Transocean Ltd (RIG) 2017 Q4 法說會逐字稿

Good day, and welcome to the Q4 and Year-end 2017 Transocean Earnings Conference Call. Today's conference is being recorded.

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

Thank you, David. Good morning, and welcome to Transocean's Fourth Quarter and Full Year 2017 Earnings Conference Call. A copy of the press release covering our financial results, along with supporting statements and schedules, including reconciliations and disclosures regarding non-GAAP financial measures, are posted on the company's 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, Vice President of Marketing and Contracts.

During the course of this call, 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 of management 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.

(Operator Instructions)

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

Thank you, Brad, and a warm welcome to our employees, customers, investors and analysts participating in our fourth quarter and full year 2017 earnings call. I would like to start today's call with a recap of 2017. As reported in yesterday's earnings release, for 2017, the company generated adjusted normalized EBITDA of $1.2 billion on $2.8 billion in adjusted normalized revenue, resulting in an adjusted normalized EBITDA margin of 44%. Over the past 2.5 years, Transocean had been acutely focused on enhancing the quality of our fleet, continuing to drive operational excellence through improvements in safety, uptime and drilling efficiency, establishing Transocean 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 bolstering our balance sheet.

Let's start by looking at our fleet. In 2017, we welcomed 2 ultra-deepwater newbuild drillships to our fleet, the Deepwater Pontus and the Deepwater Poseidon, both of which are among the most technically capable rigs in the world and both are in tenured contracts with Shell. The Deepwater Pontus commenced operations in the fourth quarter of 2017, and the Deepwater Poseidon commenced operations last week. Further in 2017, we agreed with Jurong Shipyard to enhance our 2 remaining newbuild drillships by increasing the hook load capacities to an industry-best 3 million pounds, making them the only rigs in the industry capable of running the heaviest drill streams while maintaining spare overpull capacity. These upgrades also position these rigs as ideal candidates for future 20K BOP conversion. We also upgraded the Discoverer India, adding a second annulars of BOP as well as acoustic BOP controls for enhanced redundancy. We also made our NPV capable and converted from DP-2 to DP-3 station keeping. And finally, we announced that we have reached an agreement to acquire Songa Offshore, adding 4 new contracted, harsh environment, high-specification Cat-D semisubmersibles to our fleet.

While certainly not as exciting as newbuilds, upgrades or acquisitions, during 2017, we also streamlined and strengthened our fleet by announcing the divestiture of our jackups, including 5 that were under construction. We also announced the retirement of 9 of our older assets, including 5 ultra-deepwater floaters, which were unlikely to be competitive in the foreseeable future. This brings our total number of floaters retired since the start of the downturn to 39. When considering the divestitures, the retirements and the additions of Songa and the 2 newbuild ultra-deepwater ships at Jurong, our combined fleet now stands at 49 floaters, 84% of which is comprised of ultra-deepwater and harsh environment assets.

Moving from fleet quality to operational excellence. I'm pleased to report that in 2017, we delivered the lowest total recordable incident rate in the company's story history and achieved 11 consecutive months without a single lost time incident. When added to the previous year's performance, we achieved a company-record 20 consecutive months without a single LTI across our global fleet. While we were certainly proud of our overall safety performance from January through November, on the morning of December 2, a tragic accident occurred onboard the Petrobras 10000, resulting in a fatal injury. Needless to say we remain saddened by this devastating loss, and we'll continue to honor the memory of the crew member lost while sharing with the industry the lessons that we've learned from this tragedy. As you might expect, following such an incident, we immediately shut down all operations on the rig so that Petrobras and Transocean could jointly conduct an investigation and detail a rigorous recovery and return-to-work plan. While the process is taking longer than anticipated to complete, we expect the rig to splash the BOP in the coming days and then return to work by the end of the month. This incident was a significant factor in driving our lower-than-anticipated fourth quarter revenue efficiency.

Despite the disappointing fourth quarter performance, our revenue efficiency for the full year averaged 96.3%. This indicates that our annual uptime performance with our customers was extremely strong, especially when considering the challenges associated with introducing 5 newbuilds over the past 2 years and reactivating and relocating several stacked assets. As we move into 2018, we expect that our new OEM healthcare contracts, which covers some of the most critical components on our rigs, will further improve our uptime. These new agreements, which we executed with 5 suppliers, support our goals of reducing cost, and more importantly, continuing to improve equipment reliability.

When we think about operational excellence, we consider safety and uptime, which we just highlighted. We also consider drilling efficiency. Last February, we launched our efficiency dashboard, which is available on desktop and mobile applications. Since launching our drilling efficiency campaign, we have improved the average tripping time across our ultra-deepwater fleet by more than 40%. We believe additional opportunities for efficiency are plentiful as we are currently benchmarking a relatively small percentage of all well construction operations. As we increase our benchmark operations over the coming months, we expect to recognize incremental improvements in drilling efficiency. Through these improvements in equipment reliability and drilling efficiency, we are reducing the cost of offshore drilling in a systematic and structural manner, which we hope will ultimately transcend the market fluctuations and encourage activity and investment throughout the cycle.

Because of our fleet enhancements, improvements in safety, reliability and drilling efficiency and our strong customer relationships, we continue to establish Transocean as our a customers' universal first choice. Despite intense competition in 2017, Transocean won 25 new floater awards, which represented 10 more fixtures and 5 more rig years awarded than our nearest competitor. Of these 25 new awards, 6 were with new customers for Transocean. Excluding Songa, we added $873 million in backlog on the existing fleet, almost a 70% increase over 2016. Of this total, $652 million was secured in the fourth quarter, validating our view that the offshore market is indeed improving.

Of particular note in 2017, we reactivated for 4 floaters, all associated with new contracts. 1 of the 4 included the semisubmersible Development Driller 1, which returns Transocean to the Australian market where we have been very successful in the past. The rig is on schedule to commence its contract in April. And since the DD1 will be one of the most technically capable assets in the Asia-Pacific region, she will be well positioned for additional opportunities.

In addition to the DD1, we are extremely pleased to have once again contract with Statoil for the harsh environment semisubmersible Transocean Spitsbergen. The rig was awarded a market-leading day rate with additional bonus opportunities. The program is comprised of 22 wells with an estimated duration of 33 months. Also in the fourth quarter, the harsh environment semi Transocean Arctic was awarded 2 contracts with different customers offshore Norway. The first contract consists of 3 wells with 2 one-well priced options commencing in May. The second is a 4-well contract for approximately 1 year commencing in the third quarter of 2019. Both awards further demonstrate the growing momentum in the harsh environment market. Additionally, the Paul B. Loyd, Jr. was awarded a one-well contract with Repsol Sinopec that closes the gap between the end of its most recent fixture and the commitment -- commencement of its work with Hurricane and Zenor. With rising customer demand driven by a $30 per-barrel breakeven levels and a limited number of harsh environment assets available in the market, we expect demand for the higher-specification, harsh environment assets to continue strengthening.

Turning to a few highlights on the ultra-deepwater side. We are very pleased to be returning to West Africa with our new award for the Discoverer India. The asset will commence 5 wells starting in April, which should keep the rig working for most of 2018. With the newly upgraded India in West Africa, it, too, is well positioned for future opportunities in the region. Another noteworthy ultra-deepwater award was for the KG1 offshore India. The contract, which is for 6 wells plus options, revives our relationship with Reliance and increases our footprint in the Indian market. We were also pleased to secure additional work for the Deepwater Nautilus, which was awarded an incremental contract with Shell Brunei to drill 1 well with 3 additional one-well options.

Turning to the U.S. Gulf of Mexico. In the fourth quarter, we signed an agreement with BHP to extend the Invictus from the completion of the rig's maiden contract to the commencement of its new contract in April, fully committing the rig through all of 2018. We are also very happy to return the Deepwater Asgard to work for Murphy in the U.S. Gulf of Mexico for a 3-well contract with a 1-well priced option. This award keeps one of our best assets working and positions it well for longer-term fixtures as the market improves.

While we are certainly excited about the flurry of awards in the fourth quarter, we were disappointed with the amendments to the Transocean Leader's contract. The rig performed exceptionally well during the customer's fracking campaign. In fact, EnQuest was ahead of schedule on this program. Unfortunately, the rig experienced unplanned downtime due to repair delays, which were exacerbated by inclement winter weather in the North Sea, providing the customer with the right to cancel the contract. However, as a testament to the performance of the rig and the crew, EnQuest has chosen to complete their program with the Leader, albeit with an amended drilling contract. The Leader just completed its repairs and has departed the shipyard. But as a result of the amended contract, it will not earn a day rate during the first quarter of 2018. However, in conjunction with the aforementioned amendment as well as the new contract with another customer, the Leader is expected to return to work April 1 and is now contracted into early next year.

Overall, demand was much stronger in 2017 with significant improvement in the fourth quarter. And as evidenced by the relative number of fixtures awarded to Transocean versus our competitors, it is clear that many operators are recognizing us as their first choice.

As a final recap, on 2017, we continued to strengthen our financial position and extend our liquidity runway. We added to our backlog through the $873 million in new awards that I just discussed and the acquisition of Songa Offshore which added $3.7 billion. We converted a large percentage of our backlog to cash through a combination of higher revenue efficiency which again averaged more than 96% for the year and lower cost driven by the continued streamlining of our organization and our processes. And as Mark will discuss in just a moment, we continue to proactively strengthen our balance sheet.

As we turn to 2018, I'm pleased to report that Songa Offshore is now officially part of Transocean. As mentioned, with this acquisition, we added to our industry-leading backlog, providing more visibility to future earnings and cash flows. We also significantly enhanced our fleet by adding 7 semisubmersibles, including 4 new harsh environment semisubmersibles, which were designed in collaboration with Statoil. Needless to say, we remain excited about this transaction and our growing presence in the strategic geographic market of Norway.

Before handing the call over to Mark, I would just like to offer a few comments on the macro environment and a little more insight into the global drilling market, looking forward. Oil prices have been steadily climbing since late 2017 with Brent recently reaching a 3-year high, about $70 per barrel. This upward price momentum has provided some needed confidence among our customers Indeed, new 2018 offshore project commitments are forecasted to rise approximately 140% as compared with 2017. As we move into 2018, we see a handful of near-term opportunities in the Gulf, primarily driven by the independents. We are also encouraged to see recent ultra-deepwater tenders for some of the majors and regions around the world, indicating long-term sentiment is shifting for the better.

Brazil is a bright spot for increased offshore activity as several IOCs have made significant capital investments in the area, and are now awaiting regulatory approval to proceed. We believe this growing interest in this part of the Golden Triangle will drive an increase in tendering activity in 2018 and 2019 for projects commencing in late 2019 and 2020.

In addition to Brazil, other parts of Latin America, including Mexico, Trinidad, Colombia, Guyana, and Suriname, are all showing increased demand for future rig activity with current tender suggesting this should continue to improve. Mexico is particularly interesting. In the past year, we have seen 10 shallow water and 19 deepwater blocks awarded with a possibility for more later this year. The speed at which we are seeing activity pickup, in many cases, going from block award to spud within a year, bodes very well for the near-term future of offshore drilling in Mexico.

In Eastern Hemisphere, tendering in both the U.K. and Norway has now directly translated into heightened activity with contracts at attractive day rates. While not yet returning to the pinnacle rates at the height of the market, we see a tighter market and long-term activity planning, which should drive sustained improvement in these harsh environment regions.

As mentioned earlier, we are very pleased to be returning to West Africa with the Discoverer India. We think further opportunity is emerging in this region beginning later this year. Rigs are returning to work in the Ivory Coast, Senegal and Ghana, to mention a few, and we are now seeing the possibility for 3 to 4 rigs to be added to the Angolan market over the next year.

The Asia-Pacific region was good to us last quarter with several important wins in India, Myanmar, Brunei, Malaysia and Australia. And as we enter 2018, we continue to have a positive view of this region with yet more tenders expected throughout the year.

To recap, we are very pleased to see that the improving sentiment that we discussed on our last call has indeed translated into solid contracts around the world. In particular, we are very excited about the opportunities in Norway, the U.K. and Canada. We are witnessing a tightness of supply and demand for mid-water and harsh environment asset, which is driving ongoing day rate improvements. We are encouraged by some of the opportunities that are surfacing in Australia and other parts of the Asia-Pacific region. And as we discussed on the last call, for the first time in 3 years, we are seeing multiyear awards in the Golden Triangle.

In conclusion, today's outlook is certainly more encouraging than it was a year ago. Given the improvement that we have witnessed in harsh environment utilization and day rates, we feel strongly that this market is in the early stages of a recovery. And while we have yet to see a point of inflection in the ultra-deepwater market, the increase in tendering activity certainly bodes well for the future. Still, since the precise timing and trajectory of the recovery is ever evolving, we will continue to take the necessary actions to best position Transocean to effectively manage our business throughout the cycles and deliver long-term value to our stakeholders.

Before turning the call over to Mark, I would just like to thank the entire Transocean team for your efforts in 2017. As we move into 2018, let's maintain our focus on customer service, fleet quality, operational excellence and organizational efficiency. Mark?

Thank you, Jeremy, and good day to all. During today's call, I will highlight certain items included in our fourth quarter results and provide an update to our 2018 guidance, which includes Songa Offshore for the first time. I will also update our liquidity forecast through 2019.

As reported in our detailed press release, for the fourth quarter 2017, we reported a net loss attributable to controlling interest of $111 million or $0.28 per diluted share. Excluding net unfavorable items of $18 million, adjusted net loss was $93 million or $0.24 per diluted share. As anticipated, our fourth quarter operating and maintenance expense increased in line with our prior guidance by $66 million sequentially to $389 million. And as previously indicated, this was primarily due the following items: the contract preparation and reactivation costs related to our previously announced new contracts on the Development Driller 1 in Australia, and the Deepwater Nautilus, which commenced operations in November in Malaysia; the commencement of operations of our latest newbuild drillship, Deepwater Pontus, on its 10-year contract in the Gulf of Mexico; timing of scheduled rig maintenance; and recycling and towing costs associated with some of the previously announced floater retirements. Our 2017 adjusted normalized EBITDA margin was 44% compared to 46% in 2016. In 2017, despite a 26% drop in revenue, we delivered another year of strong financial results in very challenging market conditions.

In the fourth quarter 2017, income tax expense included $66 million charge associated with the remeasurement of deferred tax assets and liabilities related to recent U.S. tax reform. Offsetting this charge was a $31 million decrease in U.S. valuation allowance.

As Jeremy previously alluded to, in 2017, we once again successfully executed on multiple financing transactions that further enhanced our liquidity and balance sheet. We issued approximately $1.2 billion of debt maturing in 2022 and 2026 while retiring $1.8 billion of debt with maturities between 2017 and 2020, which includes $96 million in export finance obligations.

As a result of these transactions and our strong cash flow generation, in 2018, we reduced net debt by almost $1 billion. In addition, we refocused our corporate strategy by monetizing our jackup fleet and eliminate approximately $1 billion uncontracted shipyard obligations. These actions, in aggregate, provide an extended liquidity runway while continuing to provide strategic optionality. Ultimately, we ended the fourth quarter 2017 with liquidity of $6 billion, including our cash and short-term investments, and a $3 billion undrawn revolving credit facility. However, despite the harsh environment clearly recovering and contracting activity accelerating in the ultra-deepwater segment, we will remain cautious and continue to retain a large cash balance for the foreseeable future.

Turning now to acquisition of Songa Offshore. On January 20, we closed the acquisition of Songa with 97.7% of the Songa shares being tendered. We are currently conducting a compulsory acquisition of the remaining shares and expect to complete the squeeze-up at the end of the first quarter.

Before I provide the combined company's financial expectations for the first quarter and full year 2018, let me update you on the consideration mix used to conclude the $3.4 billion Songa transaction. As a reminder, Songa shares were offered a choice of Transocean equity, exchangeable or convertible bonds and cash that created some variability in the composition of a final consideration. So to summarize, we issued 66.9 million Transocean shares to legacy Songa shareholders. We issued approximately $850 million of exchangeable bonds, of which approximately $560 million were issued as consideration to Songa shareholders and approximately $290 million to retire and/or convert a majority portion of the legacy Songa unsecured bonds. Including the exchangeable bonds, on a fully diluted basis, Transocean share count is now 541 million shares. We used approximately $200 million to retire other unsecured Songa debt, equity, interest rate swap obligations and for costs associated with the transaction. And finally, we assumed approximately $1.6 billion of net debt, which is secured by the 4 Cat-D harsh environment semis and their long-term contracts with Statoil.

Turning now to our combined companies 2018 financial expectations. Recognizing that we closed the Songa transaction at the end of January, our guidance reflects 11 months of Songa's 2018 activity. For the first quarter 2018, we expect the fleet average revenue efficiency of 95%, excluding the impact from the Petrobras 10000. Other revenue for the first quarter of 2018 is anticipated to be approximately $50 million, which includes customer reimbursables and $38 million of early termination revenue for the Discoverer Clear Leader. You may recall that the early termination revenue would be amortized into the fourth quarter of 2018. Additionally, purchasing -- purchase accounting rules require that we calculate the fair value of the 4 long-term Songa Cat-D drilling contracts. This is achieved by comparing contracted day rates to expected market day rates and recording the excess as contract intangible asset. This asset will be amortized as a noncash reduction to revenue over the remaining life of these drilling contracts. We will post a schedule on our website detailing these amounts in conjunction with our first quarter earnings call.

We expect first quarter O&M expense to range between $400 million and $415 million. When isolating for legacy Transocean, O&M expenses are about 7% lower than the fourth quarter 2017.

We anticipate first quarter G&A expense to be approximately $50 million. The first quarter is expected to be higher than the remaining quarters of 2018 due to certain transaction costs associated with the closing of the Songa transaction.

Net interest expense is expected to be approximately $160 million. This includes capitalized interest of approximately $10 million and income of $8 million.

Capital expenditures, including capitalized interest for the first quarter of 2018 are anticipated to be approximately $65 million, including newbuild CapEx of $40 million and maintenance CapEx of $25 million.

We expect revenue efficiency for the remaining 3 quarters of 2018 to be approximately 95%. Other revenue for 2018 is expected to be approximately $180 million, which includes customer reimbursables and $125 million of revenue associated with the early termination of the Clear Leader.

Operating and maintenance costs for 2018 are expected to be between $1.55 billion and $1.65 billion. This includes 11 months of operations for the Songa rigs and forecasted O&M costs associated with the additional contracts reflected in Monday's Fleet Status Report. This estimate does not include any speculative reactivations. The integration of Songa is proceeding well, and we expect to achieve our targeted annual run rate of cost synergies by the fourth quarter of this year.

We expect our G&A expenses in 2018 to range between $160 million and $170 million. Full year depreciation expense is expected to range between $830 million and $840 million.

Full year 2018 net interest expense is expected to be approximately $635 million, including capitalized interest of $40 million and interest income of $30 million.

Our 2018 cash taxes are expected to range between $45 million and $50 million. This excludes the impact of U.S. tax reform and Jobs Act. We continue to analyze certain aspects of the 2017 tax reform act. The tax reform includes a onetime tax on unrepatriated earnings of non-U. S. subsidiaries. Given the complexities associated with the repatriation tax analysis, we have elected to defer estimate in this amount until later in 2018.

Capital expenditures for 2018 are anticipated to be $160 million. This includes $75 million of newbuild CapEx and $85 million for maintenance CapEx.

Turning now to an update of our projected liquidity as of December 31, 2019, and excluding any assumption for new or extended revolving credit activity to replace our current revolving credit facility expiring mid-2019. Our estimated year-end 2019 liquidity is expected to range between $2.2 billion and $2.4 billion. As I mentioned in our previous earnings call, renewing or extending the RCF remains a priority, which we expect to complete during 2018.

2019, we expect total CapEx to be approximately $200 million. This includes approximately $95 million on the remaining 2 newbuild drillships and $105 million for maintenance CapEx. Please note that both 2018 and 2019 CapEx guidance excludes any speculative rig reactivations. This strong liquidity position, combined with our industry-leading contract backlog of $12.8 billion, positions us very well for the future.

Before I close, I would also like to thank the Transocean organization for their efforts in 2017, and particularly, for the hard work in completing the summer transaction. Well done to all. That concludes my prepared comments. Brad?

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

(Operator Instructions) And we'll take our first question from Blake Hancock with Howard Weil.

Jeremy, congrats on the wins that we saw on the Fleet Status Report. And obviously, you sound a little bit more bullish than maybe we have in the past. Can you talk about kind of maybe filling in the windows between -- in '18 and '19 as rigs roll off, and we kind of get to the longer-term contracts that you're talking about commencing in '19 and '20? Are those there? Or should we kind of expect some downtime still? Just trying to think about how the commodity prices are helping kind of the next 2 years before we get into the multiyear term contracts.

Yes. Thanks, Blake for the question. I'll hand it over to Roddie, but thanks for the recognition. We were accused of being a little bit more bullish last quarter as well and it because we had visibility to quite a few potential tenders that were out there and felt good about our chances, and I think that materialized in Q4. I don't expect a repeat in Q1 of the awards that we secured in Q4, but we still -- there's a lot moving around out there, and it is very encouraging across the globe. And with that, I'll turn it over to Roddie.

Okay. Hey, Blake, to answer your question specifically, yes. And kind of '16 and '17, we saw some gaps between contracts. But now, what we're beginning to see is -- even in '18, where we do have some gaps, those are rapidly being filled up. There's clearly a desire for hot assets in the market. And certainly, on the harsh environment side, for example, we had a few gaps on the Arctic's contract. Those are being filled up very quickly, and we're cautiously optimistic there won't be any gaps on that contract as an example. And then on some of the other ones, almost every rig that we have reactivated through one of the contracts that we won in 2017 has multiple follow-on opportunities. So we're feeling pretty good about that. And clearly, as you mentioned, we've seen quite a shift in the sentiment of the market to the positive, so we like that.

That's great. And Jeremy, I hate to harp on it. On the Leader, it seems very one-off-ish but hoping maybe you could just talk about that a little bit. And how common is this in contracts and any concerns we should have going forward?

Yes. The Leader was somewhat unfortunate. We identified that crack in one of the guide rails in the derrick that needed to be fixed. We thought that we could do it on location during operations. Unfortunately, it was winter time in the North Sea, which is not really conducive for work at height. And so there were numerous days over that 30-day window that we were given to get the work done, where we just weren't able to work. I mean, it was probably half the time that we just weren't able to work because of weather conditions. As a result, the customer had the contractual right to terminate the agreement early. And this was one of those contract that was signed back in good times with nice day rates, and so they took the opportunity. But as evidenced by the fact that they renegotiated the contract, they obviously liked the rig. They liked the crew performance and the overall performance that they've had with Transocean. With respect to other contracts, I'll defer to Roddie on that one.

Yes. Blake, so this was actually the last of our high day rate contracts on an older asset. So in terms of could this happen again to some of our other high day rate contracts, it's highly unlikely. We basically have the -- all of the remaining high day rate contract that were signed at the height of the market are all in newbuild rigs that have essentially no-cut contracts. So the out for extended downtime is nothing like what you saw in the Leader. The Leader is actually a fairly typical 30-day [clause] in the industry, but newbuilds for us are no cuts and include many, many months longer than that. So I think the risk of a recurrence is extremely low at this point.

And next, we'll go to Angie Sedita with UBS.

So congratulations on closing Songa, first off. And so when you think through M&A transactions with other companies and the opportunities that are out in the market and kind of discuss a little bit about the key parameters for looking at any additional opportunities, whether it's contract, coverage or neutral to positive to the balance sheet. And is it fair to think that a company is essentially off the table if they have quality rigs but no contract coverage?

Yes. Great question, Angie. And kind of going back to our market sentiment, we said that the harsh environment market was clearly in the early stages of recovery. We're seeing that in utilization and in day rate improvement. And so as we look at acquisition candidates, we would certainly be more inclined to look in that particular piece of the market because we do see that recovery playing out. And so harsh environment assets would be more of interest at this point than ultra-deepwater assets, which we still haven't seen that, that point of inflection. But then besides that, asset quality is going to play into it. Balance sheet is going to play into it, and contract coverage is certainly going to play into it. At this point in time, going out and making an acquisition of an individual asset or a complete company that's solely focused on ultra-deepwater don't really make a whole lot of sense to us. We think time is on our side in that area, so we're going to continue to monitor the environment. But at this point in time, I think you'd see more of a focus for us on harsh environment, solid balance sheet and solid backlog.

Okay, okay. Fair enough. And then you highlighted a little bit in your prepared remarks on the opportunity set in Brazil and Mexico and tendering opportunity in Brazil in '18 and '19 with work on '20. But can you talk a little bit more about the Mexico market as well, when you could start to see some tendering activity out of that market? And then any estimates for both Brazil and Mexico on how many incremental rigs to come into those markets?

That was a 4-part question, Angie. I'll turn it over with Roddie and maybe hit Brazil first and then get into Mexico a little bit.

All right. Sure. Okay. So Brazil, as you know, they had the rounds last year. And their -- the new block tender rounds are coming up this year in the end of March and also in June before the election, and this is being dubbed as the mega tender. So what we expect to see is huge participation by the IOCs which is really positive for Brazil, overall, in terms of foreign investment, but also the fact that there's less reliance on one company, Petrobras, right. It's now spread across many more. So we are very optimistic about the IOCs bringing more and more rigs to Brazil, and we think ultimately because of the specifications that they like to see in those rigs that eventually, day rates, they will start to pick up and look a little bit healthier. On the Mexico thing, so Mexico is extremely interesting. So we saw the first rounds, there was lots of participation. And then round 2.1 and then 2.4 with 10 awards and 19 awards, respectively. We're actually now seeing the resurgence of the majors. So in the first round, they were a real mixed bag. But now, big companies like Shell are coming to the fore, and they're betting big on deepwater, and they're doing it in Mexico. Essentially, you've got a lot of the same plays that they've explored in the U.S. Gulf of Mexico. So that's right in our wheelhouse in terms of capability of rigs and our expertise in drilling those fields. So again, we feel very optimistic about that. And one of our customers who has a rig in the Gulf of Mexico is expected to take one of those rigs from the U.S. to Mexico later this year, so that's a great segue for us to enter that market.

And next, we'll go to Gregory Lewis with Crédit Suisse.

Jeremy, you kind of tempered expectations in the near term around contracting, following the flurry in -- towards the back end of the year. As we think about the seasonality of tendering and contract awards, could you sort of gauge like how we should be thinking about the next few quarters in terms of -- as operators start to look out into '19 when we should start to see contracts actually being signed in the marketplace?

Yes. Greg, I'll let Roddie answer that one as well.

Okay, sure. So just a little background. So since 2016, for 7 consecutive quarters, we've seen an increase in tendering. In fact, there a fourfold increase across that period of time. And what was interesting in that was it was primarily driven by the independents and the NOCs, and conspicuously absent were the super majors. So what we're beginning to see now in terms of the awards is all this stuff that was booked in 2017 was the independents and the NOCs. Now we're beginning to see the majors return with a bang. So certainly, the seasonality would dictate that a lot of people try to get the deals done towards the second half of last year, but that was primarily driven by the stability in the oil price and also got them in a position where they're really trying to get ready for executing the programs starting in '18. So they kind of -- the follow-on that we're going to see we expect is 2018 is going to have increased tendering activity and a lot more awards as well, perhaps not right at the beginning as everyone is digesting what they've just signed up for. But certainly, when budget season comes around in '18, looking into '19 and '20, we are seeing activity pick up in every single market sector. So that's very positive for us.

Okay, great. And then just -- I guess in your prepared remarks, you talked about the customers starting to look at multiyear contracts. Could you provide a little bit of color? Is this -- are there any specific regions where we should be thinking about that? And you mentioned the various types of customers. What types of customers are thinking about taking those multi-year contracts?

Thanks, Greg.

Okay. I think I'll take that one as well. So what we're beginning to see now is the focus on the Golden Triangle, so it's been a long time since we've discussed that. But for example, in Angola, we've got several tenders out right now for multiyear awards, and thereby, the majors. So that's very interesting. In Brazil, we just covered that there's lots of interest, especially for the majors in Brazil. And then Gulf of Mexico U.S. side is really beginning to pick up, and we're seeing some of the biggest players are now looking towards their new developments and what new equipment they need to bring to the market to make that a reality. So certainly the Golden Triangle, we're seeing all of that stuff there. But then we're also seeing things like -- there's the several multiyear tenders for the Australia and Asia region, which is, again, very encouraging. And you will have seen in the fixtures that the harsh environment market is already contracting multiyear high day rate tenders, so again encouraging across the board there.

Next, we'll go to Ian MacPherson with Simmons.

And yes, congratulations for backing up your optimism with some good action on the Fleet Status Report. Yes. Demand is clicking, but one thing that concerns me a little bit is we have seen quite a few reactivations. You've done a few, but most of your competitors have also done some as well. I mean, apart from the Spitsbergen, it seems like they're being done at uneconomic price levels right now with hopes of better economics to justify that capital. And I just wonder what you -- how you assess that supply threat, how many more uneconomic reactivations can the market absorb or tolerate without getting the cart in front of the horse with regard to a pricing recovery?

Yes. It's a fair question, Ian. So to date, all of our reactivations have been backed by contracts. Do those contracts support the capital investment for the reactivation? Usually not at this point in time, but we see follow-on work for those various reactivations. And so that's encouraging for us, as Roddie mentioned earlier. I think we're at a point in time now, especially as you're looking at the harsh environment sector, we think that the market is tightening to the point where we don't see the need for a reactivation without a contract that supports that reactivation. And so that's kind of our position there. And on the ultra-deepwater side, I mean, I can't see it us in the near term reactivating any rigs that aren't tied to a contract where we've got some pretty good visibility.

Okay. Another thing that interested me with the -- your fleet report was on the Songa backlog, there's a backwardation there to the rate structure. I assume that you inherited that, that you have renegotiated those contract terms in any way. But that's a little bit unusual, I guess. And I wonder if you can speak to that and speak to any other nuances or [core] variability with regard to those day rates that we should be aware of and modeling that long-term backlog.

Good morning, Ian. This is Mark. So you may recall back a few years, when Songa ordered these rigs, they were against contracts from Statoil. And the Songa organization was not as financially stable as they could have been. There were significant cost overruns with those construction contracts. As a result, they renegotiated the day rates with Statoil. So the starting day rates will increase by an average about $40,000 per day per contract. In return for that, Songa gave Statoil certain concessions with regard to the backwardation of the day rates and a concession with regard to any options that are exercised once the initial 8-year contracts are completed, so you will see that as well. And that's purely the commercial arrangement that was agreed to, honestly, about 3 years ago.

Okay. And there's no other -- there are no other mechanics in those day rates with regard to performance, bonus or any of that type of stuff?

No, there's not.

And next, we'll go to Haithum Nokta with Clarksons Platou Securities.

I want to ask on ultra-deepwater OpEx. Can you give an update on where we are today for that? And it seems like it's continued to march lower across the industry, and you highlighted some aspects that's driving yours, I think, uniquely lower. But -- and then kind of second to that as well, is there less regional variability in OpEx compared to the peak?

Yes. Good morning, Haithum. This is Mark. So you are right. We are of seeing costs reduce over the last 2, 2.5 years. However, I would say that we probably reached the -- a level right now where we don't expect to see significantly more cost reductions in 2018. As you know, we do not break out OpEx by rig -- by type of rig or by region, so I'm not going to go ahead with that part of the question at this stage. But certainly say that the fact that you've seen a reduction in local content requirements in certain jurisdictions would also lead you to believe that the variability has been reduced somewhat over the last couple of years.

Okay. And then a kind of a similar question. But obviously industry-wide, there's a lot fewer disclosed day rates and for various reasons, I think. And I'm wondering kind of in Transocean's assessment, how rampant has it been, if at all, that you've seen rates that are below cash operating costs for the driller? And do you think that that's something that continues for a meaningful period of time in 2018? Or kind of what's your views on that?

So let me take a stab at this, and Jeremy or Roddie can jump in. So we have an internal policy where we only announce the backlog of a contract if it exceeds $100 million. So in those cases, obviously longer-term contracts, you will see the day rate being published. Otherwise, we don't disclose the day rates associated with that. And if I reflect back over the last year or so, I don't think we've signed any contracts where we are losing cash at the drill bit. So every contract is cash flow positive. Roddie?

Yes. And I would add that there are maybe some folks out there that have done that for other reasons, but they're certainly not for profitability reasons. But I think what we're seeing just now is -- on a go-forward basis, there is just a building sentiment. When we're looking at the operators announcing maintaining and increasing dividends, there's less of a desire for us to operate at that cash breakeven level. And I think as you see the activity returning, which, of course, drives utilization, which drives day rates, we're going to see things lifting off of that kind of level across the board. And I would think we're able to secure better, more attractive contracts that run for a bit longer term.

And just a final piece of that, I think you used the term rampant. It's certainly not rampant. We've seen one-offs here and there, where we suspect or have been informed that some of our competitors have gone below cash breakeven, but it's not -- it's certainly not rampant.

And next, we'll go to Waqar Syed with Goldman Sachs.

As we look forward in the next 3 to 5 years' time frame and assume some of your stacked rigs are being reactivated, you have rigs that were stacked back in '15, in '16, '17, '18. Should we look in reverse order and see the ones that have been recently stacked that they will be the first ones to come back in, and those that were stacked in '15 may be the last ones to be reactivated or maybe even retired?

I would say not necessarily, but go ahead, Roddie.

Yes. I'd probably say -- so that's not a bad analogy. I would say the technical reason behind that is that the way that it typically happened was that the more capable assets were the last ones to be stacked. So the more capable assets will typically be the ones that are most in demand in the beginning, so they will probably go back first. So because of that reason, you might see that, but it's certainly not a given. In fact, when you look at unique technical capabilities of rigs, there are several rigs that would probably come back after a longer period of stack, just because they have attributes to certain markets that are very attractive in terms of operations.

So what's the value proposition that you think that your fifth-generation deepwater rigs have that was kind of a stacked in '15? Is there any unique things that they offer that the newer sixth-, seventh-generation rigs don't have?

Well -- so if you look at some of the fifth gens, there's fifth gens and then there's fifth gens. So the ones that we're looking at eventually bringing back were the dual-activity ships that essentially had very large derricks, full dual activity, but there's room to upgrade those rigs. They're good hauls. They're very good ship systems, and their topside packages can get upgrades when the environment supports that. And what we think happens in the long term here is the activity gets driven, such that all of the high-spec units that are currently available will get booked in the next year or 2. And then from that point forward, you're then looking at bringing back some of the older ones. So the reason we still have those rigs in our fleets is because they start on a very good basis of being largest placement ships with full dual activity. And by that time, we believe we'll be able to support any upgrades and reactivations through the contracts that are going to be won.

And Waqar, this is Mark. Just note that if you recall back, we spent about $7 million to $8 million per rig in cold stacking these units. So we've taken great care in preserving all the key equipment with the full intention of reactivating these rigs quickly and cheaply on the back end. So if you look at a pure economical analysis, we are looking at adding 5 rigs in '18 or '19 or '20. It was a lot cheaper for us to reactivate these rigs, upgrade these rigs as compared to buying rigs, either from the shipyards or buying companies and paying the price that you would pay for those rigs. So for us, this is a very cheap way for us to scale up as the market recovers.

Sure. And then for any of your semisubmersibles, are you thinking of -- or are they capable of being conventionally [moored as well] and making some upgrades to make them capable for that configuration as well?

Yes. So all of our -- what we call our modern semisubs actually have DP and mooring [built] into them. So we have that capability already. On some of the older semisubs that we've kept, things like the Polar Pioneer. So in her environment that she would operate in, she would not need to be full DP. But those rigs kind of have, what we call, thrust to [assist] in terms of positioning and those kind of things. But again, the Polar Pioneer is a great example of a rig that would come to market when the economics of the program fully support a funding reactivation and upgrade.

And next, we'll go to Taylor Zurcher with Tudor, Pickering and Holt.

We'll move on to Colin Davies with Bernstein.

It's very encouraging to see some more talk about some longer-term tenders coming in. I wonder if you can gave some color, though, around the structure we might start to see evolve around those longer-term opportunities. When might we start to see some decent inflators coming into the contracts or in the [rounds] some of the option structures? Is that a 2019 event? Or is it beyond that to get to the more structural sort of upward pressure on longer-term rates?

I'll take that one, Colin. So we can use harsh environment as a little bit of a parallel here. So the space in which we went from day rates that are cash breakeven or there around to day rates that are now well in the 3s was really a 6-month period. Now that's fairly acute because it's a smaller market, but you asked about the structure of the thing. So you're kind of looking at stuff like let's say the day rate might be roundabout $300,000 for one of those rigs at the moment, but the bonus scheme will push it well into the mid-3s. And I think you're probably about to see a couple of things getting announced where the base rate is in the mid-3s and the bonus structure will push it even higher. In terms of the structure for ultra-deepwater, the one thing I'll draw your attention to is, over the past kind of decade, there was 5-year period there that reserve replacement ratios were above 100% and then they just plummeted, so all the way down to 36% reserve replacement ratio in '16 and a 32% ratio in '17. So clearly, there is a tremendous amount of work that needs to be done to bring reserves back up to where they should be offshore. And just to give you a size of the price, of the $100 million --100 million barrels per day production that we're currently seeing, 25% of it is offshore. Only 7% is shale. So we just think there's tremendous movement there. So I think what happens in terms of the structure of the contracts is as these higher-spec units start to get booked, you're going to see more and more incentive-based contracts because that helps to align our goals of higher day rates with the customers' goals of very economic development. And then as supply tightens, then I think we'll start to see a push on base rates as well. So I think at first, you're going to see more incentive-based contracts and then general day rates will simply push up. And I think that the incentive stuff is here to stay because it's a structural improvement to the industry to align efficiency with reward.

Do you think that's 2019 plus in the ultra-deepwater market? Or is it beyond that?

I think what you'll see -- and this is purely a guess, but we did see in the harsh environment sector, especially for the high-specification assets, our customers in the ultra-deepwater market, because of the current conditions, have had a taste. They've been able to demand any rig that they wanted, so they've gone with the higher-spec assets, and they've now had a taste of the efficiency. So I think what you could see is a fairly quick inflection point in pricing in day rate most like we saw in harsh environment for the higher-specification assets. And so is it realistic to think that could occur later this year? Maybe, but probably not. It's probably more of a '19 event.

Okay. That's what I getting at. And then just -- with the sentiment getting a little bit stronger, how should we think about scrap -- ongoing scrapping decisions? You mentioned earlier, for example, that some of the older cold-stacked rigs may stay there in certain situations. Would you generally start to see the scrap rate or scrap pace come down across the industry?

It's a good question. I think it's going to be different for every offshore driller. I mean for us, we've been very aggressive. 39 floaters to date over the course of the last 3 years. We continue to evaluate our fleet on a very regular basis. And primarily for us, it's a function of looking at the market and where we think the market is going. And we constantly assess what we think it's going to cost to reactivate these assets. And so as the reactivation cost increases and starts to look a little uneconomic and we may have some questions about the market, we may make the decision down the road to retire more assets. At this point in time, we're comfortable with where we are, not sure about the rest of our peers. We agree that there are more assets that need to come out of the market, but we don't get to make those decisions.

Next, we'll go to Sean Meakim with JPMorgan.

Jeremy, just a follow-up on Brazil a little bit, maybe just the recent IOC investments. Just curious how you think the competitive dynamics could change there in that market relative to the prior cycle now that you have new customers coming in, but also maybe from a competing for rigs in that market and just maybe shifts in preference or different type -- certain types of specs or assets, just thinking how that market can evolve here and the changes here?

Yes. I think in Brazil, Petrobras has a very specific technical specification that they've adhered to over the years and something that they've like. But now that you're inviting other players in that market, they're going to bring their own taste and preferences. And so what we've traditionally seen with most of the IOCs that they want the highest specification assets, so where we think there could be more demand for the dual activity, high-end ultra-deepwater assets. And Roddie, I don't know if you want to add anything.

Yes. No. Absolutely. I think that's exactly where this goes. And I think what's interesting about that is the efficiency is driving the day at the moment. And in terms of dual activity, you may or may not know that Transocean has a patent in Brazil that we are the only ones that can drill dual activity there without someone having to pay a royalty. So we feel positive about our chances there, not only because of the patent, but because we've got a tremendous operating history there, and we've been there for a long time. So it's right in our wheelhouse as I would say.

And can you see -- can cost structure change given it's been a somewhat challenging labor market over the years. How could that change if the market has been more opened up to new customers?

Yes. I think actually -- go ahead, Mark.

I think we're a long away from seeing cost inflation in ultra-deepwater drilling at this stage. Given where we are utilization-wise, we've got, I'd say, at least a 2-year runway before we start discussing increases in costs.

I was thinking about relative to the prior cycle just how the labor market dynamics could be different or how anything else, on the cost side, could be different relative to when it was a one-customer market.

Well, they've definitely taken steps down there to kind of improve the ease of doing business, if you will, these costs with changes in tax reform and some of the ways that they're conducting business down there and then bringing in other players who will take an entirely different approach to what Petrobras does. So you have a potential there to have perhaps a more efficient operation, but that remains to be seen at this point time, Sean.

That's all very clear. And just one last quick one, if I could. You mentioned in the prepared comments that Gulf of Mexico independents, some opportunity there. Can you maybe give us a few more parameters around types of programs or tender opportunities that you're seeing in the market?

Yes. I wouldn't disclose all the tenders that we are bidding on for obvious reasons, but certainly the ones that we've announced so -- going to work for Murphy. We already worked for BHP and the several others that are in the market at the moment. But typically, how this works is that those guys are looking to explore and prove things up and then kind of pave the way for the majors to come in. But I think actually the growth you're going to see in the Gulf of Mexico, going forward, is going to be the majors returning. You saw that Total has bought up several properties in this partner and several things in there, so I think we see a shift now. I think the independents helped to fill the gap during the difficult times, and now we see the majors returning as they have to address this reserve replacement issue.

And that does conclude today's question-and-answer session. And I'd like to turn the call back over to Brad Alexander for any additional comments or closing remarks.

Thank you, David, and thank you to everyone for your participation on today's call. If you have any further questions, please feel free to contact me. We look forward to speaking with all of you again when we report our first quarter 2018 results. Have a good day.

And that does conclude today's conference. We thank you for your participation. You may now disconnect.