Noble Corporation Plc

Jeffrey L. Chastain - Noble Corp.

Plc David W. Williams - Noble Corp.

Plc Adam C. Peakes - Noble Corp.

Plc Simon W. Johnson - Noble Corp.

Plc

Gregory Lewis - Credit Suisse Securities (USA) LLC Ian Macpherson - Simmons & Company International Haithum Nokta - Clarksons Platou Securities, Inc. Eduardo B.

Royes - Jefferies LLC Vaibhav Vaishnav - Cowen & Co. LLC Colin Davies - Sanford C.

Bernstein & Co. LLC

Okay, Carol. Thank you very much, and welcome, everyone, to Noble Corporation's first quarter 2017 earnings call.

We appreciate your interest in the company. In case you missed it, a copy of Noble's earnings report issued last evening, along with the supporting statements and schedules, can be found on the Noble website, and that's noblecorp.com Before I turn the call over to David Williams, I'd like to remind everyone that we may make statements about our operations, opportunities, plans, operational or financial performance, the drilling business, or other matters that are not historical facts and are forward-looking statements that are subject to certain risks and uncertainties.

Our filings with the U.S. Securities and Exchange Commission, which are posted on our website, discuss the risks and uncertainties in our business and industry and the various factors that could keep outcomes of any forward-looking statements from being realized.

And that includes the price of oil and gas, customer demand, operational, and other risks. Our actual results could differ materially from these forward-looking statements, and Noble does not assume any obligation to update these statements.

Also note we are referencing non-GAAP financial measures in the call today. You will find the required supplemental disclosure for these measures, including the most directly comparable GAAP measure and an associated reconciliation, on the Noble website.

And finally, consistent with our quarterly disclosure practices, once our call has concluded, we will post to our website a summary of the financial guidance covered on today's call, which will cover second quarter and full year 2017 figures. So with that I'll now turn the call over to David Williams, Chairman, President, and Chief Executive of Noble.

All right. Thanks, Jeff, and good morning, everyone.

I'd also like to extend a welcome to each of you, and thank you for joining us today and for your continued interest in Noble. I'm very pleased with Noble's start to 2017 and encouraged by what continues to be clear evidence of a recovery in the offshore industry, although it's still in its early stages.

Joining me today and contributing to the discussion in addition to Jeff are Adam Peakes, our Senior Vice President and Chief Financial Officer, and Simon Johnson, our Senior Vice President of Marketing & Contracts. I'll begin today with some high-level comments on first quarter results, after which Adam will cover the quarter in some detail, including revised guidance for the year.

I'll also offer some further clarity on our disclosure made on April 24 regarding the termination of Noble's settlement agreement with Paragon Offshore. And then, following Adam's and Simon's discussions and before we take your questions, I'll have a few closing comments.

I could not be more pleased with the operational performance and overall execution of the company during the first quarter. Total downtime across the fleet of 2.8% approached historic lows for the company, and with unpaid downtime of less than 1% in the quarter.

Operating costs continued their positive trend, finishing 9% lower than the fourth quarter level as we continued to implement cost management initiatives and expeditiously aligned our operation with the prevailing level of fleet operating days. These efforts supported operating margins that remained well above 50% despite the persistence of the market malaise and what we believe is the trough in the current cycle.

Our cost management efforts will not end with the return of the industry growth. We will continue to identify and implement programs through the business cycle that support sustainable and efficient operations.

One such program is our recently announced partnership with GE to collaborate on the Digital Rig solution. This is a holistic vessel-wide initiative enabling operational efficiencies achieved through the use of predictive analytics.

As previously noted, the partnership is expected to have a transformative impact on our entire drilling operation. The Digital Rig solution, which will initially be deployed on four of our rigs, will utilize data models and advanced analytics to detect asset anomalies, often a sign of potential failure or of performance degradation.

This early detection capability enhances drilling process efficiency by allowing us to address problems before they arise. This ability to predict the future condition of assets will also enable a shift from planned to predictive maintenance.

Although you may have heard similar discussion from others in our industry, at this time, we believe Noble is the only driller employing a vessel-wide, multi-vendor approach to achieve data-driven operational efficiencies. What does this mean for Noble?

Repair and maintenance of an offshore drilling rig can run as much as 25% of the daily cash cost. We believe the expected efficiencies captured through the implementation of the Digital Rig solution could achieve a reduction of 20% or more in repair and maintenance OpEx on the pilot rigs, and this estimate should grow as we realize synergies in other areas of our rig operations.

We're excited about the operational efficiencies expected from this collaboration with GE's Marine division, which is further evidence of how Noble is differentiating itself from competitors in the offshore drilling space. As a final comment on first quarter results, I want to address the operations of our jackup fleet.

This sector of our business provided another significant highlight in the quarter, with utilization improving to 93% compared to 86% last quarter. During the first quarter, our jackup fleet was awarded contracts totaling approximately 12 rig years, representing in excess of $650 million in contract revenues and increasing our total contract backlog at March 31 to $3.5 billion.

We closed the quarter with 77% of the remaining 2017 available operating days in the jackup fleet committed to contracts. Both jackup fleet utilization and days committed to contracts are setting the pace for our industry.

Simon will have more to say on the regional contract opportunities across the fleet in just a moment. Before I turn the call over to Adam, I want to address the latest developments with Paragon Offshore to provide some clarity on Noble's position.

As many of you know, Paragon, which was spun out of Noble in August of 2014 has sought approval for a pre-negotiated plan of reorganization by filing for voluntary relief under Chapter 11 of the U.S. Bankruptcy Code.

As part of Paragon's original plan, Noble had previously entered into a settlement agreement with Paragon, which involved Noble providing bonding support for Mexican taxes in exchange for a release of potential claims. Paragon has filed a new reorganization plan under which this tax bonding is no longer applicable, and the settlement agreement has therefore been terminated.

In their latest filing of May 2, Paragon has included the establishment of a litigation trust that would fund any litigation against Noble. As we've said from the outset, we do not believe there is merit to a potential fraudulent conveyance claim by Paragon or their creditors.

We established Paragon with good liquidity, a strong backlog, and a solid global business with well-maintained, operating rigs. We set them up to succeed, and we fully believed they would.

After the spin-off, a series of events led to an unfortunate bankruptcy filing. However, we do not believe there is merit to such a claim against Noble and are fully prepared to defend it if we do not amicably settle any potential claims.

And with that I'll turn the call over to Adam.

Thank you, David, and good morning to everyone. The first quarter 2017 results issued last evening included two highlights that have been noted consistently for several quarters: lower operational downtime and a further reduction in contract drilling services costs.

Both items were better than the guidance provided in February. I will provide more detail on these two items, along with other areas of our operation which fell outside of the guided range, after a brief review of first quarter results.

Additionally, I will provide updated financial guidance for the second quarter and full year 2017. As indicated in the earnings press release, Noble reported an adjusted net loss to the company of $42 million or $0.17 per diluted share on total revenues of $363 million.

The adjusted results exclude the negative impact of a noncash discrete tax item totaling $260 million or $1.07 per diluted share. Recall during my comments on the previous conference call, I noted an internal reorganization was in progress, driven by our efforts to produce an annual tax outcome that is better aligned with the company's earnings through the cycle and at the same time provide a more efficient cash tax profile.

As part of the reorganization, we recognized a $260 million noncash discrete tax item, which was previously anticipated to total approximately $280 million. Reported results for the first quarter, which included the noncash discrete item, were a net loss attributable to Noble of $302 million or $1.24 per diluted share.

I will provide additional comments on the subject of taxes during my update of 2017 guidance. For further clarification of this discrete tax item, please refer to the supplemental non-GAAP supporting schedule that was included with the press release issued last evening.

The schedule provides a reconciliation of net income or loss attributable to Noble Corporation, income tax, and diluted earnings per share for the first quarter of 2017. The non-GAAP schedule can also be found on our website at www.noblecorp.com.

Following fourth quarter 2016 contract drilling services revenues of $385 million, which excludes a $16 million favorable adjustment for the lump sum contract termination settlement on the jackup Noble Tom Prosser, contract drilling services revenues for the first quarter of 2017 were $355 million. In addition to unfavorable day-rate adjustments seen predominantly in our floating rig fleet and lower demobilization revenues, the decline was negatively influenced by an adjustment totaling $8 million relating to the quarterly revaluation of contingent payments associated with the contract termination settlement reached in May 2016 with Freeport-McMoRan.

Recall, the contingent payments total $25 million and $50 million and depend upon the average price of WTI crude oil over a 12-month averaging period ending June 30, 2017. Adjusted for the revaluation of this contingency, first quarter revenues declined 6% from the adjusted total in the previous quarter.

Shifting to a discussion on the first quarter results versus our guidance provided in February, I'd like to briefly update you on operational downtime, contract drilling services costs, non-controlling interest expense, and capital expenditures. Total fleet downtime was better than expected at only 2.8% for the quarter compared to guidance of 4%, while unpaid downtime ran less than 1% in the quarter.

This outstanding performance, which was achieved while more than 70% of our fleet remained active in the quarter, helped to preserve our quarterly operating margin at 55% for the first quarter and continues to demonstrate why Noble has earned a reputation for operational excellence. Contract drilling services costs were also below previous guidance.

The first quarter total of $160 million was 11% below the midpoint of our guided range of $175 million to $185 million. This favorable variance was due in large part to lower operations support costs, rig stacking costs, labor, and repair and maintenance expenses.

Non-controlling interest expense, on the other hand, was $5 million above the guidance of $13 million, with the variance due to longer-than-expected operations on the drillship Noble Bully II. The rig completed the drilling assigned offshore Malaysia in early April when it began an idle period of up to 365 days at a day rate of $200,000.

Capital expenditures in the first quarter totaled $19 million, notably below our guidance of $35 million. Factors contributing to this favorable variance were largely driven by delayed timing on certain projects that are likely to be addressed in our second quarter CapEx spend.

Finally, and before I transition my comments to an update on our full year 2017 and second quarter guidance, I want to highlight some liquidity and debt figures. Liquidity at the close of the first quarter was $3 billion, down only slightly from $3.2 billion at December 31.

The decline was due largely to the repayment of $300 million of senior notes maturing in March with cash on hand, partially offset by net cash from operating activities of $142 million. The components of liquidity at March 31 were cash and equivalents of $520 million and an undrawn revolving credit facility of $2.445 billion, which does not mature until January 2020.

Following the repayment of the $300 million in senior notes, total debt at March 31, 2017, declined to $4 billion and was composed of long-term debt of $3.8 billion and debt due within a year of $250 million. I'll now review our guidance for full year 2017, beginning with operational downtime.

We will maintain downtime guidance at 4%, even though results through March proved to be substantially better. We believe that 4% is a practical assumption given the complexity of our clients' wells programs and the premium nature of our fleet.

Contract drilling services cost estimates for 2017 are being reduced again. Our revised range of $585 million to $625 million reflects the favorable cost experienced in the first quarter but is also indicative of our continued success in identifying areas where efficiencies can be achieved.

Costs associated with client reimbursables remain unchanged for the year in a range of $20 million to $25 million, resulting in expected total operating costs of $605 million to $650 million. Contract drilling services costs in the second quarter are expected to range from $155 million to $165 million, reflecting lower operating costs for the Noble Bob Douglas and Noble Bully I following the recent completion of contracts and the idling of the Noble Bully II, along with lower insurance costs.

Following the completion of a drilling program offshore Suriname, the Noble Bob Douglas was mobilized to the Southern Caribbean and is currently hot-stacked while we evaluate multiple near-term opportunities. With the completion of the Noble Bully I contract in the U.S.

Gulf of Mexico, the rig was mobilized to the Southern Caribbean and is in the process of being cold-stacked, with daily operating costs estimated to total between $10,000 and $15,000. The Noble Bully II is warm-stacked in Southeast Asia at an expected operating costs of approximately $40,000 per day.

Costs associated with client reimbursables should remain in a range of $5 million to $7 million in the second quarter, reflecting the decline in our active rig counts. DD&A in 2017 remains in a range of $535 million to $550 million, with the second quarter range unchanged at $135 million to $140 million.

SG&A expenses in 2017 are being modestly increased to a range of $60 million to $64 million to reflect an expected increase in professional and legal fees. Second quarter SG&A expenses are expected to total approximately $17 million.

The full year guidance range for interest expense does not change from the range provided last quarter of $285 million to $295 million, with the range for the second quarter unchanged at $72 million to $74 million. Non-controlling interest expense on our P&L representing the Bully I and Bully II 50/50 joint ventures with Shell is now expected to range from $5 million to $10 million in 2017 following the first quarter results.

For the second quarter, we expect the line item to shift to income to Noble of $7 million, with both of the joint venture rigs expected to be idle over the quarter. However, as noted earlier, the Bully II will collect a day rate of $200,000 over this idle period, and we continue to market the rig for possible contracts that could supplement the day rate during this idle period.

As for capital expenditures, we are maintaining our guidance for 2017 at $115 million, which is made up of $39 million in major projects and $76 million in sustaining capital. Capital expenditures in the second quarter are expected to total approximately $39 million.

Finally, and in light of the internal reorganization discussed initially during our last call, I want to offer some additional thoughts on our tax outlook for 2017. Our go-forward effective tax rate exclusive of discrete events should be better aligned with the prevailing business environment and the resulting earnings.

When you exclude the $250 million non-cash discrete tax item from the first quarter results, our effective tax rate in the quarter was a benefit of 10%. For the full year 2017, we expect the tax benefit to be approximately 20%.

In closing, a solid base of revenues, matched against a level of operating costs that continue to demonstrate a downward bias, are key components of our financial performance in 2017. This, along with a more efficient cash tax strategy and significantly lower capital expenditures, are expected to support positive free cash flow generation for the year.

Our healthy liquidity position of $3 billion is expected to close the year only modestly below where we began 2017, including the use of cash on hand for the repayment of $300 million in maturities earlier this year. Contracting success over the first quarter provided improved operating and financial clarity and should enhance the available alternatives for capital structure and liquidity enhancements.

That concludes my remarks. I will now turn the call over to Simon for the market outlook.

Thank you, Adam. Good morning to all.

I'll begin today with an overview of our marketing efforts in the first quarter, which were exceptional. You can see this in the value of the new contracts that were signed.

As David noted, these added 12 rig years and over $650 million in contract backlog. However, the success of our efforts were evident in other ways.

For example, we engaged a growing number of customers in conversations for an expanding list of offshore rig requirements. Also, we diversified our customer base and, in the process, took steps to expand our geographic footprint into areas that will soon include Eastern Canada, along with a return to Australia.

And, finally, our customer's well program, located in one of today's most exciting offshore regions, was executed well ahead of schedule, demonstrating the operational skill and expertise of the Noble crews and resulting in strong endorsements from the client. Achievements such as these are not secured overnight but require many weeks of preparation and discussion and years of nurturing appropriate behaviors and culture.

I commend my global marketing team for a stellar effort and look forward to continued success through the remainder of 2017. As we continue to manage through this challenging phase of the business cycle, 19 of the 28 rigs in our worldwide fleet are currently contracted.

This compares favorably with overall industry utilization levels, which are markedly lower. This includes the Noble Tom Prosser, which will begin a contract in Australia in September 2017, and the extension of the current (19:21) accommodation contract for the Noble Regina Allen in the North Sea into mid-July of this year.

Upon completion of this work, the Regina Allen will mobilize to its new customer, Offshore Canada, as early as the fourth quarter of 2017. With our floating rig jackup fleet setting an industry-leading pace of utilization at 93% in the first quarter, our uncontracted rigs are all floating assets, which is indicative of the lagging nature of this segment.

However, we presently anticipate the contracted floater count to approach bottom in the second half of 2017. Thereafter, we anticipate improved opportunities to place some of our idle floating rigs back into service in what we presently forecast will be an improving demand environment for semisubmersibles and drillships.

I'll have more to say about our floating jackup rigs in a moment. Before I begin a discussion on the status of key offshore regions, it's worth noting, if only for some perspective, key takeaways in a report issued by the IEA addressing conventional crude resources in the offshore sector.

The report noted the following: Conventional resources sanctioned for development in 2016 were 30% below the total in 2015, with FIDs dropping to the lowest levels since the 1940s. The offshore contributes one-third of crude oil production, yet accounted for only 13% of resources sanctioned in 2016, compared to over 40% on average from the years 2000 to 2015.

North Sea oil investment fell to approximately less than half 2014 levels and is now approaching the same level of spending on North Sea offshore wind projects. These are some uninspiring statistics, to be sure.

The Executive Director of the IEA noted, "The key question for the future of the oil market is how long can a surge in U.S. shale supplies make up for the slow pace of growth elsewhere in the oil sector."

We believe that what we are witnessing today is an unsustainable investment model that will increasingly refocus attention on the enormous opportunities to be found offshore. As challenging as the offshore drilling environment has been over the past three years, numerous operators have recorded exploration success in 2016 and into early 2017 as they probe new prospects.

According to industry commentator IHS, there were 21 announced discoveries in 2016, which might come as something of a surprise given the industry headwinds, but still remained well off the pace set over the past decade. Because exploration is a necessity if our customers are to grow production and replace and even expand reserves, it remains our belief that in time the offshore sector will increase its share of our customers' upstream budgets.

I now want to discuss developments in offshore activity across the globe and the near-term outlook for those assets in the Noble fleet that are currently seeking work or rolling off contract later this year. The international rig market appears to be at or near low tide.

The good news is that at a 50,000-foot level, we are seeing continued improvement in customer activity overall, and this is beginning to be reflected in the total number of working rigs and a degree of stabilization in contract backlog across our peer group. In the U.S.

Gulf of Mexico, we recognized little change from our last call. Jackup requirements are likely to remain flat, and floater demand's still expected to pick up slightly towards the end of the year, albeit with predominantly short-term programs.

In Mexico, though activity will be rising, the successful operators in shallow water lease Round 1.2 have already awarded work to contractors and commenced drilling. Most of the tenders deepwater Round 1.4 would generate will manifest themselves in 2018, with work likely to commence in 2019 and beyond.

Looking ahead to shallow water Round 2.1, 26 operators have been prequalified to 15 blocks, with water depths ranging from 30 feet to 1,650 feet, which is good news for the medium-term outlook. As we look to adjacent countries, the Central American rig market seems to be improving generally.

Short-term work is increasing off the northern coast of South America, with operators moving forward on drilling projects in countries such as Guyana, Suriname, and Trinidad. Petrobras' activity remains muted, but tendering activity and general interest in floating rigs from international E&Ps in Brazil has improved since early in the year, but with most programs having a relatively modest duration.

In the Eastern Hemisphere, inquiries are trending higher for West Africa, the Mediterranean, and Europe generally. We're still seeing limited near-term growth potential in the North Sea.

However, there is a noticeable increase in operator optimism and a general view that the North Sea has bottomed. While there has been a clear uptick in visible rig demand, as evidenced by numerous market surveys and tenders that were issued in the first quarter, we believe the strong interest levels shown earlier this year will taper back in the near term as operators prepare for the Northern Hemisphere winter and contemplate 2018 drilling budgets.

The Middle East has continued to show a relatively strong increase in activity, with most national oil companies moving forward with planned projects. In the near term, we still expect day rates to remain generally flat but anticipate an increase in contract durations.

Qatar remains the most active country in the region, with the recent removal of a self-imposed moratorium on new gas developments and four new term awards expected in coming months. In Saudi, two tenders are being issued for multiple rig years of work commencing in 2018.

Finally, in the Asia Pacific region, we have seen a definitive increase in tendering activity. With regard to the contracts that are currently being awarded, we see short-term work for jackups as a continuing trend and expect to sign throughout 2017, with the rates generally flat for now.

Importantly, the fleets of the indigenous drilling contractors in Malaysia and Vietnam are approaching full utilization, which will allow international contractors like ourselves to access new opportunities in these important regional markets. I now want to review the status and prospects for our floating and jackup rig fleets.

Among the floaters, four rigs are on a cold-stacked mode, and we are not actively seeking work at this time for these units. As noticed in our latest Fleet Status Report, we've also moved the Noble Bully I to a cold-stacked posture following completion of the rig's five-year term contract in mid-March, consistent with our disciplined approach on balancing near-term market exposure against OpEx considerations.

Three other floating rigs are in warm-stacked mode, including the Noble Sam Croft and Noble Tom Madden in the U.S. Gulf of Mexico, and the Noble Clyde Boudreaux in Asia.

All three rigs, and the hot-stacked Noble Bob Douglas in South America, are chasing work in and around their respective locations, and we are increasingly confident of securing contracts for some of these units prior to the conclusion of the year. We are especially encouraged by the prospects we have for the Noble Bob Douglas in light of the exceptional performance it has just delivered to its last client in an exciting basin.

Although the Noble Globetrotter II is now stacked and receiving a day rate of $185,000 per day, as per our amended contract with Shell, the rig has several maturing options for additional work, and we are well-placed to secure incremental contract revenue under a contract with another operator in the latter half of 2017. And finally, in our jackup fleet, we ended the first quarter with all 14 units contracted.

And this should be the case until mid-2017, when the Noble Houston Colbert is expected to complete its current contract offshore Qatar, followed in August by the conclusion of the near-term charter for the Noble Mick O'Brien offshore the UAE. The Middle East remains a highly resilient region, and this fact, along with the excellent performance of these premium units, informs our belief that additional work for both rigs can be secured in a timely fashion.

As I mentioned earlier, the Noble Tom Prosser will be relocated back to Australia for what is initially an estimated 60-day program. However, we're evaluating other emerging options in the region and believe that we have a strong competitive position for securing ongoing work, although it may come in small parcels.

That concludes my comments, and I'll now turn the call back to David.

Okay. Thank you, Simon.

I've noted on several occasions the solid industry position that Noble enjoys by virtue of our premium fleet; our excellence and consistency of our operations, which we demonstrated once again with the first quarter results; and our contractual backlog, which is on the rise. I'd also call your attention to our dramatically reduced capital expenditure requirements, with no pending cash requirements for undelivered newbuilds, our positive free cash flow before debt repayments, our robust liquidity position, and our manageable debt maturity profiles.

Finally, you should note our continuing success in securing drilling programs for our fleet, which continues to enhance our excellent contract coverage. In 2018, our current contract coverage is already expected to provide gross revenues of more than $840 million, while in 2019, the current contract coverage should support more than $650 million in revenues, driven largely by the operations of only seven rigs.

We almost certainly will be working more rigs than that, and those revenues that grow will continue to add to our backlog. Keep in mind that today we're working 19 rigs.

More important, and as Simon stated in his commentary, we believe improving conditions in the offshore drilling industry are becoming clear. We're not alone in seeing the early stages of the industry improvements, such as the increased frequency of contract awards, especially in the jackup sector; numerous customer tenders currently outstanding; or the increase in field development decisions, as our customers report improved economics resulting from successful project cost rationalization.

Although oil prices remained range-bound during the early part of 2017, we continue to believe long-term oil market fundamentals are supportive of stable to higher crude oil prices. And this, together with the enormous potential that continues to emerge offshore, will support an increase in offshore rig demand over time.

Noble has navigated this industry downturn with skill, but it's imperative that we stay true to the structural pillars that have enabled us to establish our current position. In addition to a continued commitment to superb operations that are safe and environmentally sound, we'll remain focused on securing utilization for our active and warm-stacked premium assets as we build on our early successes in the year.

Also, further cost management initiatives will aid in the preservation of our operating margin, which is currently supported by a high level of activity in our jackup fleet, along with a solid base of operating days in our floating fleet, which includes four long-term contracts. We're confident better days are ahead for Noble and for the offshore drilling industry, and we look forward to reporting additional operational and financial accomplishments as we reinforce our excellent competitive position.

With that, I'll thank you for your interest in Noble, and we'll now turn the call back to over Jeff to take some of your questions.

Okay. David, thank you.

And, Carol, let's go ahead and pull together the queue for the question and answer segment of the call. And while you're doing that, I'll remind everyone, since we're going to conclude the call at the top of the hour, if you could please address one question and one follow-up, we'd greatly appreciate it.

Thank you.

Yes. Thank you and good morning, gentlemen.

Morning, Greg.

Hey, David. So, as we think about the market – I mean, clearly, when oil prices go lower, it always brings in the question about the liability or the timing over the return into the offshore drilling market.

But just as you think, as where contract drillers such as yourself fit into this equation, realizing that over the last two years, the industry as a whole has done a great job of getting costs down. As you sort of look at the next, call it, 12 to 18 months, what else can Noble do to sort of get its costs down?

Is integrating better with other suppliers a solution? Just curious how you're thinking about what else Noble can do over the next 12 to 18 months to make at least itself more competitive in this market?

Thanks, Greg. I'll take a stab at it, and if one of the other guys has something to offer, I'll let them chime in as well.

I think the industry is surprised, or observers of the industry are surprised, at how far and how fast we've been able to bring our cost down from what it was at a peak in 2014 and moving on. We continue to look for ways to bring our cost down.

We continue to be much more, I would say, dynamic in how we make decisions about stacking rigs, reducing costs every chance we get when a rig goes down. At this point, there will always be, and we'll continue to push on, things that will drive our normal operating costs down.

But largely, going forward, it's going to be a function of operating days. The days the rigs are going to operate, you're going to recognize fulsome operating costs, and the days they aren't, we'll able to get to those lower idle rates faster.

But there are incremental things we can do. I mean, there's a lot of talk around the industry about shared services and stuff.

We've been in this business 96 years. We've done everything from turn-key to full-day work and everything in between.

We're already providing additional services for our customers that a year ago or two years ago they were hiring third parties to do. We're continuing to look for ways to collaborate.

We're providing, in some cases, data, in some cases additional services. In some cases, we are having conversations and collaborating with other vendors to provide things.

So, there's a lot of talk about it. This is nothing new.

We've been through this before. We provided the full range of services to our customers and certainly have that capacity to provide a lot of those services again.

So anything that we can do to, (a), position ourselves for the work; and, (b), deliver a higher percentage of the cash flow through the system, we'll do. I think you should take heart that even as we're – sit here today, we delivered about a 55% margin on our revenues, which is – I haven't seen how everybody else did, but is pretty good against the group.

And that's something that Noble's always done. So we'll continue to push on our margins.

We'll continue to drive as much cash through the system as we can, and we'll push on everything. So shared services, additional efficiencies, and things that we can do in house.

Things that we can control, we'll continue to push hard. I don't know if the other guys have anything to -

What I would add is that we're sort of articulating an approach to this topic, which we call Noble OneSite. And I would add that we also see a lot more value in areas where we can deploy a disruptive technology, where we can reduce POB on the rig, where we can reduce the total number of service companies at the well site, where we can change the CapEx-OpEx bargain and achieve value for both the client and also for our shareholders.

But we're focused on true well site integration, rather than the integrated services concept that was peddled in the late 1990s and is somewhat discredited. Simply shifting the costs from the operator to the contractor or having the contractor subcontract a service that was previously provided by the operator doesn't really do much for anyone.

It's about really identifying value where both parties can benefit and exploiting that.

Okay, great. And then just looking at the jackup fleet, I mean, clearly you guys have done a good job of keeping those rigs busy.

I mean, yeah, there's a couple jackups that sort of roll off contract this year. But, I mean, just as we've seen sort of jackups, I guess, in the sale and purchase market start to change hands a little bit, just given as successful as you've been with keeping your jackups busy, is Noble looking at or exploring the potential of adding some jackups to its fleet here in the sort of near-medium term?

Greg, I would say we as a company always have an oar in the water. We're always looking.

The company really was built through M&A and acquisition of rigs. It's only in the last few years that the newbuild profile has taken leave.

So we're always looking at what's out there. I would say that one of the hallmarks of our fleet now is the age and the technical capability of the fleet.

So, yes, we're looking at jackups, we're looking at floaters, we're looking at opportunities for broader M&A. All of those things are on our radar screen.

I would say just in a one- or two-rig acquisition mode, either something that we don't have that provides a service in a market that we can't otherwise access or something that looks like what we've already got is what our preference would be. So first thing is anything we can make money with.

We don't want to buy something that creates a hole that we pour cash into. So something that creates an opportunity for us, we're certainly looking for those opportunities.

I would say that one of the reasons our jackup utilization is so high – and we're very pleased with our rate production; I think we're still one of the few guys still reporting most of our rates through the Fleet Status – is the quality and technical capability and the service that we can provide with the fleet. And so just adding more rigs just for the sake of adding more rigs doesn't necessarily improve that story.

So – but, yes, we're interested in adding rigs, and we're interested all facets of those opportunities.

Okay, guys. Hey, great.

Thanks for the time. Have a great weekend.

Thank you, Greg. You, too.

Thank you.

Hey. Thank you.

Simon, you mentioned opportunity for Globetrotter II later this year. If I recall correctly, your standby rate from Shell, the $185,000, you get to keep in addition to whatever work you might get on top of that.

So this would effectively allow you to double-dip on the day rate if you secure work for that. Is that the correct interpretation?

Yeah. That's correct, Ian.

Any revenue that we earn for work secured in that standby period is certainly incremental to our earnings profile.

Okay. That would be good.

And then can you update us on where you stand with regard to your expected reactivation parameters in terms of expense, maybe capital expense and timeframe, when you look at rigs like the Madden and the Croft in hopefully a recovering market, at least for seventh-gen assets in 2018, and maybe contrast that with a cold-stacked rig like Bully I.

So, yeah – this is David. I'll take that one.

I mean, the cost of reactivation, when you're talking about reactivating the Croft and the Madden, both of those rigs have – the marine systems are all hot. As we talked about, some of the drilling systems have been preserved, but those rigs are in a position where we can put to sea in very short order, so they meet safe manning requirements generally speaking and can move in short order.

And so all of the ship systems are hot and available and ready to go. So, when it comes to the cost to reactivate the rig, what you're really looking at is full crews for some period of time and the cost to reactivate the drilling system.

So we're not talking about tens of millions of dollars. We're talking about some expenses around however long it takes to assemble the crew, have them onboard the rig, which will come in stages.

We'd probably have a drill crew show up first, then a larger roustabout crew, then the rest of the drill crew and bring it in stages. So we would stage in the expenses.

I'm not going to give you a number, but it's really basically OpEx. There may be some capital that's required.

It's not going to be extensive at this point. It's going to go to annual hoisting surveys and other things that we might not have been able to do because that particular equipment has been pickled or something of that ilk.

So, again, it's some rig expense and some, I would say, minor manageable capital. That compares to a rig that's cold-stacked, say the Day or the Adkins, where those rigs have been fully preserved.

We pull the thrusters off of them. They are set on bottom at Ingleside with overburden, so that they won't move in the event of a storm.

Topsides have been preserved. The dehumidifiers have been put into the ship spaces, and a way to deal with water has been developed.

So, in there, you're talking about crews, some definite deferred capital, some cost with some probably some weather sensitivity to move those rigs offshore, to reinstall the thrusters. And so you probably are talking – I'm not going to say what a number would be, but it's not $50 million, but it's probably not $15 million either.

Probably somewhere in between that, and that's going to depend on how long the rig sits where it is. Certainly, the faster we get to it, the lower that number is going to be.

Actually, probably if we got to it really fast, it might be closer to $15 million. But I think that's probably the best guidance I can give you on those.

Much of what goes into the cold-stack cost is not additional capital. It's regular maintenance CapEx that becomes deferred.

And so it just builds – the BOPs, in the post-Macondo world, have to be recertified every five years. If you pass that date, then you've got to recertify those BOPs.

And so there are – it's the deferred maintenance that you start to accumulate that builds up. Frankly, once you hit that number, it's not going to get a whole lot bigger.

Okay. That's helpful.

Thanks, David.

Sure. Thank you.

Hi. Good morning.

I just wanted to ask, maybe – you've been talking about rising tendering activity for both floaters and jackups. Can you maybe just comment on the firmness of that tendering activity, especially beyond the context of Brent being south of $50?

What are the risks that you see there? Is it delayed award timing, or is the start-up of these tenders sufficiently out in time that maybe it's not as impactful?

Or just some color around that would be good.

Yeah. Well, obviously, we're not in position to determine whether a tender results in a contract award until it does.

So what I would say is that we've said on numerous occasions now that the trend is positive and accelerating. So we'll have to wait and see what results in terms of firm contract awards.

But in regards to your point about the day rate range, it has been somewhat range-bound here in recent weeks. However, most of our clients have spent a huge amount of time over the last two years rebuilding their price books.

Most of the projects they're looking at now fly at thresholds that are well below the numbers that you mentioned. And they take a long-term view.

They don't dart about in response to short-term oil price movements. Really, they're looking through that into the medium term.

They simply can't respond that quickly. David, I don't know if you have anything -

Yeah. I mean, I would say that – not to – I mean, we have great customers, generally speaking.

They're not that nimble to respond into short-term swings, particularly to offshore developments. So they're not looking at the oil price today.

They're looking at the deck out into the future. And so I would say, generally speaking, once the budgets are approved and the projects are started, by the time it makes it to the bid level, most of these projects have enough momentum that they'll go forward.

Oh, all right. That's helpful.

And then I just wanted to maybe dig a little bit more on the Digital Rig solution with GE. Can you maybe just map out what we should expect over the next, call it, two to three years from that, as it pertains to kind of achieving that 20% cost saving on repair and maintenance?

And then is there any kind of investment that's been required as part of that partnership, or – ?

That's a great question. This is something we've been working on for a while with GE.

And the original investment is, I would say, de minimis and invisible to the investor. It's something that's part of our normal small capital outlay and then some expense that goes with it.

But that pales in what we expect to derive out of the benefit. So we would expect to start – the process really is building of digital twin of most the equipment on the rig or effectively all the capital equipment on the rig.

That's going to take some time. But through that, we would expect within a year to start seeing some benefit on the four rigs that we've piloted it on.

In terms of our ability to – instead of changing out equipment or doing maintenance processes and procedures at a certain number of operating hours, we can extend some of that into – and be more definitive about when that equipment actually needs it rather than when we're responding to a failure or doing it because of just rote process. So I think that the numbers that we've laid out in terms of what we expect to be the benefits of it, I would expect that we wouldn't throw those numbers out to you unless we had a high degree of confidence that we could achieve those, so I would expect that we would hope to be able to achieve higher than the 20% savings on the operating cost.

I also expect that, in time, we'll be able to manage much of our onboard maintenance much like we manage our BOPs, in that we have a shore-based hit team that goes out to do major work on the BOPs. Every time a BOP hits the beams, we send a crew in from shore base to tear it apart and go through it.

And it's one of the reasons I think that our uptime on our BOP – our subsea systems – is so good right now, is the way we're handling that. We would like to see the same development in time with other rig maintenance features to be able to reduce our onboard crews, which is where the real savings is.

And so change is hard in this business, but the ability, this data – the data is there. The sensors are there.

The ability to work with somebody like GE Marine in this, to be able to collect and use the data, is something we're very excited about. And so I would say that the investment really is de minimis in terms of the global project of what we have.

It's in the numbers that are already in the company. So don't want to say too much about what we've done, because I don't know that anybody else is doing what we're doing.

I don't think anybody else is doing it. So I don't really want to say too much about the commercial aspects, except we expect to see real efficiency gains as we move forward through the next couple years and would apply this to the rest of the fleet.

And, Simon, you got anything to add to that?

Oh, look, I'd just confirm David's comments that the potential for this to be truly disruptive to our cost base is certainly there. The gains share (47:16) approach that we've developed with GE's Marine division confirms that.

So there's cost savings, reduced downtime outcomes, but I think one interesting element that hasn't really been commented on much is the potential impact on drilling performance that may result in the longer term. We've spent a lot of time here developing business intelligence scorecards that monitor performance in real time across the fleet.

So guys on different crews and on different rigs can see what their counterparts are doing to create an environment where people are continuously looking at, adjusting, and improving performance. So you couple that with a more sensate data-gathering capability across the fleet, and you start to have the beginning of an approach to the business that's truly transformative.

So I think we're witnessing the beginning of a step change in how offshore drilling rigs operate and how they're managed.

That's great. Appreciate that color.

Thank you.

Thank you.

Hey, guys, good morning.

Good morning.

Hey, Eduardo.

Hey, Simon, I think this one's probably more for you. Just curious, you talk a little bit about the tendering picking up and may be even some more contracts with a little bit more term.

I guess that may be especially more true in the jackup market. Obviously recognizing that you guys have been pretty transparent with your rates, when a lot of your peers haven't, we obviously have some more perspective.

But if we can think and hope and pray that we are on the upswing here and you do start getting some more work, can you talk a little bit about your views on – obviously we're at a day-rate trough right now. As you go out and to the extent you sign stuff that's maybe 18, 24 months and maybe it doesn't start till next year, are you able to have some optionality in those contracts to upside in rates, or is that something customers will just tell you no, I mean, the rate's at the floor and that's what you're going to earn on that rig for two years?

Or how should I think about the overall dynamics as you go to bid for some of this work that maybe will keep some of these rigs occupied out for a couple years?

Yeah, certainly. Look, you're quite right.

I mean, in the current environment, there is a risk of going too long at very low rates. So we've discussed a number of different options with our clients: oil price links for some upside, stair-step right profiles, improve through time on calendar renewal points, et cetera.

And performance upside as well, whereby if we can demonstrate that we have made meaningful improvements in their anticipated budget outcomes, then we share some of that. Generally speaking, spot rates at the moment are at or about cash operating costs.

And it's not really a mid-cycle investment level of income that contractors are earning. So I think that the client base increasingly realize that a positive way of engaging us and ensuring that people focused on performance and not cost is to give people the opportunity to earn a little bit more revenue on the come.

So, yeah, we've had a number of those conversations. I believe that they will continue.

But I wouldn't want to overstate the revenue impact of that. It's at the margin rather than a material difference.

Got it. Thanks.

That's helpful. And I guess this one would also be for you.

I think the Bob Douglas – I think that program ended up being just a little bit over a month or five weeks or something like that. I think originally it was slated to be a little bit longer.

Just curious if there's some perspective there, if that was something – was that just the rig was that much better than the client expected? Any color there?

Because I think we were a little surprised to see it roll off after, I think, only about five weeks or so.

Well, I think everyone except for our operations guys were surprised by how quickly we got through the well. So they did a fantastic job, the crews onboard the rig.

I think really it's a testimony not only to the operational performance at the well site, but also our developing approach to how we plan wells. The NobleAdvances center, which is our latest-generation training facility out here, we utilize that in part of a deeply immersive approach to how we plan the well to identify and mitigate unplanned events that might occur in the course of a drilling operation.

So that was an integral part of that preparation. And I think that, together with just a really good understanding between the client and ourselves, resulted in great communication levels and outstanding drilling performance, as you saw in terms of coming in well under budget and AFE.

So, yeah, we're excited about that, and we think that it places us very well in terms of near-term performance delivery for some of those other opportunities that we see in that basin down there.

Okay. The rig is going to stay there for now, right?

It's just available in the region?

It's in the region, yes.

All right. Thanks.

I'll turn it over.

Thank you.

Hey. Good morning and thanks for taking my question.

David, I believe you mentioned there could be some amicable settlement around Paragon. Could you provide some color around that?

Are we talking monetary or something in kind?

No, I really can't provide any color about that. I think the usual way this will be done would be some of kind monetary settlement.

But they've just filed their plan. We've had a dialogue with them.

We were hopeful that our ability to support them in the Mexican tax regime was something that would be applicable. But in the final analysis, they have filed a plan that doesn't require that.

And so it just effectively become irrelevant to their core plan. So we're happy to have a conversation, and if we can we'll look toward some kind of settlement.

If we can't, we'll defend it.

Okay. Fair enough.

And in terms of just a signpost, what are the next signposts or timelines we should look for related to that?

For the Paragon transaction?

Yeah.

I think it's an ongoing progress. I think we're kind of early in the game.

I think there are some hearings to be held on their part in short order, within the next 30 days or so. So we'll see.

I mean, I can't give you a timeline of how long this might take. We're certainly ready, willing, and available to have a dialogue with them anytime.

Okay. And just a quick question for Adam if I may.

You mentioned some demobilization revenues in fourth quarter 2016 which did not occur in first quarter. I didn't catch, if you said how much that was.

It was $3 million.

Okay, so not a big amount. All right.

That's all for me. Thank you, sir.

Thank you.

Hello, good morning. I just wanted to delve in a little bit deeper, if I may, on the OpEx progress that you've been making.

Can you give some color on the sort of proportions that are coming from the mix issues, more jackup activity relative to floaters that was mentioned in the release, and then obviously the cold-stack decision? And how much is, if you like, the secular trend of the underlying internal improvements you guys have been making?

And then perhaps take that a stage further and talk to the guidance in the future as to how much is, if you like, internally driven as opposed to mix driven.

Wow. Okay.

So let me see if I can answer that as best I can. Certainly, the mix of assets – and I don't know what your model has for what it costs to operate a floater versus a jackup is.

But if you assume that it's costing $135,000 a day in the Gulf of Mexico to run a floater and your average cost of a jackup is $55,000 or $60,000 around the world, then obviously the greater proportion of jackups are going to drive your overall fleet daily operating costs down. Just the fleet mix is going to drive that number down.

And we're certainly experiencing some of that. And with as high as our utilization is on our jackups as a percentage of fleet mix, that's certainly a big part of it.

But in real terms our operating costs around the fleet for all classes of rigs have come down significantly, and that's come down through the company moving from a growth and a very fast-paced mode into a more of a slow, steady-state reduction mode where we're not working extras in the fleet, we're not training extra people, we're not buying spares well in advance in bulk. There's a whole lot of things that we're not doing anymore.

We pulled back a lot of retention devices that the industry had gone to, instead of giving raises at this fast pace, so pull all those back. In some cases, we've given some pay cuts.

But, I mean, it goes to travel, meetings, the staffing, everything. I mean, we push on everything.

So as what percentage comes from fleet mix and what percentage comes from other I can't give you any kind of granularity. We've cut – the fleet mix and operating days are certainly going to be part of it.

But if we see a rig in a market that is becoming idle and it is, because of technical features, not as capable as some other rigs we might have that are closer to the market, then that makes the decision to cold-stack that rig pretty easy. It doesn't mean that we're calling the market for the next two years.

It means that we can save a lot of cash by doing it efficiently and not waiting on the market to develop. So I would say we're making decisions quickly.

We're making hard decisions quickly, and we're making good decisions. So it's kind of all of the above.

The Bob Douglas we've kept hot because it is just completed a well and very successfully in a great market, in a place where there are new opportunities. We've kept the couple other rigs warm-stacked because we like the proximity of those rigs to other markets.

And so we're making decisions on each rig as we can. But we're making better decisions faster.

Yeah. I think the one thing I would add to David's comment is I think it would be incorrect to suggest that it's really just mix-driven.

I mean, I think the cost efficiencies we're talking about and the savings we're realizing are real, and you're seeing that, as he mentioned, in labor, repair, and maintenance. And so, there's no doubt mix plays a role.

But I think that what I'd highlight is the cost efficiencies are real. And then as we think about guidance going forward, continued focus on realizing those efficiencies, but so much of it's going to be activity-driven.

So the cost guidance we have out there assumes some level of activity. And to the extent there's not incremental work, we're still very comfortable that we'd be at the bottom end of the indicated range absent additional work.

So it's obviously, in this market, something we're very focused on.

That's very helpful. Thanks.

And just one follow-up that's sort of related. If I look at the CapEx guidance for the year, it's really come down very substantially over the successive guidances.

And perhaps some discussion of the drivers behind that. I mean, how much of that is a deferred maintenance sort of bubble that just gets pushed back in the planning to subsequent years, or how much is it just to do with the types – the stacking versus the active decision-making that's been going on?

Well, I would say – thank you for noticing. But I would say that the – I mean, we're not sacrificing our future to survive today.

We're not uncomfortable with where we are from a liquidity perspective. So – and we're maintaining our equipment.

You don't see the kind of performance that we just had on the Bob Douglas on a rig that's been neglected for the last year. So I would say that our maintenance CapEx and our project capital is a reflection of the number of rigs that are working and what we think it takes to keep them properly maintained, and in the forefront of our customers' minds for future work.

We're focused on getting work. We've come off of a multiyear, very heavy newbuild program where we were not only building new iron, but we were sparing up, largely from a subsea perspective and from a broader fleet perspective, into a newer fleet to make sure that we had adequate spares to be able to meet the requirements to rotate equipment in and rotate equipment out as we wanted to, say, if we wanted refurbish a ram preventer or triple ram preventer on a seventh-generation stack, we had spares that we could nipple one down and change it out instead of just dismantling the rig – taking the rig out of service.

So we've spared up. We're using those spares.

The company is very well-equipped with critical spares and other equipment. And it's something that we've been planning for, for the last few years.

So I would say that what you're seeing now is a steady state that reflects the condition of the market. As we put rigs back to work, I don't know that our maintenance CapEx will go up, except as a function of the rigs that are going back to work.

You will see some probably additional capital that's required to start up some of these rigs once they've been cold-stacked. It's one of the reasons that we're very comfortable – as I mentioned in my dialogue, we've got about $840 million or $850 million under contract already for next year.

Our guidance for operating costs this year is in and around $600 million. If we don't book any more time next year, our operating costs will come way down from that $600 million.

So it's a function of operating days and what we see. But our capital program is supporting the rigs we've got, and we're not sacrificing our future for today.

That's really helpful. Thank you very much.

Thank you.

Carol, we're just past the top of the hour, so we're going to go ahead and conclude the call. For those of you who have been left in the question queue, I will be reaching out to you later this morning.

Thank you for your participation on today's call. Please make note that our next call is scheduled for the morning of August 4.

That follows our report of second quarter 2017 results, which will happen on the afternoon of the 3rd of August, and we will confirm those dates as we get closer. Carol, thanks for your participation today in coordinating the call, and good day, everyone.