Transocean Ltd (RIG) 2018 Q1 法說會逐字稿

Good day, and welcome to the First Quarter 2018 Transocean Earnings Conference Call. Today's conference is being recorded.

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

Thank you, Christina. Good morning, and welcome to Transocean's First Quarter 2018 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.

And now, I'll turn the call over to Jeremy.

Thank you, Brad, and a warm welcome to our employees, customers, investors and analysts participating in today's call. As reported in yesterday's earnings release, for the first quarter, the company generated adjusted normalized EBITDA of $170 million on $645 million in adjusted normalized revenue. These results were driven by a combination of strong uptime performance and a continued focus on organizational and operational efficiency.

Operationally, when normalizing for the downtime associated with safely returning the Petrobras 10000 back to work, we delivered first quarter revenue efficiency in excess of 96%. Of note, we achieved this high level of performance despite the fact that we've added 6 new rigs to our active fleet over the last 2 quarters. I'd like to take this opportunity to thank the entire Transocean team for your continued focus and effort in delivering another solid quarter.

In addition to delivering strong quarterly operating results, on January 30, we officially closed the acquisition of Songa Offshore. We are extremely pleased to welcome the former Songa team into the Transocean family. In addition to the expertise, skill and experience our new colleagues will contribute to the combined company, this transaction is important for a number of reasons. First and foremost, the Cat-D rigs represent 4 of the highest specification harsh environment assets in the world and support our fleet strategy of owning and operating the largest and most technically capable floater fleet in the industry.

Secondly, as of April, these 4 rigs carried a total backlog of approximately $3.6 billion, bringing Transocean's total backlog to $12.5 billion, more than 3x the level of our nearest competitor. Importantly, we believe that there will be opportunity to add to this backlog as the Cat-D rigs were designed in close collaboration with Statoil. And each of the 4 rigs has 12-year options. And given the performance of the Cat-D rig to date, with the Equinox recently being ranked as the top performing floater in Statoil's Norwegian fleet, we were encouraged by the prospect of Statoil ultimately exercising these options.

Finally, we are pleased to be realizing the synergies that are only made possible via consolidation. Administratively, because we designed a robust plan prior to closing, we have already made significant progress in integrating and consolidating local offices, yards, warehouses and IT systems. Operationally, we're in the process of introducing legacy Songa personnel to Transocean's HSE and overall management systems. We are also identifying and aligning around best practices from both organizations for managing maintenance and the supply chain.

Additionally, we have migrated Songa Offshore to our insurance program and we're in the process of extending the coverage of our OEM agreement to the 4 Cat-D rigs. The combination of these 2 actions alone will result in millions of dollars in annualized savings. It's important to note that these statements could not have been realized by Songa as a stand-alone entity, that their scale is not sufficient to warrant the favorable terms that we have negotiated with our key supply partners and service providers.

Based on what we've seen and accomplished to date, we have full confidence that by the end of 2018, we will achieve, at a minimum, the $40 million of annualized cost and operational synergies initially expected, clearly demonstrating the incremental value that we can deliver through consolidation.

As we progress through 2018, we will continue to evaluate acquisition targets with characteristics similar to what we found in Songa, including high specification assets that will strengthen our fleet and some balance of backlog and maturity that will not significantly impact our near-term liquidity.

Speaking of strengthening our fleet. In February, the fourth of our high-specification ultra-deepwater drillships contracted to Shell for 10 years, the Deepwater Poseidon, commenced operations in the Gulf of Mexico. And I'm pleased to report that during her first 2.5 months of operations, she had delivered an impressive 99% uptime. We are obviously extremely proud of Poseidon as well as the performance of the other newbuild drillships, and they demonstrate that we truly have applied best practices to ensure these rigs are reliable from day 1.

With the addition of the Poseidon, the rigs from Songa and including our 2 state-of-the-art 3 million pound hook load drillships under construction at Jurong, we will have 49 floaters in our fleet, of which, over 80% are categorized as either ultra-deepwater or harsh environment.

As we move through 2018, we will continue to evaluate our fleet, potentially acquiring high-specification assets, recycling some of our existing assets we think are no longer competitive or economically viable and upgrading assets to meet customer demand where the economics of the investment justify the enhancement.

Transitioning from our fleet to some of our first quarter wins. In addition to the approximately $3.6 billion in backlog associated with Songa Offshore, in the first quarter, we added 8 fixtures, including a 6-month extension with Husky on Henry Goodrich worth an additional $50 million in backlog. In addition to a solid base day rate, the extension provides for additional upside via performance bonus, again demonstrating the strengthening of a global harsh environment market.

As you may recall, we reactivated the Goodrich in 2016 after receiving a contract from Husky. Since commencing operations, the rig has delivered uptime of 98% working in the harsh environment conditions in Eastern Canada and has generated cash flow of more than $100 million, which significantly exceeds our reactivation and mobilization costs. The Goodrich was the first of what is now 5 reactivations we have completed and represents from a performance standpoint where our customers can and do expect when they contract any of our rigs.

In addition to securing the extension on the Goodrich, we are also pleased to have secured additional work for the Deepwater Asgard in the Gulf of Mexico. As you well know, the Asgard is one of the most technically capable ultra-deepwater rigs in the world, therefore, capitalizing on short-term opportunities to keep her working is important as we await better-priced fixtures.

Across the Atlantic, off the Ivory Coast, we are returning the recently upgraded Discoverer India to work for CNR to commence a 5-well project. As we routinely evaluate our assets, we consider the impact effort to provide to the long-term competitiveness of our fleet. In the case of the India, we invested approximately $15 million into enhancements, which elevated her technical ranking into the top 50 ultra-deepwater assets in the world. We believe this is an efficient use of capital and strengthens our position for the eventual ultra-deepwater market recovery.

During the quarter, we also secured another extension with Statoil for the Transocean Spitsbergen, a true testament to the outstanding performance of the assets, the crew and the shore-based support team. Moving farther to the east, in Malaysia, we were also pleased to see Shell pick up 2 additional options on the Deepwater Nautilus, and we are optimistic about future prospects for her in the region.

And finally, in April, the DD1 returned to operations, commencing work for Quadrant in offshore Australia. As we've previously discussed, we have long believed that the DD1 is best suited for the Australian market, where she would instantly become the most technically capable asset in the region. Given the Quadrant work and the visibility to numerous potential follow-on opportunities in the Australian market, we made the decision last year to reactivate the previously cold-stacked rig. So far, we are pleased with the decision as we recently signed an additional 1-well contract to the DD1 with PTTEP and are currently bidding the rig into other projects commencing in 2019.

On a go-forward basis, we will continue to thoughtfully and prudently evaluate our reactivation opportunities, considering both near-term demand and follow-on opportunities that provide sufficient cash flow to justify each rig reactivation.

Looking at the macro environment. Oil prices have remained solidly in the 60s since the fourth quarter of last year, with Brent exceeding $70 per barrel since the beginning of April. Needless to say, these higher and more stable prices enable our customers to generate sufficient operating cash flow to fund near-term dividend and debt requirements while also pursuing longer cycle investments.

Despite the longer-dated oil price curve remaining below current spot prices, multiple factors provide optimism that longer-term oil prices will remain at or above the $60 level. For one, OPEC has maintained compliance with the supply cuts they first announced in the fall of 2016. Additionally, reserve replacement ratios are at 20-year lows, and delays in final investment decisions by operators over the past 4 years are expected to remove approximately 6 million barrels per day from the 2025 supply with the initial decline starting no later than 2020.

With this supply dynamic playing out, combined with current offshore breakeven economics for most projects at levels ranging from the 40s to as low as the low 20s, it's not surprising to see increasing customer interest in offshore developments. In fact, if oil prices can remain constructive for the next few months, we believe that operator budgets for 2019 could reflect a return to offshore project sanctioning for 2019 and beyond as the deepwater space is becoming a more compelling investment proposition for our customers.

In the harsh environment market, opportunities in Norway, the U.K. and Canada remain strong. We continue to see day rates strengthening for high specification assets with customers more frequently seeking to sign multi-year fixtures with base day rates now approaching, if not exceeding, $300,000 per day. And many of these fixtures, like the Henry Goodrich, include additional upside linked to performance incentives.

In ultra-deepwater, the increasing level of interest throughout the Golden Triangle is encouraging. In Mexico, there are a handful of opportunities, which could materialize into deepwater drillship contracts before year-end. In fact, we would not be surprised to see some deepwater activity commencing in Mexico later this year and steadily increasing through 2019 and into 2020.

In Brazil, the recent lease sales are reflective of the significant interest integrated oil companies have in these basins. If IOCs contract rigs to drill their respective prospects and Petrobras goes through the tendering process to replace the rigs rolling off contracts in the coming quarters, we expect to see a reversal in the declining rig counts in this area that have occurred over the last 4 years. In fact, we believe in the next couple of years, we could see deepwater rig activity in Brazil again exceeding 40 floaters. We also believe that the presence of IOCs in the region could ultimately drive the push towards higher specification assets and establish drilling contractors, which will certainly bode well for Transocean.

In West Africa, we have visibility in several new opportunities in a handful of countries. As confidence in the oil price continues to increase, we expect longer duration of opportunities in the region to become more numerous and ultimately drive additional demand for our assets and services. We are further encouraged by the recent customer interest in projects considered to be frontier drilling, with multiple customers exploring projects in deeper water depths beyond 12,000 feet and high-pressure fields requiring 20k BOPs. This points to an industry that's focusing on the future and to new sources of hydrocarbons beyond what is accessible today.

As the harsh environment market continues its recovery and optimism for an ultra-deepwater market recovery grows, we recognize that our operational performance is essential to our continued success. As such, we will continue with our unwavering focus on safety, equipment reliability, drilling efficiency and cost control. We've made considerable progress in all 4 areas over the past 3 years, and we have been repeatedly recognized by our customers for our market leadership.

From a safety perspective, while we are continuing to refine our policies, procedures and training programs, we recognize that we need engineered solutions to prevent injuries. As such, we are reassessing all potential hazards on our rigs and actively exploring opportunities for their physical removal. We are also evaluating technologies from other industries that we can leverage to move closer to our goal of an incident-free workplace.

Regarding equipment reliability, in addition to our OEM health care agreements, which have dramatically improved the alignment between Transocean and our primary equipment providers, we have recently designed a BOP health monitoring tool, which enables to forecast the future operating state of the BOP based on predictive analytics, which compares current operating conditions versus an ideal model.

From a drilling-efficiency perspective, our performance dashboards have successfully raised visibility and awareness across our organization, which has driven material performance improvements. The dashboards have also highlighted inconsistent performance from rig to rig and even from crew to crew. As such, we are now introducing a machine analytics tool across our fleet to monitor the movement of equipment to better understand the specific reasons for the inconsistencies and to quickly share best practices across the fleet.

And finally, from a cost perspective. We continue to evaluate opportunities for streamlining our organization and our operations to make offshore drilling more economically viable.

Before turning the call over to Mark, I would just like to reemphasize our continued priorities. We will continue to proactively manage our balance sheet to provide us the necessary liquidity to invest in our business, while simultaneously providing us the optionality to be opportunistic. We will continue to explore and pursue opportunities that further enhance the capability and overall quality of our fleet. We will continue to acutely focus on operational and organizational efficiency to reduce the time and cost required for our customers to construct wells while also enhancing our earnings. And most importantly, we will never lose sight of our objective of maintaining a safe, incident-free workplace all the time, everywhere. Mark?

Thank you, Jeremy, and good day to all. During today's call, I will recap our first quarter results, provide updated second quarter and full year 2018 guidance, and update our liquidity forecast through 2019.

For the first quarter of 2018, we reported a net loss attributable to controlling interest of $210 million, $0.48 per diluted share. Highlights for the quarter include: 2 months of operations on the 4 Cat-D harsh environment semisubmersibles acquired as part of the Songa acquisition; 48 days of operations from the newbuild Deepwater Poseidon, which commenced operations in the U.S. Gulf of Mexico in February 12; and a full quarter of activity for the newbuild Deepwater Pontus, which commenced operations in the fourth quarter of 2017.

Let me now address 2 revenue-related items in more detail. Firstly, in related to the Songa acquisition, pursuant to purchase price accounting rules, we've calculated the fair value of 4 Cat-D drilling contracts by comparing them to current market day rates and expectation of future market day rates during the term of these contracts. The difference being recorded is contract intangible assets. The contract intangible assets associated with the Songa totaled $232 million at closing, and will be amortized over the remaining term of the drilling contracts on a straight-line basis.

Accordingly, in the first quarter of 2018, we recorded a noncash reduction in contract drilling revenues of $19 million. This amount is included in contract drilling revenues on a consolidated statement of operations and presented on a separate line on the statement of cash flows. A schedule detailing the expected quarterly contract intangible amortization is now available on our website.

Secondly, we adopted ASC 606, the new revenue accounting standard, effective January 1, 2018. As a result of this adoption, we have determined that drilling and related services we perform represent a single performance obligation and hence, all revenues, including reimbursable revenues, are reported as a single line on a consolidated statement of operations. For this adoption, reimbursables will now be recognized when accrued as opposed to when bought. Please see our first quarter Form 10-Q for additional information.

For the first quarter, reimbursable revenues were $26 million, compared with $15 million in the previous quarter. The increase was mainly related to the adoption of the aforementioned revenue standard. Likewise, reimbursable costs associated with the aforementioned reimbursable revenue will be included in operating and maintenance expense. Please note that these additional costs were not included in my prior guidance.

Moving on, cash flow from operations totaled $103 million compared with $244 million in the prior quarter. The decrease was mostly due to the receipt in the prior quarter of the early termination payment related to the Discoverer Clear Leader.

Capital expenditures in the first quarter were $53 million and were mostly attributable to a final cost associated with the delivery of the Deepwater Poseidon, whose 10-year contract will show. Including the effect of $57 million of net cash acquired to settle our Songa acquisition obligations, cash and short-term investments were $2.9 billion. At the end of the quarter, we have total liquidity at $5.9 billion, including our $3 billion undrawn revolving credit facility. Renewing or extending our revolving credit facility remains a priority, and we expect to complete this 2018. We also anticipate refinancing the secured debt associated with all 4 of the Songa Cat-D rigs with the completion occurring this summer.

Let me now provide an update to our 2018 financial expectations. For the second quarter of 2018, we expect our contract drilling revenues to increase approximately 14% sequentially. This forecast includes both early termination revenue related to the Discoverer Clear Leader and -- of $38 million and the amortization of the Songa contract intangibles of $29 million and with revenue efficiency forecasted to average 95% during the quarter. This forecast also includes an estimated $13 million in customer reimbursables.

We expect second quarter O&M expense of approximately $445 million. This includes a full quarter of the Cat-D rigs and the cost associated with reimbursable revenues. The second quarter will also include a full quarter of the Deepwater Poseidon operations. We expect G&A expense for second quarter to be approximately $42 million. Net interest expense for the second quarter is expected to be approximately $150 million. This includes capitalized interest of approximately $9 million and interest income of $10 million. Capital expenditures, including capitalized interest for the second quarter, are anticipated to be approximately $55 million.

Turning now to our full year 2018 expectations. Contract drilling revenues for the year are expected to include customer reimbursables and revenue associated with the early termination of the Discoverer Clear Leader. Our full year operating maintenance and -- operating and maintenance expense expectation has increased to the top end of my previous range of $1.55 billion to $1.65 billion, primarily due to now including reimbursable costs related to the adoption of ASC 606 and an O&M forecast, which excludes any costs for respective reactivations.

We expect our G&A expense 2018 to be approximately $170 million. Full year 2018 depreciation expense is expected to be approximately $840 million. Net interest expense is expected be approximately $575 million. The estimate includes capitalized interest of approximately $40 million and interest income of $40 million.

Our 2018 cash taxes are expected to be approximately $90 million. This estimate includes the impact of BEAT taxes associated with the 2017 U.S. tax reform and Jobs Act. However, we continue to assess and analyze the portion of the act related to transition taxes. Capital expenditures in 2018 are anticipated to be approximately $175 million. This includes $77 million in newbuild CapEx with the remainder targeted for maintenance CapEx.

Turning now to an update on our projected liquidity as of December 31, 2019. An exclusive of a new extended revolving credit facility or any additional secured debt issuances, our end-of-year 2019 liquidity is estimated to range between $2.2 billion and $2.4 billion. In 2019, we expect total CapEx to be approximately $200 million. This includes $97 million on the remaining 2 newbuild drillships at Jurong and $103 million for maintenance CapEx. I would note that both 2018 and 2019 CapEx guidance exclude any speculative rig reactivations.

In conclusion, we continue to generate robust cash flow as a result of our fleet's strong revenue efficiency and prudent management of our cost structure. We also remain very pleased with our balance sheet, especially our debt maturity profile with no significant debt due until 2023. And liquidity position would provide the optionality to continue to selectively hydrate the quality of our fleet. With our industry-leading contract backlog of $12.5 billion, we expect to continue generating strong cash flow as market utilization and day rates recover.

And I'll turn the call back over to Brad.

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

(Operator Instructions) We'll take our first question from James West with Evercore ISI.

Jeremy, the -- clearly, the harsh environment market has picked up nicely and tightened nicely. Do you have any thoughts on the true seventh-gen market? I mean, those really high-spec, high-end rigs, the 36 or so that are out there -- or really 26, I guess, what's in the shipyard, on when that market may see a tightening? It seems to me there's a number of large oil companies looking for that specific rig right now with very few uncontracted that are available for work today.

Yes. No, that's exactly right. I'll let Roddie handle that one.

Hey, James. Okay, so to kind of give you a picture of that you're spot on that the high-spec rigs are in high demand there in the ultra-deepwater sites. So we're seeing several programs. In fact, we're just going through our numbers here, but there's a -- there's been a doubling of project sanctioning from last year to this year and there's a projected doubling again into '19. So what we're beginning to see now is a lot of them -- a lot of push to bring those better rigs back to the market. And actually, the other thing I was going to mention in this realm is, looking at utilization, we look at effective utilization. So the actual supply of good floaters is really only somewhere in the region of kind of 160-or-so rigs. And with a 120 of them working today, we're -- our utilization is already in the mid-70s. And just with a little bit of uptick that we're all projecting -- and in fact, we were at Clarksons yesterday. They're showing a nice uptick plan for '19. What utilization should be in '19, well into the 80s and approaching the 90 mark. So the answer is yes, those big rigs with the nice specifications are going to go pretty soon.

Well, and we hope that they really follow what they did with the harsh environment space.

Got you. Okay, that's great to hear. And then, are -- as you assess your fleet further, Roddie or Jeremy or Mark, do you still have rigs that are candidates for retirement at this point or is that primarily done?

No, we still have a few rigs that are candidates for retirement. Some of them may currently be on contracts, and so certainly not going to recycle them while they're generating revenue and cash here for us. But yes, we are continuing to assess the fleet. And as we learn more about the direction of the industry and the eventual market recovery and continue to update our reactivation models what that cost looks like, we'll continue to take action as needed.

We'll take our next question from Angie Sedita with UBS.

So Jeremy, maybe you can talk a little bit about your commentary on M&A and individual assets that you had in your prepared remarks. Maybe on the M&A side, you mentioned, right, a focus on high-spec assets with backlog. Are there companies out there that meet those specs, that offer both high-spec assets in the backlog? And then two, on the individual assets, maybe a little bit of criteria there as far as specs, timing? And would you need to have a contract in hand before acting on a transaction?

,

Yes, good question, Angie. And the pickings are slim, and that's why you haven't seen more transactions in the space. There are certainly candidates out there that we feel have the right mix of asset quality and have some kind of combination of backlog to offset near-dated maturities, but they're few and far between. So we are certainly looking and trying to progress those discussions, but it is a challenge. With respect to individual assets, given what we've seen in the harsh environment space, with not only utilization picking up to the high-spec rigs but followed by day rates, which have more than doubled over the last 2 months, if we were going to go out and acquire individual assets, you'd probably see us more inclined to look at the harsh environment space than the ultra-deepwater space at this point. But we're certainly encouraged by what we're seeing in ultra-deepwater as well.

All right. Okay. That's helpful. And then on the comments on Mexico, potentially some opportunities later this year. Any thoughts there on how many rigs we could be moving into Mexico, either late this year or 2009 ( sic ) [2019] and the specs they're looking for in short-term or longer-term work?

Yes. Angie, I'll take that one. Certainly, the excitement around Mexico is just palpable amongst the customers. Where our sales, just Transocean's fleet, looking at our opportunities that are right in front of us, by mid-'19, we could have up to 4 rigs, maybe even more in Mexico. The overall industry as a whole, you've got to extrapolate that out and say they're going to be perhaps in the teens in terms of number of rigs. But as we said in the previous call, moving into Mexico with a couple of our existing customers that have rigs under contract is a great segue to get in there. But now we're seeing that it's a very real possibility that we're going to move in on several new contracts as well. So we're very encouraged by that.

And regarding your question around the spec, it would be the exact same spec that you'd see in the U.S. side of the Gulf of Mexico. So you're looking for dual activity, high upload, 2 BOPs. Yes, highly efficient rigs.

Okay. Okay, great. And then, those are shorter-term contracts or longer or mixed?

It's a mix. It's kind of all over the place. It's primarily exploration work, right? But there's a mix of just 1 or 2 wells, but then there's also programs that will be a year or longer.

We'll take our next question from Blake Hancock with Howard Weil.

Jeremy, maybe first as we think about the cold-stacked assets and you talked about the Goodrich and the ability to generate cash flow, exceeding the reactivation costs. You've kind of laid out what you think reactivation would be on some of these other rigs. Can you maybe talk about the criteria, what you would expect? Would you expect a payback on kind of your reactivation on the first contract? Peers out there are doing the same thing, but not getting paid back on that first deal. So maybe you could talk about the strategy there as you think about the improvement environment.

Yes. And I mean, candidly, in the current market, it's tough to get payback on that first contract. So as we assess whether or not we want to reactivate a rig, we want to see not only the first contract, and of course, get as much as we possibly can as far as that contract, but then what are the follow-on opportunities? And so far as we've looked at that, we've seen several follow-on opportunities that any -- one of say, 3, could materialize. And that's what gave us the confidence to go forward with reactivations. So there's not an exact science to it. I can assure you that Mark pushes back pretty hard on us as he should whenever Roddie comes up with new opportunities to reactivate rigs. But so far, we -- I think the process has worked well for us. We've been rewarded with every rig that we have reactivated to give us follow-on work and so we're going to continue to follow that process.

Yes. Blake, I'd also add in there that those strategic assets that we think are going to be very strong players in the future helps in the decision-making. But we also look at some of the older rigs as well that are fit for purpose for the right markets. And as we saw with the Goodrich, that worked extremely well. So that's an older vintage asset pulling down some really nice numbers, and we're currently engaged in a couple of other things that we'll let you know about once they're committed. But that would reactivate rigs again that are a little bit older, but with very solid financials to not only pay for the reactivations but move those rigs into a good profitable space in the first contract.

That's great. And then part Jeremy, part Roddie here. Jeremy, on the Asgard, can you give us an update? You kind of talked about waiting -- holding out here for pricing. What do you think is acceptable if we were to term out that rig? And Roddie, update on the contracting potentials for the Asgard and maybe the DD3?

Yes, I'll just start, and then turn over to Roddie. If you'd had asked us this question a year, 18 months ago, we probably would have been inclined to lock up a rig like the Asgard for 12 to even 24 months. But then, if you think beyond that, we want to have some kind of market-driven fluctuation increase in day rate to give some optionality in the outer years and some upside. Today, I think given what we're seeing, we'd be less inclined to go that kind of duration, probably more inclined to look at something no longer than 12 months before we would start to get some day rate appreciation. And so I think that's kind of how we're thinking about rigs like the Asgard right now, and then I'll let Roddie elaborate.

Yes, that's spot on. So the Asgard is arguably, one of the very best available rigs in the market today. And we are pursuing short-term activity for her until we see that window where we can really push the rate on her, but she is extremely capable. And you also asked about the DD3. So we think about the DD3 in a similar fashion. Very interested in putting her in the right spot where she has that unique DP (inaudible) capability and she's a dual-activity rig. So finding the right job for that, we're cautiously optimistic we'll have something to tell you about pretty soon on her.

We'll take our next question from Haithum Nokta with Clarksons Platou Securities .

Roddie, I wanted to follow up on the comments about the high-spec ultra-deepwater market tightening. And do you see that as, I guess, sustainable even if rates start to rise in that segment? Do operators just say, "All right, I can work with, call it, single activity or I can go without dual BOP." Is that something that you see that could actually be a risk to that outlook?

I'll tell you what we see. The operators, how would you say, are not opposed to paying more money for the rigs. But what they're really opposed to is paying money for the wells. So with the efficiency that we're delivering on these high-spec assets, even with the higher day rate, they're still getting a tremendously lower cost of ownership for the wells, better than it's ever been, actually. So we just think that, that will be a sustainable environment. And I think we will be able to see some, how would you say, appropriate day rates coming out in 2019.

That's good to hear. And then I wanted to ask about the Spitsbergen extension that you had announced in your recent Fleet Status Report, that you also had basically a shorter-firm duration of the contract, and I assume that's basically performance-driven. And I guess, are you guys able to positively benefit from that shorter duration in the contract structure? Or kind of how should we think about improved efficiency from a financial perspective?

Yes, you're spot on. It's -- the rig is just drilling like crazy. She's doing a fantastic job in knocking out these wells for Statoil. So what -- in that contract, we have a series of options before the next big firm term period. So Statoil was picking up those options as we go. They've got several partners that are interested in it. And of course, the performance of the rig speaks for itself. In terms of upside for us, that rig is on a performance bonus contract. So the better we drill, the more upside there is for us. So our compensation is linked to our performance.

And that's the one that you're trying to add to more areas of the fleet at this time? A performance-driven (inaudible)

Yes, we believe that's a very positive business model for our entire industry actually. We view ourselves as competing against other places where operators can spend their capital. So making ultra-deepwater as competitive as you possibly can and making harsh environment competitive is what we're all about. So we do welcome that because our operations teams around the world are the very best in the world and they're delivering a fantastic performance. So it kind of gives the operators the opportunity to pick up a rig on a pretty reasonable headline rate, but also be able to pay for a significant performance that gives us a per-day higher margin on those rigs. So it's kind of a win-win situation. And the answer is yes, the customers are very interested in that performance alignment.

(Operator Instructions) We'll take our next question from Ian MacPherson with Simmons.

I guess, my -- the first question will be back to the M&A strategy. If things are really so close to tightening, it sounds like they could be, I don't know if you want to be careful with your contract length, but you also want to be careful with your use of equity. And as terrific as Songa has been in every way, it was a very equity-intensive transaction for you. So Jeremy, what would be your attitude towards the use of equity in future M&A given how close it feels that we may be to recovery and a $12 stock price for Transocean today?

Ian, that's a great question because you're right, we look at this pretty carefully. And when the Songa transaction was negotiated last August, we announced that it was negotiated over the previous several months. If you recall, at that time, the harsh environment had barely moved. And clearly, the industry was not experiencing the level of optimism we're seeing today. So shoring up a balance sheet by over-equitizing a transaction was certainly the right way to go. I think we are in a different place now. And I do think that we expect ultra-deepwater to follow harsh environment over the next few quarters. So as we look at opportunities. We get a little more comfortable with our balance sheet and our -- especially our level of liquidity. We'll be more inclined to use cash or a bigger mix of cash in a corporate transaction. Obviously, in an asset transaction, that would be cash only. So we certainly do reflect your views on this.

Okay. Mark, I have another question also for you and I wanted to clarify the revenue guidance for Q2. If we go up 14% sequentially, that's $757 million. You said that includes terminations, intangibles and reimbursables. So if we added back the intangibles, would it therefore be tax revenue of, what it is, I guess, $786 million? Is that what we should be thinking about?

Yes, that's the calculation, Ian. That's correct, yes. The fact that we have been -- have not been disclosing day rates on our Fleet Status Reports, we thought of starting to give you some guidance on revenue on the call. It would make it a little easier for you to get closer to the revenue for the quarter. So that's what we're trying to achieve with that.

We'll take our last question from Colin Davies with Bernstein.

I wonder if you could give us some -- a little bit more color on the nature of the performance benefits that you talked about. I mean, it sounds like that could become the precursor to gaining some pricing traction in the market. But how significant are we talking about in terms of sort of an uplift from the headline rates you were mentioning? I mean, we -- are we talking tens of percents or just sort of single digits?

So I'll take that one. We're -- so we have various different models, and there are a few that are relatively small numbers. But the increasing trend at the moment is that we're seeing bonus potentials of 10%, 15%, 20%, and some cases, 30% and beyond possibility, which is really significant. Now obviously, you have to deliver really top-tier performance for that. But we have done that in several instances. So we really think that is a way forward. And you're right, it's a way of getting our effective day rates up nicely compared to where we used to be, at the same time, allowing the operators to get an AFE over the line, so to speak, and giving us all that potential to perform and add a lot more money. But in short, the bonuses are significant and in fact it seems to be the higher the day rate, the higher the bonus percentage as well. So in harsh environment, that seems to be leading the way where you're seeing routinely potentials of 15% to 20%.

Okay, that's really helpful. And then just a follow-up question. I mean, if I look at just -- take a step back and look at the contract expiry portfolio. I mean, there's a lot of rigs coming off sort of back end of the second half of '18 just as you're sort of describing the market to be tightening in certain of those categories. But you've also got a large option portfolio as well, if I look at the Fleet Status Report. What happens next? If the market is tightening, do you see customers really starting to lock in those options?

Yes, certainly. So far, we've actually seen them locking up options. So most of the options are picked up. I think the pickup rate is over 80% of number of options that we're -- that get picked up. So -- but in terms of where that goes going forward, so options being offered, we're being a bit more stringent on that now, right, especially in the tighter market. We're tending not to offer as many options or we're pushing back on straight debts so that they're picked up and (inaudible) a lot earlier.

Yes, that makes sense. And you managed to getting some -- on the longer options, you managed to get some pricing on those as well?

Yes. So as Jeremy said, we've been very balanced in how many rigs we commit to long-term prospects in the downmarket. And all the ones that we do have on longer periods, in every case, the option rates go up. So in fact, we can point to the Norway ones because they're the easiest. But the option rates go up quite significantly, and they're still picking up the options. So that's a good sign. But certainly, even on the ultra-deepwater ones, a couple of the long-term ones that we signed during the downturn, all of them have higher option periods, higher option rates. So some of them are hardwired, but will go up by a certain percentage. And some of them are actually linked to things like oil price commodity or average day rate of floaters. So when we saw options being requested in later years like '19 and '20 and '21, that's kind of the way we played it to make sure we didn't lock ourselves into lower rates into the early '20s. But -- so we should see some good upside in some of those longer ones.

And that concludes today's question-and-answer session. Mr. Alexander, at this time, I will turn the conference back to you for any additional or closing remarks.

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

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