Transocean Ltd (RIG) 2016 Q1 法說會逐字稿

Good day, and welcome to the first-quarter 2016 earnings call for Transocean Limited. Today's conference is being recorded. At this time, I'd like to turn the conference over to Bradley Alexander, Vice President of Investor Relations. Please go ahead, sir.

Thank you, Lauren. Good day and welcome to Transocean's first quarter 2016 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 are call Jeremy Thigpen, President and Chief Executive Officer; Mark Mey, Executive Vice President and Chief Financial Officer; and Terry Bonno, Senior Vice President Marketing.

During the course of this call, participants 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.

Finally, once we begin our question and answer portion of the call, to give more participants an opportunity to speak on this call, please limit your questions to one initial question and one followup. Thank you very much, and now I'll turn the call over to Jeremy.

Welcome to our employees, customers, investors, and analysts participating in today's call. Joining me today are Mark Mey, Chief Financial Officer, who will later provide the financial overview; and Terry Bonno, Senior Vice President of Marketing, who will then provide an overview of the market.

As reported in yesterday's earnings release, the Company generated adjusted net income of $254 million in the first quarter, or $0.69 per diluted share on $1.3 billion in revenues. While there are a few puts and takes in the quarter, which Mark will explain, we are very pleased that our underlying operating performance continued to deliver strong revenue efficiency of 95% as well as further cost reductions. Of note, we delivered this high level of performance while breaking in the Deepwater Thalassa, the first of four newbuild drillships commencing 10-year contracts with Shell. As such, I would like to personally take a moment to thank our newbuild project teams, our crews offshore, and our shore-based support for exemplary work in the first quarter.

As we move through the balance of 2016, we will continue our intense focus on safety and operational integrity, both of which continue to improve; on up-time performance, which continues to average 95% or better across our fleet; on cost control, which resulted in meaningful sequential reductions in operating and maintenance expense and G&A expense; on the high grading of our fleet, which we demonstrated in the first quarter with the addition of one new high-specification ultra-deepwater drill ship and the retirement of an older rig; and on the further strengthening of our customer relationships, which helped us to secure additional contracts in a highly competitive environment.

Speaking first about cost control, we continued to identify and realize opportunities to reduce operating, stacking, and overhead costs to maximize our operating margins in the face of declining activity. For rigs under contract, we are streamlining maintenance activities, which are delivering sustainable cost savings while simultaneously increasing uptime. In addition to recognizing savings associated with process efficiencies, we continue to work closely with our supply partners to drive cost out of manufacturing, maintenance, service, and repair. To date, the realized savings are ranging between 20% and 30% for some of our costliest areas, including riser inspection and certification, engine overhauls, and crane maintenance.

For rigs that need to be stacked, we challenge our teams to look beyond conventional practices, especially when it came to our dynamically positioned rigs, to find ways to preserve these assets in the most cost-effective manner. As a direct result of their expertise and ingenuity, we are now clustering these rigs in benign sheltered environments offshore, using a temporary mooring system. As part of the process, we are protecting critical equipment and controls using preservation fluids and dehumidification units to ensure that the rigs are in condition to be reactivated in an expedient and cost-effective manner when market conditions improve. As a result of these actions, stacking costs associated with these rigs have decreased by approximately 75% since last year to less than $20,000 a day.

For our shore-based support and overhead costs, we have almost finalized the restructuring of our organization, which includes centralizing our global support functions in Houston. This eliminated or significantly downsized our hub offices around the world while reducing the layers between our management and the rig. While streamlining maintenance processes, stacking rigs, and restructuring the organization are not necessarily easy and require tough decisions, we are pleased with our progress in these three key areas of cost reduction, which will continue to positively impact our operating results going forward.

Turning to our fleet, we are pleased to welcome the Deepwater Proteus to Transocean. The Deepwater Proteus, which is the second of four newbuild drips contracted corrected to work for Shell, is expected to commence operations in the coming days. In addition to the Deepwater Proteus, in March we christened the Deepwater Conqueror at the Daewoo shipyard in Korea. This ultra-deepwater drillship is scheduled to commence her five year contract with Chevron in the Gulf of Mexico at the end of the year. As a reminder, all of these rigs are designed to operate in water depths of up to 12,000 feet and drill wells to a depth of 40,000 feet. They were constructed with Transocean's patented dual activity drilling technology, industry-leading hoisting capacity, and dual BOPs. These rigs are fully outfitted to be upgraded with 20,000 PSI BOPs. In short, they are excellent additions to our fleet.

While discussing the newbuilds, and as previously announced, we've reached agreements to delay the deliveries of our uncontracted floaters and jackups into 2020. These deferrals will help us preserve near-term liquidity while continuing with our fleet renewal strategy, albeit at a slower pace. In addition to our own newbuilds, we are now seeing more sixth-generation deepwater rigs marketed for sale. As stated in previous calls, we will continue to evaluate these opportunities with our interest limited those assets that would enhance our overall fleet quality while furthering our fleet strategy; however, it's important to note that we continue to place a very high priority on liquidity and will remain very selective in regard to any potential transactions.

As part of high-grading the fleet, we also continue to assess the capability and marketability of our existing rigs. Through this review we made the decision in the first quarter to recycle the mid-water floater, the Transocean John Shaw, increasing our total rigs recycled or held for sale since the start of the downturn to 25. As we move through the year, we will continue this process and will remain decisive in determining the future of each rig the market continues to evolve.

Before turning the call over to Mark and then Terry, I'd like to take a moment to talk at a high level about the market. As you well know, the near-term market outlook remains very challenging. At this point we do not expect to see a meaningful recovery in rig activity before 2017, as customer budgets have been set for 2016 and are unlikely to improve until there's further recovery in the price of oil and confidence regarding its sustainability as bolstered. Even so, we remain very confident in the long-term fundamentals of offshore exploration and development, and the drilling industry's inevitable recovery. I visit with customers on a regular basis and my recent conversations with them have reinforced our position that future hydrocarbon supply requires significant production from offshore, and more specifically from deepwater fields.

Our largest customers have significant deepwater reserves and they recognize without increased activity they will face production declines and reserve replacement challenges that will be difficult and costly to reverse and overcome. North America, Venezuela, Mexico, and the UK have all experienced year-over-year production declines and we expect this will only increase as the recent deficiencies and reinvestment continue to impact overall supply. Additionally in my customer discussions, it's becoming more evident they recognize the benefit of narrowing their supplier base for key services to a few select partners that can help them to deliver their operational and financial objectives. This market downturn has allowed them to cherry-pick the highest quality contractors and service providers and move toward agreements that should promote direct negotiations on some of their prioritized opportunities.

Through both pricing concessions and the more collaborative approach between operators, contractors, and service providers, the high costs previously associated with much of the deepwater activity are beginning to abate. The industry is now witnessing sustainable cost reductions that will ultimately drive economic development of large offshore projects well below previous price per barrel requirements. As wells are drilled faster and more precisely, and production equipment and facilities are engineered using more efficient approaches, the competitiveness of these assets will continue to improve.

As oil prices then recover and the liquidity profile for our customers improves, we expect the offshore drilling activity declines we have experienced will reverse. When that time comes, we are confident that our stacked rigs are not only being preserved in the most cost-effective manner but in ways that will enable their swift reactivation and return to operation. Until that time, we will continue to prudently manage our balance sheet and cost structure while remaining intently focused on operations to ensure we remain the offshore industry's driller of choice.

I'll now turn the call over to Mark.

Thank you, Jeremy, and good day to all.

During today's call I will recap the first quarter results, provide an update to our 2016 guidance, and discuss our balance sheet and liquidity position. For the first quarter of 2016, we reported net income attributable to controlling interest of $249 million or $0.68 per diluted share. These results included $5 million or $0.01 per diluted share in net unfavorable items that are detailed in our press release. Excluding these items, adjusted net income was $254 million or $0.69 per diluted share.

Contract drilling revenue for the first quarter of 2016 decreased by $345 million sequentially to $1.1 billion. The decrease was primarily through reduced activity associated with 634 fewer operating days during the quarter. Operational and technical teams continue to perform at a very high level, delivering another quarter of 95% revenue efficiency. Other revenue decreased $165 million sequentially to $230 million during the quarter. This included $209 million in early contract termination fees, primarily associated with the Discover Deep Seas and the Deepwater Millennium. When adjusting these early contract termination fees for contract drilling revenues expected during first quarter, these rigs [worked] as planned, $133 million related to days beyond March 31, 2016.

First quarter operating and maintenance expense was $655 million, down from $794 million in the prior quarter. The 16% decrease was largely due to lower activity, cost savings related to operational and restructuring initiatives, and reduced [second] costs for our fifth- and sixth-gen DP floaters. This was partially offset by the $45 million of reactivation costs for the Henry Goodrich expense during the quarter. The Goodrich begins its two-year contract with Husky later this month. Additionally, we recognized $18 million mobilization costs on a GS8 development driller number 1 that was previously anticipated to be recorded in the second quarter. Also, first quarter O&M expenses were negatively impacted by $3 million of restructuring costs associated with employee severances.

G&A expenses totaled $43 million, down $15 million from the prior quarter, which reflects our ongoing restructuring efforts. Our operating margin, including G&A expense, was approximately 47% for the quarter, driven higher by the impact of early contract terminations included in other revenue above. The first quarter annual effective tax rate was 22.8% compared with 13.1% in the prior quarter. This increase was due to the lower adjusted pretax income and change in the mix operating results from certain jurisdictions. We ended the quarter with $2.6 billion in cash and cash equivalents, reflecting cash flow from operations for the first quarter of $631 million, which includes a working capital release of $128 million.

Capital expenditures for the first quarter totaled $368 million, largely associated with payments on the newbuilds. Since the last call, we opportunistically repurchased $100 million of debt at a cost of $84 million. As these debt repurchases were settled after the end of the quarter, the first quarter's balance sheet does not reflect these debt repurchases. Cash interest savings for these debt repurchases is approximately $23 million over the remaining term. This brings our total repurchases for the three quarters to $603 million at a cost of $557 million and an aggregate interest cost savings of approximately $105 million through maturity of this debt.

I will now provide an update on our financial expectations for 2016 and our liquidity expectations through 2017. Our 2016 revenue efficiency guidance remains at 95%. Other revenue for 2016 is expected to be between $260 million and $270 million, which includes customer reimbursables and the early contract termination fees recognized to date in 2016. We expect full-year operating and maintenance expense to range between $2.1 million and $2.3 billion. This 6% decrease from our previous guidance reflects reduced activity, primarily as a result of early contract terminations. Consistent with activity, O&M costs will be higher in the first half of 2016 and trend lower through the later quarters as the number of rigs active decline during the year. We estimate that O&M expense for the second quarter will be in the range of between $550 million and $570 million. We also expect the second half of the year to benefit from reduced [second] expenses and beneficial cost impacts resulting from our smaller streamlined support organization.

Full-year G&A expenses are expected to be approximately $160 million. Similar to O&M, this amount is anticipated to decrease as it progressed through the year. We estimate that the second quarter G&A will be approximately $45 million. Full-year 2016 net interest expense is expected to be between $360 million and $370 million. Net interest expense includes capitalized interest and interest income of $185 million and $10 million respectively. Full-year 2016 annual effective tax rate is expected to be in a range between 28% and 30%, as we expect higher tax rate for the remainder of the year. This is due to a significant reduction in net income from operations as fewer rigs are working and some at lower dayrates.

There are no changes to our expected 2016 depreciation expense. Capital expenditures for the remainder of 2016 are expected to be approximately $1.1 billion, including approximately $1 billion for the newbuilds Deepwater Conqueror, Deepwater Pontus, and Deepwater Poseidon. This amount includes capitalized interest. We expect maintenance CapEx to be approximately $80 million for the remainder of 2016.

Turning now to our financial position. Since our last call we have enhanced our liquidity position by announcing two separate future newbuild delivery deferrals. In early March we agreed with Keppel FELS to defer the delivery and related payments of our five high-specification jackups. This defers approximately $735 million from 2018 and 2019 into 2020. In April, we amended the construction contracts which are long, to delay delivery of two newbuild ultra-deepwater drillships by approximately six months each. These two proprietary Jurong Espadon 3T designed drillships are now expected to be delivered in the first and third quarter of 2020. This defers approximately $420 million from 2019 into 2020. We continue to evaluate the secured financing options in our five contracted newbuild drillships. As you are aware, these rigs are highly marketable assets due to the quality of our assets and the respective contracts, as well as the contract duration. We'll provide a more fulsome update in due course.

We reiterate our assumptions related to our updated liquidity forecast through 2017. These include revenue efficiency of 95%, a limited number of new contract awards with dayrates assumed to be at or near cash breakeven, and working capital release of approximately $500 million in total for the years 2016 and 2017. This includes the previously mentioned $128 million of release in the first quarter. In 2017, we expect total CapEx of approximately $625 million. This includes $375 million of newbuild CapEx and $250 million for maintenance CapEx. Based on our current forecast, our projected liquidity at December 31, 2017, remains in the range of $4 billion to $5 billion. Our projection includes our $3 billion undrawn revolving credit facility that remains available to us through mid-2019.

To conclude, we are very pleased with our strong operational results, adequate liquidity, and substantial contract backlog. We also believe the quality of our fleet, together with our proprietary rig (inaudible) focused on efficient reactivation, better positions us to win more than our fair share of future drilling contracts, increasing our contract backlog and further bolstering our financial strength.

This concludes my prepared comments. I'll now turn the call over to Terry.

Thanks, Mark, and good day to everyone.

As you all know, the market remains very challenging. Despite the recent increase in oil prices from the multi-year lows experienced early in the year, operators remain hesitant to commit to long-term projects that require significant levels of capital. However, as Jeremy mentioned, we continue to have meaningful dialogue with our customers, and they remain firmly committed to their deepwater assets as they view these as a necessary source of future reserves.

The real question is around the velocity with which these customers will ultimately add rigs in response to decline in reserve replacement and production. Even more so than in past cycles, our customers realize that the reduction in offshore drilling is not sustainable, especially considering the fact that the global demand for energy continues to increase. In the meantime, as we await the eventual recovery, we will continue to position our fleet to take advantage of opportunities in the market. As stated in previous conference calls, our teams continue to battle for every opportunity in this highly competitive market, looking at ways we can best align with our customers well plans and business objectives. This approach has once again proven to be successful, as we signed several new contracts resulting in the addition of $138 million of contract backlog since the last earnings call, bringing our 2016 total to $184 million.

In our ultra-deepwater fleet we extended the duration on the Deepwater Invictus by adding a 2.0 contract at $350,000 a day in Trinidad, with additional bonus opportunities. This contract award highlights our stellar operational performance for BHP and our willingness to work with a customer to best meet their project priorities. We've also secured a six-month contract on the KG2, returning her to work after being idle.

While you are likely aware of the recent announcement from Hurricane Energy with respect to the Spitsbergen, we've waited to formerly announce this contract pending approval of their Board early this month. In India, we were awarded a three-year contract on the mid water floater Actinia, also returning her to work after being idle. In total, our fleet in commercial strategy enabled us to return three idle rigs to our active fleet and to further extend work for another rig during the quarter. As a result, our backlog as of April 21 is an industry-leading $14.6 billion. This foundation provides solid future cash flow generation, with 79% of the revenues contracted with the super majors, 13% contracted with the independents, and 8% contracted with the national oil companies. And further, we do not have contracts in our current backlog that permit cancellation for convenience without compensation.

Turning to the global market, while we are seeing some positive movement in the macro environment and improved confidence regarding oil prices for the second half of 2016, we expect challenging conditions are likely to continue into 2017, impacting both utilization and dayrates. In order for contracting conditions to improve for next year's budgeting cycle, customers need to see these improved oil prices sustained in the coming months. As the market stands today, ultra-deepwater market utilization is down to 79%, with 32 rigs idle and 23 cold-stacked. Year to date, we have seen 11 fixtures that have been executed, mostly in Asia and India in addition to a few in South America and Africa, with the majority being short-term work. Longer term fixtures were largely agreed in 2015 but executed in 2016. With the amount of rig availability in the market, including farm-out opportunities, we will continue to see strong competition for every opportunity. Another example of this is increasing competition, as we understand it, is the recently announced Chevron Nigeria tender for two years, which drew numerous contractors.

As we wait for the award of the long-term exploration tender in India, expected to be within the next two weeks, we understand the development work requiring two additional 1,500 meter DPs for almost three years term per rig commencing in 2017. It is encouraging to see some customers are taking advantage of the lower pricing environment to proceed with their projects. Deepwater marketed utilization is down 71%. There have been five fixtures year to date, primarily in Asia and Europe; there are currently 11 idle and 10 cold-stacked deepwater units, while we await the results of the ongoing 600-meter tender in India. We are also happy to see another long-term tender about to come to the market. [OEGC] is expected to release the development tender for one more unit for almost two-year term that will commence in 2017.

Mid-water utilization is at 69%, with six fixtures contracted year-to-date, mainly in Norway and India. Currently, there are 16 mid-water rigs that are idle and 18 units cold stacked. As previously stated, continued stability and improvement in commodity pricing will increase the number of opportunities for these assets in the UK and Norway. Industry-wide, there are 51 cold stacked floaters plus 53 units that are retired or being held for sale. We expect these numbers to increase with a relative high levels of supply and near-term lack of demand forcing the retirement of most assets.

The jackup market continues to deteriorate as a result of increased market oversupply. This is being exacerbated by very few rigs being scrapped due to the minimal costs associated with cold stacking and the growing is supply of newbuild rigs being delivered. Marketed utilization is approximately 71% with 120 rigs currently idle and 69 cold-stacked. There have been 21 fixtures year to date, mainly in the Middle East, Asia, and UK. Unlike the floater market, national oil companies are leveraging their local market dominance and lack contract terms in either renegotiating dayrates or outright canceling the remaining term.

Overall, our customers remain focused on cost reductions, operational excellence, and safe operations, and they remain committed to delivering their core business, which will undoubtedly include deepwater exploration and development. Until we experience the uptick in demand for our assets and services, we will move forward with our strong liquidity, industry-leading backlog, and excellent operational and safety performance, as we continue to position Transocean to increase our market-leading position as we progress through the downturn.

This concludes my overview of the market, so I'll turn it over to Brad.

Thanks, Terry. Lauren, we are now ready to take questions. And as a reminder to all of our call participants, please limit yourself to one question and one follow-up question.

Thank you.

(Operator Instructions)

Our first question comes from Greg Lewis from Credit Suisse.

Yes, hi. Good morning.

Good morning.

Jeremy or I guess Terry can answer this question. So as we progressed through 2015 we started to see a pick-up in contract terminations not only for Transocean but across the industry and then it seems like it's accelerated again in the early part of 2016. Are we at a point now where generally customers that were going to cancel contracts have that behind them or is this something that we think is going to continue to plague the industry over the next 6 to 12 months?

Well, Greg, good morning. I think what we have to look at is from our own conversations with our customers. It's really hard for us, difficult for us to project what will happen to our competitors, but for those folks that are suffering for the lower commodity prices I think we will see more contract terminations or probably a little bit more a contract renegotiation, but from our fleet and our perspective we are not hearing those conversations as of today. In fact, we are in conversations with some extensions of our fleet, so we believe that with our strong backlog that our conversations perhaps are going to be a little bit different than our competitors.

I think that's the point. Almost 80% of our backlog is with the super majors and 90% is with investment-grade companies, so we feel really good about the strength of the backlog and being able to convert that into future earnings and cash flow. Never say never though. It depends on what happens in the market obviously, but right now we aren't having those conversations with our customers.

Okay, great. And then, Mark, just for you. Saw in April you bought back some debt. I'm just trying to sort of gauge why April? Why not earlier this year? And then any color on which of the bonds were actually repurchased?

Yes, sure, Greg. We focus mainly, as I've mentioned to you guys in the past, focus mainly on the new-debt maturities. So we have been buying back the 2016, 2017, 2018s mainly with some focus on the 2020s to 2022s. It just so worked out the previous quarter that our opportunity to actually attract bonds, raise the bond availability was later in March.

Our next question comes from Ian Macpherson with Simmons.

Thanks, good morning. I guess my first question was I wanted to get your updated thoughts on the equity market as an option for your financial strategy given the pretty strong support that Insco got on theirs?

Good morning, Ian. I think I'll be very clear in the past that we have substantial liquidity. We have an industry-leading backlog and I think we have a debt maturity profile that allows us to avoid the equity market. I think we'll be opportunistic with regard to adding and refinancing our maturities with secured-debt options in the event that we are able to achieve that, but at this stage we do not feel that equity is the right solution for Transocean.

Very clear. Thanks, Mark. I have a follow up also for you, if you don't mind. I'm looking at your fifth-gen rigs that are stacked. It looks like 2014 fifth-generation rigs that are mainly stacked, a couple of them idle or maybe almost stacked. Can you comment on the carrying value of those and what the impairment test framework looks like for those rigs going forward and whether we should think about a vulnerability there going forward?

As you well know, the impairment test is based on the remaining life of the assets and these assets will be dominantly delivered around 2000, so you're looking at assets that would last through 2020. So given the fact that we have a significant tail, on average about 15 years or so of remaining life of these assets, I think it's fair to say we feel very strongly that given the way we have approached our stacking on these assets they've been cold stacked with the intention of reactivating these rigs very quickly and cost effectively, so as the market does recover in 2018 and 2019 as Jeremy has mentioned in the past, we believe these rigs will come back to the market and we will be able to earn sufficient cash flows to offset the carrying value of that remaining period.

Our next question comes from Angie Sedita with UBS.

Thanks. Good morning, guys. As a follow-up to the prior question, I guess another way to think about it or ask the question is thoughts about what are the parameters leading you to scrap additional rigs and what are your considerations? You have a lot of rigs that are stacked and how do you think that through?

Yes, Angie. I think we've taken a pretty thoughtful view of the global float and kind of positioned our rigs against that. As we look at our fifth-generation rigs, not all of them but the vast majority of them, we see them being highly competitive when the market turns around. Other than really the Gulf of Mexico and presalt Brazil, these are excellent assets that are proven to be very valuable for us and our customers, so we feel good about our asset strategy and fifth gens will be a part of that asset strategy.

Okay, okay. And then good to see that you're paying down some of the debt and I guess a little bit further looking out going into late 2016 and going into 2017, if you don't secure that secured financing on the Shell new builds is it fair to assume that cash is going to be drawn down or would you tap into the revolver? How are you thinking about cash versus your revolver on those debt maturities?

Angie, we typically look at our liquidity as spongeable, so cash and revolver, so we fully expect to be able to use a combination of both to retire the 2016s. The potential secured debt is opportunistic on our part. We don't feel that it's necessary to raise that debt to retire the 2016s or the 2017s for that matter, so anything we gauge in addition to our current liquidity in the form of secured debt would be over and above what we planned to manage through the cycle.

Our next question comes from Ole Slorer with Morgan Stanley.

Yes, thank you. Thank you very much. I thought I'd ask you a little bit about your high level thoughts around Transocean Partner and the flexibility that they potentially offer you, how you are thinking about utilizing that both maybe for assets or for maybe buying discounted debt in Transocean?

Good morning, Ole. This is Mark. Look, I've been very clear that in the past on these calls that currently the value arbitrage that we enjoyed when we listed Transocean Partners for the first time has reversed, so it's not economic for us to be able to use Transocean Partners in the capacity which was envisioned initially. That is still our intention if and when the market does recover for both the offshore drilling industry and for yield-based vehicles. So the intention there would be to nurture Transocean Partners as best we can and recognize when the opportunity provides itself we will utilize the vehicle in the capacity in which we intended.

Okay. Very clear. A follow-up question would be your thoughts on Brazil. It strikes me that getting international clients to become operators in presalt Brazil is probably the only thing that can bring the ultra-deepwater market back in balance again at a reasonable time frame, so have you had any thoughts? Do you have a very strong relationship in particular with one international national client that recently made a very big bet on Brazil?

Yes, that's a good question. So we believe that the interest certainly with the majors is very high in Brazil and we think that at some point, and of course I can't tell you when that set time is going to happen, but the customers that have bet big on Brazil are very focused on developing those opportunities. So when the time comes, I think that we will be participating in a meaningful way and, again, I think as we wait for Petrobras to take another look at their fleet and continue to high grade, I think that they are going to be able to extend some of these contracts, and we've been speaking with them a lot, too. So, again, we've been having a lot of conversations about Brazil.

Our next question comes from Sean Meakim with JPMorgan.

Hey. Good morning.

Good morning, Sean.

Just had a little follow up on your OpEx. Just wondering if there's any incremental OpEx in the quarter from the [deem bobe] on the Deep Seas or the Millennium and I'm asking that as just trying to get a sense of quarter over quarter how you're seeing rig OpEx is tracking as you guys are looking to bring those costs down?

Well, Sean, I think I was very clear in my prepared comments with regard to what one-time costs we saw in the first quarter with regard to the reactivation costs on the Goodrich, the mobilization which we recognized in the quarter as some severance costs, but obviously the trend is Q1 will be higher, Q4 will be the lowest for the year because as you model out our operating activity with a number of rigs, those decline throughout the year. That being said, we have to factor in the addition of the [Polassa], the Proteus, and obviously the reactivation of the Goodrich which will go in the other direction but, in general, you are going to see a significant reduction in operating cost. In addition, as you know with the first-quarter's contract cancellations, we have announced that those rigs are going to be cold stacked, but there are certainly costs associated with cold stacking the units, which is expense in the 30 to 60 days, so you'll see that flow through in the February, March, and some of it in April time frame as well.

Great. Thank you, Mark. And then just as we think about blend and extend opportunities, just thinking about the Discover India, some of these other -- if you think about the opportunity to spread some contracts across certain rigs, just curious to get an update of how you guys see the world there.

I think that there's going to be a few opportunities, more opportunities for blend and extend. We did something a little bit different than our competitors have done. We did actually with BHP in Trinidad we actually inserted a contract and then moved all of our terms to the right in Trinidad to help better align that program with BHP's objectives. So you might see a bit more of that where we're able to do that and certainly remain focused on our cash flow, but as far as true blend and extend, we are in discussions with a few customers and again I they we will see a few more.

(Operator Instructions)

Our next question comes from Darren Gacicia with KLR Group.

Good morning. Thanks for taking my question.

Hey, Darren.

I wanted to -- this may be more for Terry. In your prepared comments you talked about the commodity would have to stay higher with a positive view going into budgeting cycle, maybe to change the kind of trajectory where demand has been. Is there a chance that you may not get enough momentum and (inaudible) end of your budgeting cycle to have things updated meaningful in 2017 or maybe the budgeting cycle will be much more fluid going on, and I ask this question also with respect to lead times to get rigs back into operations and just how customers and how you're kind of view on that is given the fact that the commodity market seems to be a little bit more accommodating?

Darren, I think that was three or four questions in one. I'll try to go through them all again. I think we've been pretty clear, do we see the up-tick in oil price and the sustainability of it early enough for customers to build it into their budgets for next year. We aren't sure. We said publicly we don't know the answer. We said publicly we expect 2016 and 2017 to be challenging, so I think it would be a pleasant surprise if oil prices continue to move up and to the right and customers got confidence ahead of their budgeting cycle where we could see meaningful improvement and activity for next year, but we're not building the business on that right now, so that was one piece of it.

I think that the second piece of it in terms of how quickly can we respond, it's going to depend on the rig and the condition of the rig. We have a team that is both responsible for the stacking of the rig and also that same team is responsible for reactivating the rig, so we're doing everything that we possibly can to ensure that we're preserving this equipment and preserving these rigs in a way we can reactivate them cost effectively and quickly, but it's going to depend on the rig. Some of them may take 60 days, some of them may take 120 days, but that's the range of reactivation we're looking at across the fleet right now.

Sure, and if I could follow up with a much simpler second question. In terms of the dispatch of rigs going back into the market, most people would assume the best high stack 60 rigs come to work first. Do you think there's enough spread of work where maybe your reactivations are kind of (inaudible) to come back (inaudible) across down into some of the mid-water rigs as well?

There was a little bit of static in the line. I'm not sure you got the question. Can you ask again, Darren?

Sorry, I was simply saying everybody was in the (inaudible) to go to work first, maybe the incremental up-tick in work spread into some of the 5G, 4G, or maybe even 3G rigs in a recovery.

Darren, this is Mark. I think it's expected to assume that you're going to have dollars spent across the board, right? You're looking at dollars being spent onshore, shallow offshore, harsh environment, deepwater, Gulf of Mexico, and elsewhere. So I think what's going to be an interesting driver of the recovery is the makeup and financial viability and strength of our customer base. So as we look around the world and we look at the basins and the main customers in those areas, that's going to drive how they return back to the market. I think Jeremy made a comment in his prepared statements around Venezuela, for example. If you don't have any funds available you aren't going to be able to attract service companies or E&P companies to be able to restart your production. So I think we have to think about that as well in the context of what's going to be first, second, and what's going to be most viable on a perspective basis.

Our final question comes from Jud Bailey with Wells Fargo.

Thank you. Good morning and actually probably wanted to follow up on some of your commentary there, Mark, on thinking about a recovery. If we look back at prior offshore cycles, typically jack-ups and mid-water tend to react first because those customers will tend to spend cash flow first. In your mind is there a case to be made that ultra deepwater activity could recover as fast as some of the other markets maybe faster than they have historically because some of the majors cut back so severely? I'd just be curious from what you're hearing from customers if you think that's a possibility.

Well, Jud, I'd love to answer the question but Terry speaks to customers a lot more than I do, so I'm going to defer it to her.

As you look historically you're right because it's easy to plug and play on the jack-ups and the mid-water fleet and we certainly expect the UK Norway to react pretty quickly. The ultra-deepwater sites, we do have the independents who are telling us that if $50 looks really great and they could do some plug and play, so I think we'll see that happen as long as we have some sustained momentum certainly with the commodity price, but as far as the majors they've got to get a little bit more stability. It takes awhile to do their feed study, so I think we're going to see a pause until they get more comfort and are able to push their programs forward.

Okay. Appreciate that. And then my follow up is thinking about the reactivation of fifth gens. Whenever that time does come, is there a way to help us think about the costs associated given that how you're maintaining the rigs as they are stacked? Are we looking at something I would assume greater than what it just cost you to reactivate the Goodrich or help us think about reactivation costs whenever you do start unstacking some of the fifth gens?

It's going to be a range. It's going to depend on the asset itself, but we kind of had a range on -- if you go through the different classes of rigs, ultra deepwater might be somewhere between $20 million and $100 million and I know that's a big range, but that's kind of where we are. And then as you go into some of the lower classes of rigs, that high end comes down obviously maybe into the $70 million and $60 million range, but until we do it we're not going to know. We've got pretty good plans in place. We have got good ideas of what it is going to cost us, but until we actually execute, we are not going to know, Jud.

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

Thank you to everyone for your participation and questions on our call today. If you have any further questions, please feel free to contact me. We will look forward to talking with you again when we report our second-quarter 2016 results. Have a good day.

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