices, the continued reduction in ultra-deepwater project cost has enhanced the viability of projects here as well.

In the Asia-Pacific region, we now have both our KG1 and KG2 drillships operating, along with 2 of our semisubmersibles, the DD1 and the Nautilus, and we continue to be encouraged by opportunities in India, Malaysia and Australia.

Importantly, as it relates to the ultra-deepwater market, we are starting to arrest and reverse some of the trends that emerged during the downturn. Specifically, we are experiencing a shift from tendering to direct negotiations, which we view as a positive sign. In select circumstances, we are now asking for and receiving mobilization fees. With certain customers and programs, we are successfully negotiating downtime banks, which all but disappeared over the past 4 years. We are actively engaged in conversations with customers about paying for reactivations, special periodic surveys and upgrades, and perhaps, most importantly, we are starting to lift dayrates in ultra-deepwater markets. The combination of all of these factors suggest that we could be progressing to a more sustainable business environment.

Moving from the deepwater to the harsh environment markets of Canada, Norway and the U.K. The market for high-specification assets in both Canada and Norway continues to be tight. In fact, with virtually no remaining marketable supply in these 2 regions, we could see base dayrates, which have been temporarily capped around $300,000 per day before bonuses, move higher as we progress through the year and into 2020.

And in the UK, as evidenced by the signing of the Transocean Leader, the market for highly efficient semisubmersibles remains constructive. As we perceive through 2019, we believe that the attractive project economics in these basins, coupled with the demonstrated ability of operators in these regions to compress their time to first oil, should result in solid demand and activity for the foreseeable future. So overall, we remain encouraged by the outlook for 2019 and beyond.

While there is no doubt that the decline in oil prices at the end of 2018 was disheartening, it's important to focus on the following: Offshore project costs and returns are competitive with shale. As an industry, we have materially compressed the time to first oil for offshore projects. Our customers have generated record cash flows and can now comfortably service debt, return cash to shareholders and invest in longer-cycle projects, and reserve replacement is a real challenge. We are currently replacing just 1 of every 2 barrels currently produced offshore, and that number decreases to 1 of 3 barrels when averaging production over the last 3 years. With estimates for annual worldwide oil demand growth generally ranging between 1 million and 1.5 million barrels per day, the current level of offshore activity must increase materially to keep pace. In conclusion, today's outlook is not without its near-term challenges, but we have prudently positioned Transocean to outperform throughout the cycles.

As we move through 2019, we will continue to execute the strategic plan that we established almost 4 years ago, which includes: enhancing our fleet through additions, subtraction and upgrades; identifying and realizing opportunities to improve operational efficiency, including safety, uptime and the streamlined delivery of our customers' wells; identifying and realize opportunities to improve organizational efficiency through continuous improvements in our operations and our processes; and taking the necessary actions to further bolster our balance sheet so that we can continue to invest in differentiation, including our assets, new technology and our people.

Before turning the call over to Mark, I would just like to thank the entire Transocean team for your performance in 2018. May our focus on safety, customer service, fleet quality, operational excellence and organizational efficiency continue to serve us well in 2019. Mark?

Thank you, Jeremy. Good day to all. During today's call, I will briefly recap our fourth quarter and full year results and then provide guidance regarding the first quarter as well as the full year 2019, which includes the Ocean Rig acquisition for the first time. Lastly, I'll provide an update on our liquidity forecast through 2020.

As reported in our detailed press release, for the fourth quarter 2018, we reported a net loss attributable to controlling interest of $242 million or $0.48 per diluted share. After adjusting for unfavorable items, primarily associated with discrete tax items and impairment charges related to the previously announced floater retirements, we reported adjusted net loss of $171 million or $0.34 per diluted share. Further details are included in our press release. Contract rig revenues decreased $68 million sequentially to $748 million, due largely to fewer operating days as well as unexpected rig-related downtime on 2 of our harsh environment rigs off the coast of Canada, resulting in approximately $21 million in lost revenue.

In addition, the quarter was also unfavorably impacted by the completion of the recognition of the Clear Leader early termination revenue in October, resulting in a $24 million decrease; and an unfavorable $21 million impact from the plan-and-extend contract extension on the Petrobras 10000. This was partially offset by the increase in revenue of approximately $15 million from the 3 working rigs acquired in the Ocean Rig transaction and better revenue efficiency from the previous quarter.

In addition to the successful acquisition of Ocean Rig, highlights for the fourth quarter include fleet-wide revenue efficiency of 95.7%, an adjusted normalized EBITDA margin of 34% that continues to lead the industry and showcase the strength of both our industry-leading backlog and operational performance and cash flow from operations of $238 million.

For the fourth quarter 2018, we had operating and maintenance expense of $497 million. That includes $15 million on the Ocean Rig fleet as well as higher-than-anticipated shipyard cost and fleet maintenance costs. The shipyard costs are mainly due to the DD3 project incurring certain expenditures forecast for the first quarter 2019 in 2018. Fleet maintenance costs include the payment of uptime bonus related to no unplanned BOP pause in 2018, associated with one of our OEM health care agreements.

Speaking of reactivation, let me briefly recap our reactivation history. We have been disciplined in our reactivation strategy, ensuring that all our investments are either repaid within the initial contract or shortly thereafter.

For example, the Henry Goodrich and the Transocean Barents investments will repay within 18 months. For the DD3, we expect to recover approximately 75% of its reactivation costs by the end of its third option or 2 years after initial contract commencement.

Turning to the cash flow and balance sheet. The effective tax benefit for the fourth quarter was a negative [82.6%] compared to an effective tax rate of 6.7% for the prior quarter. To that effect, cash taxes paid for the fourth quarter 2018 and full year 2018 were $19 million and $119 million, respectively. We ended the fourth quarter with a total liquidity of approximately $3.2 billion, including cash and cash equivalents of $2.2 billion and $1 billion of undrawn revolving credit -- from our revolving credit facility.

Earlier this month, we completed successful cash tender offer, in which we repurchased a total of $509 million of debt maturing between 2020 and 2023. After this cash tender offer, we accessed the debt capital markets by issuing $550 million of senior notes securable at Deepwater Poseidon with a 2027 maturity.

Looking at our 2018 results, we delivered another year of strong financial results under challenging market conditions, all directly attributable to Transocean's continued commitment to operational excellence and revenue efficiency. We will continue to be disciplined in our approach to extending our liquidity runway by both enhancing our cash position and/or addressing our near- and midterm debt maturities. Let me now provide an update on our 2019 financial expectations. For the first quarter of 2019, assuming revenue efficiency of 95% on our active fleet, we expect total contract drilling revenues to be down approximately 5% quarter-over-quarter. This forecast includes the impact of scrapping the Jack Bates and the Transocean 706, both of which completed contracts in the fourth quarter; and the absence of amortization of the early termination revenue associated with the Discoverer Clear leader.

Our revenue forecast includes approximately $45 million of quarterly noncash contract intangible amortization, which will reduce our revenue each quarter in 2019 as a result of the above-market value backlog acquired in the Songa and Ocean Rig transactions.

Additionally, we will also recognize a quarterly noncash step dayrate adjustment of approximately $12 million related to the average difference in dayrates of the current [Skeros] contract with Total in Angola, and its follow-on options which start in October 2021.

We expect first quarter O&M expense to be approximately $517 million. This includes reimbursable expenses of approximately $23 million. This sequential increase in O&M expense is due to a full quarter of Ocean Rig as well as 2 shipyard projects.

During the first quarter, we performed the Chevron contract preparation for the DD1 and a routine 35-year SPS for the Sedco 712, which we expect will result in a total of 30 days out-of-service time.

We expect G&A expense for the first quarter to be approximately $47 million. The sequential decrease primarily relates to the reduction of Ocean Rig onetime acquisition costs from the first -- from the fourth quarter. Net interest expense for the first quarter is expected to be approximately $155 million. This forecast includes capitalized interest of approximately $9 million and interest income of approximately $8 million. Capital expenditures including capitalized interest for the first quarter are anticipated to be approximately $84 million. This includes approximately $34 million for the 4 newbuild drillships under construction, which consists of approximately $31 million for the 2 Jurong drillships, including preparation for the Chevron 20,000-psi contract and approximately $3 million for the Ocean Rig Santorini and Ocean Rig Crete.

The financing arrangements for these 2 assets are set, but our final payment are not due until 2023 and 2024, respectively. Our cash taxes are expected to be approximately $23 million for the first quarter and approximately $90 million for 2019.

Looking now at full year 2019. Full year 2019 contract drilling revenue is expected to be approximately $3 billion.

Operating and maintenance costs for 2019 are expected to be between $1.8 billion and $2 billion, assuming no speculative rig reactivations.

We expect G&A expense in 2019 to range between $185 million and $195 million. Our depreciation expense is estimated to be approximately $880 million and net interest expense to be approximately $620 million. This includes capitalized interest of approximately $44 million and interest income of $28 million. Capital expenditures in 2019 are anticipated to be approximately $440 million. This includes approximately $280 million in [newbuild] CapEx, including $168 million for the 2 Jurong drillships, mostly associated with the Chevron contract mentioned above and delivery preparation of $112 million for the Ocean Rig Santorini and Ocean Rig Crete.

Maintenance CapEx should approximate $160 million and includes $70 million for the build-out of our new office building and several innovation, technology and IT projects. In addition, we anticipate spending approximately $50 million to replenish our major spares inventory and for the 7 SPSs, which we discussed in detail on our third quarter earnings call.

As we indicated in our third quarter call, we are providing additional guidance regarding the current treatment for our investment in the Transocean Norge, the high-specification harsh environments semisubmersible, in which we would own a 33% joint venture interest.

We have made a $50 million shipyard installment payment in the first quarter of 2019 plus $9 million for contract preparation, with a final installment of approximately $33 million to be made in the first quarter 2020.

Transocean will operate the Norge, and therefore, its current backlog of $85 million and future contract backlog will be fully reflected in our overall backlog. The Norge is scheduled to commence operations in July, and we anticipate quarterly revenue of approximately $25 million, assuming 95% revenue efficiency related to its maiden contract with Equinor. As contract operator, Transocean will generate approximately $1 million of quarterly operating income in addition to other income reflecting our 33% investment in the company that owns the rig.

Turning now to predicted liquidity at December 31, 2020. Including our $1.1 billion revolving credit facility, which matures in June 2023, our end of year 2020 liquidity is estimated to be between $900 million and $1.1 billion. This liquidity forecast includes customer CapEx of $440 million, discussed above, for 2019 and 2020 CapEx of $1.3 billion. The 2020 CapEx includes $1.1 billion related to the 2 newbuild drillships at Jurong, $86 million for the 2 former Ocean Rig newbuilds at Samsung and maintenance CapEx of $115 million. Please note that our CapEx guidance excludes any speculative rig reactivations. Despite our enough liquidity, we continue to carefully monitor the market recovery. As you are aware, we continue to have multiple levers available to further bolster our balance sheet. These include, but are not limited to, unencumbered assets with long-term contracts and substantial capacity to issue additional priority guaranteed notes. This concludes my prepared comments. I will now turn the call over to Brad.

Thanks, Mark. Molly, we're now ready to take questions. (Operator Instructions)

(Operator Instructions) We will take our first question from Ian MacPherson of Simmons.

Mark, when you guided full year revenues to $3 billion, do you have -- could you give us what that figure is on your adjusted normalized basis that strips out the noncash and amortization effect?

Yes, so for 2019, we have $178 million of intangible amortization and $63 million of the step dayrate adjustment, which I discussed previously.

Got it. I also wanted to ask about the automated drilling technology upgrades on the Norway rigs. If you could maybe expand a little bit about how -- what -- percentage-wise, what the efficiency gains have been on the Transocean Enabler that have been measured over the past couple of years. And also if you could talk a little more about any economic impacts to you as you apply these technology upgrades to the 5 additional rigs going forward in terms of is there a dayrate adjustment, is there a CapEx consideration, et cetera?

This is Roddie here. So yes, really pleased to the announce that. And to answer your questions, basically, the stuff that Jeremy talked about before, our dashboards and those kind of things, those all work on what we call the flat-spot parts of the well curve that essentially shorten the nondrilling time. The ADC system is all about optimizing the actual drilling time. So we achieve higher rates penetration, and essentially, that's done through measurement of the -- or highly accurate measurement and application of the drilling systems. So things like rpm, weight on bit, circulating pressures, those kind of things. So the long and short of it is, the investment that we made in this was basically a partial capital investment on equipment across the rigs, and what we get in return is a pretty significant bonus opportunity. So the -- you asked the question about what improvements we expect to see. Well, we have seen up to 25% to 30% increased rate penetrations on certain drilling sections. And the overall expectation on the impact to the entire well curve is somewhere between 5% to 10%, could go up to perhaps 15%.

Now if we realize the base case, then our return on the capital investment will be approximately four or fivefold over a 5-year period, and if we see the real upside or the potential of the technology fulfilled, that could be almost tenfold over that 5-year period. So it's a very interesting technology. It's pretty solid economic model from our point of view. But our customer saves a tremendous amount of time and thereby, expense. So again, it's just one of the steps that we wanted to take in partnership with Equinor to make sure that we are driving the cost of offshore drilling down and making it as competitive as possible.

Very interesting. So in effect, you are getting an incremental bonus revenue opportunity associated with these upgrades?

Absolutely. And it's on contracts that are on long-term signed deals with fixed dayrates. So this is actually a way of making incremental revenue.

And is the technology expandable beyond this customer? Or is there an IP exclusivity that confines it to Equinor?

No. Absolutely expandable. And in fact, we would expect to see that implemented elsewhere around the world.

Our next question comes from James West of Evercore ISI.

Jeremy, lots of good details on the deepwater market and how things are changing there. Curious to know though as you talk to customers, as you guys are negotiating these contracts, which are obviously, you're talking more about low cost, et cetera, is there a sense of urgency building within the customer base about securing rigs for late this year, 2020.

Yes, I think I'll take that one. Basically, what we see is for the higher-specification rigs, that's absolutely the case. So when we think about harsh environment, well, it's very obvious. We're essentially sold out of high-spec rigs, and there's -- the kind of next tier down is now being put to work at extremely healthy dayrates with big bonuses. You asked specifically about ultra-deepwater. So for high hook load assets, we are seeing a very similar things. So obviously, evidenced by the Chevron contract having the very high specification is extremely useful for a long-term view. But we have a couple of very high-specified current state-of-the-art rigs that we expect to continue work through 2019 and then into 2020. So we see that market tightening, and actually, the number of high hook load rigs available in 2020 should be very small indeed. In fact, that may actually encourage some commitments on the other Jurong rig we have that is one of the ultrahigh hook load rigs.

Okay. That's great color, Roddie. And then on these assets, as dayrates do move up here, which -- it's pretty clear that they're going to. Are you -- with the new dayrates and the big bonuses, will you now get to at least cost of capital or maybe even above return on the assets?

Yes, I think when we look at the Chevron fixture as an example, that basically gets us there. It gets us to returning the cost of capital on the entire asset plus the upgrades and what have you. But in the rest of the market where we have more of the lower-spec ultra-deepwater ships, we're not quite there yet, but we're moving in that direction. And in fact, we kind of saw a lot of kind of cash breakeven fixtures last year. But now we're already posting a couple of fixtures and extensions that are beginning to return healthier margins. So we're really encouraged by seeing those commitments.

Our next question comes from Kurt Hallead of RBC.

So Jeremy, I just wanted to follow up on -- you mentioned there could be as many as 91 offshore projects being sanctioned this year versus say the 50 or so last year. I'm just curious when you map that out to potential incremental rig demand, how many rigs does that -- you think that equates to? How many ultra-deepwater rigs does that equate to?

So I don't know that we've gone to that extent. We have put together what we think could -- rig count could look like by the end of the year. And if you factor in all the rigs that have rolled off contract this year and all the new opportunities that we think are available out there, we could see an exit rate for 2019 between 5% and 10% higher than where we exited 2018.

Great, appreciate that. And the other commentary that I think Roddie just talked about, of having contract expansions for some of these ultra-deepwater ships that previously have been running about cash breakeven. What I'm really trying to get a feel for here is as you look out at potential contracting opportunities, whether they'd be late '20 or into 2021, it appears to me that the ultra-deepwater rate structure, the discussion should start somewhere between $250,000 and something over $400,000 a day. Can you just kind of dial me back if needed? Or how do you see things evolving with respect to contracts for that '20, '21 time period?

So we have -- I wouldn't dial you back, and what I'd say is that we have 2 proxies out there, if you will. So if you look at the harsh environment market, we saw over a 9-month period, dayrates move from about $150,000 a day to $300,000 a day plus bonuses for the highest-end assets. So what Roddie was saying about the ultra-deepwater market, if you look at those really high-end asset with the high hook load capacity, we think you could see similar movement in dayrate. Maybe it's not quite that fast, maybe it is. But -- so what you're thinking about is not out of the realm of possibility, just based on recent data that we have available to us in the harsh environment market. The other data point I would address you to -- or direct you to is the recent signing of the 20K rig with Chevron. So if you look at that rig and you back out the 20,000-psi blowout preventers and you kind of back that out of the dayrate, you're looking at a dayrate somewhere between $350,000, $375,000 a day for a premium seventh-gen rig with 15,000 psi, and that's a start date in 2021. So I mean our customers have the advantage right now. There's no doubt about that. So in Chevron's mind, I can't speak for them, but you would say, listen, a $360,000, $375,000 dayrate on a premium ultra-deepwater rig in 2021, they think they're getting a discount at $350,000 to $375,000 a day. And so I think that bodes well in terms of thinking about dayrates. So I can't tell you what dayrates are going to be, but we do have some data points out there that would point to somewhere in the neighborhood that you're talking about.

Our next question comes from Scott Gruber of Citigroup.

I want to start with a question on the Norge. Jeremy, how are you thinking about the possibility of buying out the remaining interest in the rig? If you think that's likely, can you comment on the timing? Is that this year, next year?

I mean, I think ultimately that's the end game. But I think we're going to need to see another fairly healthy contractor extension behind the current one before we make that decision. But I think both parties in the joint venture agree that ultimately, market condition supported, that Transocean will ultimately own that rig outright.

Got it. And just following Kurt's question on the face of demand recovery, Brazil seems to be a key region in terms of the outlook for demand recovery here with Petrobras now adding some more rigs, and the majors pick up a number of new blocks. Can you just comment on the Brazilian floater count specifically? Where do you think that could end now? At the end of '19, end of '20, end of '21, if you want to go out that far? Kind of how do you think about Brazil specifically?

Sure. We've said on previous calls -- and I'll turn it over to Roddie in just a sec, we said on previous calls that we think the more normalized rig count, if you will, if anything's normalized in this market, could be somewhere approaching 40 active rigs with 30-ish probably run by Petrobras and another 10 to 15 by the internationals. And so we think we can get to that point again. Unfortunately, as is with all things in Brazil, things kind of pushed to right never happen according to the timetable that we would like. But I think if you get out a couple of years, you could certainly see a rig count of that magnitude. And Roddie, I don't know if you want to add more color.

Yes, absolutely. So when we think about just 2019, the near term, we're expecting that Petrobras is going to make somewhere in the region of 5 to 7 fixtures in 2019, which is great because that brings them off bottom and starts building the rig count a little bit. But in addition to that you get another 5 to 7 fixtures from the IOCs in Brazil. So that's a pretty healthy outlook. The real interest is probably as you had stated towards the end of '20 and '21 where things really start to push on. So yes, we're just looking at the tenders that're out just now, and we think that, that rig count in Brazil is going to increase over the next 12 to 18 months. And I think after that, it could increase quite sharply.

If I could squeeze one more. Can you just comment on the types of rigs that are being demanded in the contracts, particularly with the majors but also with Petrobras? Just in terms of the quality step-up, there seems to be one, but just want to hear from your perspective what you're seeing?

Yes, absolutely. So specifically, to Brazil, that is what we're seeing is there's a variety of tenders. So Petrobras in particular are very good at parsing out kind of categories of tenders. So in the deeperwater tenders, they are demanding much higher-specification rigs. So that's kind of lowering the average age and raising the high spec -- the average spec of the rigs in Brazil. But then you also have some of the [MIR] tenders that are for, obviously, a little bit older rigs but less capable. So there seems to be a pretty good spectrum of demand across the different rig specs in Brazil but certainly, a push for higher-spec rigs and primarily more efficient rigs is where we see it going.

Our next question comes from Sasha Sanwal of UBS.

Jeremy, maybe the first question for you, just to kind of follow up on some of your market commentary. I was intrigued by just some of the comments you were making about the shipment tendering through direct negotiation, we've seen that on the past cycles as well and then some of your commentary just about potentially negotiating some of the shipyard, essentially, surveys for some of these reactivations. Can you kind of comment and maybe give us more color on just how broad-based this is across regions and then maybe in some of these discussions is the contract term that's under discussion also lengthening?

Yes, sure. I'll let Roddie field that one.

Yes, sure. So if we think about direct negotiations, so what we've seen is, there are more direct negotiations, particularly around extensions of existing rigs. But what we're also seeing is when a tender goes out there in the beginning, I think the replies now are that there are far less assets available that are highly desirable. So typically you'll see an operator just selecting the 1 or 2 that are available and going direct with those contractors, which is obviously very positive for us. You asked about durations. So that's actually one of the key themes that -- we do a snapshot year-on-year. So in January 2018 versus January '19, and we're actually seeing that the length of the projects is more than doubled. So if you take the average length of a project, it's doubled. That basically demonstrates that things are looking much better for the long-term. And then I think just in general as we go around the world, you see that the direct negotiations clearly in Norway and the North Sea are prevalent now where everything was tendered previously. I think that's basically more often than not the case. And certainly, for the high-specification units in the ultra-deepwater side of things, there's a lot of direct negotiation because again, the supply of the best-spec units is pretty tight.

Great, that's helpful. As maybe as a follow-up, just wanted to see if we can get an update on just potential reactivation costs for the rest of the Ocean Rig assets. Any -- right, just any change there?

Sasha, no change to that yet. We're still working through that. You've obviously seen our comments on the Ocean Rig Santorini and Crete. But at this stage, we haven't completed our analysis and updating our previous guidance of about $35 million for those rigs.

Our next question comes from Greg Lewis of BTIG.

Greg?

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on contract.

Sorry, Greg. We missed the question.

Oh, yes, sure. So I guess my question is around the Chevron 20K stacked rig contract. And really, how we should be thinking about that on the dayrate curve because just -- I mean if I think about that rig, that seems like a one-off kind of biggest, best rig in the world?

Right. Yes, so I'll just kind of go back to what I said previously, if you back out the upgrade cost from the dayrate, you get to a 15,000-psi kind of gen-7 rig with high hook load capacity, there's no doubt in the $350,000 to $375,000 day range. So I think that's the only market that we have out there today, and so I'm thinking somewhere in that range as we get into 2021 for that type of asset, maybe a little north of that, maybe a little south. But I think something in that range is fairly reasonable.

Okay, great. And then just -- and then, I guess when the 2 rigs, the Ocean Rig, the Paros and -- was I guess decided to be retired. Was -- how much equipment was able to be taken from that rig and sort of put back into inventory or sort of thought about? I mean, just in thinking about the BOPs, the pipe -- was there sort of any number we could throw on that?

Zero, probably. I mean that rig was -- that rig had gone through some pretty tough times with an owner that had gone bankrupt and had not invested in the asset at all. That were no records of any maintenance or original equipment documents. It had been cannibalized for parts. And it was in pretty bad shape.

Our next question comes from Taylor Zurcher of Tudor, Pickering, Holt.

Jeremy, in the past, I think you've talked about potentially reactivating 1 to potentially 2 of the Ocean Rig floaters per year moving forward. And so my question is, is that still the assumption -- or a fair assumption to make today and I assume the $3 billion revenue guidance for 2019, there's effectively nothing embedded in there for rigs that -- on the Ocean Rig side that aren't currently contracted today?

Well, the pace of reactivation is going to depend on the contracts. And so to the extent that we can secure contracts that are deserving of reactivating the asset, then we'll make that decision at that point in time. But I mean given what we're seeing in the marketplace, it's probably not unreasonable to think that -- what was the second part of the question? Mark?

Yes. Let me just add to that. So we've included no reactivations into our guidance. We had revenue, albeit OpEx or CapEx. Just to remind you, Ocean Rig does have 2 warm-stacked rigs are sitting in Las Palmas. So those will be the first 2 assets more likely than not to get reactivated through contract.

I think we'd also add that we're at the point in the market now for the right assets that I don't believe we any longer have to fund the mobilizations or the reactivations ourselves. So I think a lot of stuff that you -- that our customers will see [as bid] in the market is basically inclusive of them paying those costs. And essentially, as Jeremy had indicated, the operators delivering record level cash flows, it doesn't make sense really for us to be funding those reactivations at this stage. Certainly, maybe a few fixtures that were made in the past will include that, but I think going forward, much less of it.

Okay. And if I heard you correctly in prepared remarks, you talked about a third drillship likely being mobilized to Mexico for one of your IOC customers. Is that -- if I heard that correctly, is that a rig that's currently contracted? Or is that a rig that would be idle today?

No, it's a rig that's currently contracted and operating in the U.S. Gulf of Mexico.

Our next question comes from Eirik Røhmesmo of Clarkson.

Could you just discuss a bit more around the second newbuild at Jurong. In terms of your mentioned potential opportunities, is it fair to assume that, that rig will be the one chosen for other high-spec opportunities in the U.S. Gulf of Mexico? And in terms of additional CapEx, would that be in the same kind of range?

So there's certainly interest for that asset across multiple customers, and so we're obviously in conversations on that rig right now. But in terms of further upgrades to that rig, we don't have anything planned at this juncture. We did upgrade it to the 3 million pound hook load, which certainly differentiates it in the class of rigs. And so it is going to be, we think, a rig that will be in high demand once it's delivered, right.

Yes. Certainly, the high hook load and a few other key features that are on that rig make her very interesting for the really difficult deep wells in the Gulf of Mexico. And also as Jeremy said, this time we're not planning to do it proactively, but certainly, with a contract, she would be just an ideal candidate for the second 20K rig.

All right. And just a quick one on the Ocean Rig transaction. Is there any update on the estimated synergy effects on that? Or is the number still, what was it, $70 million or so?

Eric, we're going to stand behind our $70 million, and as I've mentioned previously, we expect to get that all in 2019.

Our next question comes from Colin Davies of Bernstein.

I wonder if I could get a little bit more color on the master service agreements you mentioned in the prepared remarks, a sense of how rig-specific is it, pricing, term. Just a little bit more color would be helpful.

Yes. I'll take that one. So that master service agreements that we enter are actually a vehicle for which to contract very expeditiously. So standard terms and conditions, like liabilities, indemnities and such are then kind of memorialized in that master service agreement, and the piece that does get negotiated each time is often service agreement is attached to it that deals with the rig-specific. So which particular asset is, how long the program is, when it starts, those kind of things.

That make sense. That make -- that's helpful. And then just on further scrappage, obviously, the Paros was an interesting one, as you say, fairly degraded sixth-gen. Do you think that's kind of a one-off special situation? Or do you think the industry and perhaps, Transocean specifically, is now taking a harsher view on perhaps some of those earlier sixth-gens that are still sitting out?

No, the -- yes, the Paros was definitely a special circumstance. And as I said the owner went through bankruptcy and became virtually nonexistent and didn't invest anything in the asset. And so it was just -- it was basically just a hull that remained. And so that was a very special circumstance. With respect to our fleet strategy, I think we've been pretty clear and consistent over the course of the last 4 years. We are focusing on that high-end high-specification ultra-deepwater drillship and harsh environment semisubmersibles. But no, not -- I don't think you're going to see a big push to eliminate sixth-gens from the global fleet. Still very marketable assets, very capable assets.

We will take our last question today from Sean Meakim of JP Morgan.

I was hoping we could maybe just talk a little bit on contract strategy today. How are you thinking about managing fixed-priced options? Are we factoring in escalators, variable indexing? Just thinking about new contracts, is it different than maybe how you thought about that a year ago? And to some extent, if drilling efficiencies lead to contract impairments, how does that sit near term if it's -- if ultimately, those results are helping to drive potentially incremental opportunities with customers?

Yes. I'll handle that one. I think in terms of impairments for higher performance, we definitely don't see that. I mean we -- what we see is a great performing rig gets recontracted and actually helps the operators justify picking up additional rigs because their cost per well goes down. So that's really the direction to push into.

And with respect to the long-term contracts, we're -- we definitely have a different view today than we had 12 to 18 months ago as it relates to the ultra-deepwater market and are unwilling to lock up our best assets in longer-term contracts at today's dayrates. And so anything beyond the next 6 to 12 months, we're going to have an escalation built in for any term beyond that or we're just not going to accept it or are not going to bid it.

Absolutely. And I think you see is that we're really keeping validities much shorter and obviously, honoring offers that we've made in the past and I'm sure many of our competitors will, but going forward, there's just a much less willingness to, a, to offer options because they create some uncertainty as to availability and, b, pricing now here would ultimately be pricing on a much higher level for the future work.

Got it. No, that's very helpful, I appreciate that feedback. And then just with respect to the ring automation upgrades, Equinor has been a trailblazer in a number of these areas for a long time. Are there other operators as focused on efficiencies? Are there specifics that make these rigs more amenable? Just thinking about more the addressable market is for you for ADC upgrades.

Yes. No, absolutely. There's -- ADC is actually several components pulled together, and those components are of great interest to others around the world. So it just so happens that we kind of jumped first in Norway, but in the Gulf of Mexico here, we've got several of our major customers are very interested in technology and efficiency upgrades. So I think you could see it translate very quickly to Gulf of Mexico side. But then to be quite honest, any rig that would benefit from it is a candidate.

This concludes today's question-and-answer session. Mr. Alexander, I will now turn the conference back to you for any additional or closing remarks.

Thank you 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 first quarter 2019 results. Have a good day.

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