Good morning. My name is Christa, and I will be your conference operator today. At this time, I would like to welcome everyone to the Noble Corporation Fourth Quarter 2018 Earnings Conference Call. All lines have been placed on mute to prevent any background noise and after the speakers' remarks, there will be a question-and-answer session. [Operator Instructions] Please limit yourself to one question and one follow up. Thank you. I would now like to turn the call over to Jeff Chastain, Noble Corporation Vice President Investor Relations. You may begin.

Thank you, Christa, and welcome, everyone, to Noble Corporation's Fourth Quarter and Full Year 2018 Earnings Conference Call. We appreciate your interest in the Company. And in case you missed it, a copy of Noble's earnings report issued last evening, along with all the supporting statements and schedules can be found on the Noble website and again that's noblecorp.com. Before I turn the call over to Julie, I'd like to remind everyone that we may make statements that are not historical facts and are forward-looking. These 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 these include the price of oil and gas, customer demand, operational and other risks. Our actual results could differ materially and Noble does not assume any obligation to update these statements. Also note that 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 any associated reconciliation on the website. And finally, consistent with our quarterly disclosure practices, once our call has concluded, we will post to our website a summary of today’s guidance and that will cover both first quarter and full year 2019 figures. With that, I'll now turn the call over to Julie Robertson, Chairman, President and Chief Executive of Noble.

Thank you, Jeff. Good morning, ladies and gentlemen and welcome to our review of fourth 2018 results. I appreciate your participation in today’s call and your continued interest in Noble. In addition to Jeff, I am joined today by Adam Peakes, our Senior Vice President and Chief Financial Officer and Robert Eifler, our Vice President and General Manager of Marketing and Contracts. Adam will cover in detail the financial results for the fourth quarter and our thoughts regarding the expectations for 2019, and Robert will follow with a review of the Noble fleet and an assessment of global offshore regions and opportunities. This morning I want to begin with addressing our operational and fleet enhancement success from this past year which holds positive implications for 2019. These achievements were a result of the collective efforts involving focused team work execution from all organizational disciplines within the company. In 2018, we achieved record safety performance as the company’s Total Reportable Incident Rate or TRIR improved 11% from the prior record set in 2017. Our 2018 safety mark remains superior when compared to the average TRIR results for the offshore drilling industry. Additionally, from an operating perspective, downtime across the Noble fleet is only 2.7% in 2018 or stated inversely, we registered 97.3% of operational uptime. This achievement also represents a record result for the second consecutive year and it is most impressive that both the safety and fleet downtime results were achieved during a year in which we increased our active rig fleet by four rigs following the reactivation program and expanded our offshore headcount by 10%. These results demonstrates Noble’s strong culture of excellence as we continued to emphasize strict adherence to best operational practices and maintain our focus on top quartile performance. We are certain that these are the…

Thank you, Julie. Good morning and welcome to everyone. Noble finished 2018 on a strong note with fourth quarter results continuing the steady progress that began earlier in the year. On a quarterly basis, we set high marks for the year in fleet utilization, contract drilling revenues and EBITDA and this despite the persistent challenges our industry faces today. On a reported basis, the fourth quarter net loss attributable to Noble totaled $33 million or $0.13 per diluted share on revenues of $310 million. Included in the reported results was a again from the retirement of debt and a discrete tax benefit which together totaled $66 million or $0.27 per diluted share net of tax. With regard to the gain from debt retirement, we spent approximately $20 million in cash to purchase $27 million of principal amount senior notes with maturities in 2040, 2041 and 2042. This debt repurchase was done through a couple of small opportunistic open market repurchases during the fourth quarter. These favorable items were partially offset by a $9 million or $0.04 per diluted share asset impairment charge relating to the standard duty jackups Noble Joe Beall and Noble Gene House. Following the close of the quarter, the Noble Gene House was retired from service reducing the company’s jackup fleet to 12 units before the pending addition of the Noble Joe Knight. Excluding the net favorable outcome of all of these items, the net loss attributable to Noble for the fourth quarter would have been $90 million or $0.36 per diluted share. We have included a non-GAAP supporting schedule with our press release and the schedule can also be found on the Noble website at noblecorp.com. That schedule provides a reconciliation of non-GAAP numbers to net loss attributable to Noble Corporation to income tax provision, and…

Thank you, Adam and good morning to everyone. I’ll open today with some observations on the current state of the offshore drilling industry, provide an update on the status of the Noble fleet which continues to show meaningful improvement in activity and finally, close with an overview of regional developments and opportunities. Beginning in the fourth quarter of 2018, the effect of the drop in oil price has featured prominently in most discussions on the state of the offshore drilling industry. Following this short duration break down in price levels, some operators, primarily smaller ones indicated they would undertake reassessments of their 2019 upstream spending assumptions during the first quarter. As a result, we have seen some cancellations and delays in 2019 well programmed primarily in the floating sector. However, it’s our belief that while these changes will have some negative effects, they won’t be significant, especially in relationship to our own fleet marketing efforts. In fact, jackup contracting activity is continuing at a very strong pace and floater activity remains active as evidenced by the numerous tenders outstanding to fill floating rig needs across the globe. Noble’s experience has also been encouraging with contract days added in January for our floating rate fleet and important opportunities emerging for our jackups. I’ll have more to say on our fleet in a moment. We believe our industry remains in early stages of recovery and any adverse impact stemming from the late 2018 crude oil price volatility should prove to be short-term in nature. We have already witnessed a swift recovery in the price of Brent office December 2018 low of $51 per barrel. The international benchmark rose to an average price of $60 per barrel in January 2019 that has remained above this average through February. The return to a sustained…

Thank you, Robert, and Adam for your insights. As we work through the early days of 2019, I am encouraged by what Noble can accomplish in this New Year. I agree with Robert’s conclusion that in 2019 we will continue to see a competitive environment, but as I noted earlier, I believe, actions taken by Noble in 2018 places us in a truly favorable position to compete in 2019 and beyond. Our rig reactivation projects have gone well with each of the five reactivated units currently contracted, even better, new contract opportunities are becoming increasingly visible keeping a number of these rigs contractually engaged well into or beyond 2019 as evidenced by the recent contract award to the Noble Tom Madden in Guyana and expected contract extension for the Noble Clyde Boudreaux offshore Myanmar. I also believe our global rig fleet distribution advantageously positions us for a growing number of contract opportunities in key regional pockets of strength. As we noted earlier, our jackup fleet is highly consolidated into the North Sea and Middle East regions or 11 to 12 units will operate following the deployment of the Noble Johnny Whitstine and the Noble Joe Knight. Both regions have numerous customer needs outstanding that define the prospects for visible work into 2019 and beyond. Availability and our marketed premium floating fleet is concentrated in the Western Hemisphere where enormous resource potential is driving heightened exploration interest and multi-year development opportunities. We have already established a leading presence in some regions such as Guyana with other attractive locations including Mexico, Brazil and Suriname. We began this year with a higher percentage of operating days into contract. On January 1 of this year, 75% of our jackup days and 49% of our floating rig days were under contracts as compared to 53%…

Okay. Thank you, Julie. Chris, we're ready to go ahead and begin the Q&A session of the call. So if you would assemble the queue and identify the first caller please?

Certainly. [Operator Instructions] Your first question comes from the line of Kurt Hallead from RBC. Please go ahead.

Hey, good morning.

Good morning, Kurt.

Okay, thanks for all that detail and color. So I am going to – my question kind of focus on the floater market here. So, when you look out into 2019 and even beyond 2019, and you assess the new demand that’s out there in terms of contracts. Can you give us some general sense on what the mix is between exploration and development?

Sure. Kurt, this is Robert. So, we are seeing most of the longer term demand that’s out there which pretty focused on is development work. There have been a few fairly notable exploration successes here, last year, especially in the last part of last year. So we’ll have a percentage break down in front of me. I think that the important trend is that exploration focus has steadily improved over the last year-and-a-half or so on the floating side.

Okay. I appreciate that color. Now second - the follow-up question I had then for you was given the backdrop with respect to improving demand, can you give us some general sense on how you are thinking about the rigs that you have that are idle in terms of do you think, how many of those rigs do you think that could be activated in 2019? And what the potential costs are to activate those rigs?

Well, Kurt, we’ll start with the floaters, just we will pick those first. We would love to reactivate obviously the Danny Atkins are very capable units, lot of foot load capacity, lot of size, those are unique drilling assets which customers are willing to work. Reactivation cost for those would be somewhere between $50 million and $100 million. We could easily add more and as you know, those are BP 3 units, but we could easily add more into those units to make them attractive in certain regions. But we think those have a great potential to get back to work in the right markets. The Paul Romano is currently warm stacked. It came on contract not long, but all we think that rig has a lot of potential of going back to work soon. We are bidding that on lot of opportunities also.

Just add the Bully I.

The Bully I.

We are in probably – well, certainly not a 2019 event for that rig. But we are focused with Shell on discussing what sort of long-term opportunities may exist putting that rig into either a different region or into a slightly different usage. And so, we are in lot of communication with the,

Yes. Kurt, this is Adam. In addition to Julie and Robert’s comments, I think it’s important to point out that the guidance that we provided for 2019 does not contemplate any reactivation around the Danny Atkins or the Bully. As Julie said, we continue to think those are strategic assets that are going to have a nice future, but we are going to be really disciplined in how we think about bringing those out of stack and I think as we – Julie outlined the cost profile to bring those back, as we sit here today, that’s not contemplated for 2019. I think we continued it to need to see an improving market to feel compelled to do that and specifically, anticipating a follow-on question. I think, to make that decision to reactivate any of those rigs, we would need to have a contract with a substantial payback on that reactivation capital. And so, we are ways away from doing that. It will be a high-class problem when we get there. But that’s not contemplated for 2019.

That’s awesome. Thanks. Appreciated.

Thank you, Kurt.

Your next question comes from the line of Ian MacPherson from Simmons. Please go ahead. Ian, your line is open.

Sorry for that.

Ian , are you there?

Yes. I am sorry. I couldn’t hear you called my name and I apologize my extension has been divided with your call So I apologize. But I wanted to ask you, Robert, if you address the outlook for the Boudreaux rollover and what the prospects are there for next work and how we should think about any gaps that $1.2 million after next month? And then, I separately wanted to ask the Joe Knight contract broadly resembles what you got for the Whitstine. I assume that it does. I just want to confirm that or maybe comment if there is anything materially different about the economics on that deal. And then, just if there is any scalability or keepability of those two jackup bolt-ons that you are looking at that we should think about? That’s it for me. Thank you.

Sure.

Sure, thanks, Ian. On the Boudreaux first, we – the customer does have options on that rig and it’s little too early to talk about the outcome there. But we do anticipate that that rig stays active throughout 2019 and without any gaps in the region. On the Joe Knight, the contract construct and the economics are very similar as they were with Johnny Whitstine. And in terms of scalability, I would say, we think about market share in the Kingdom and we made those purchases to maintain scale and market share in the Kingdom. I would not say that we are interested in expanding through similar purchases at this time. But we are very happy with the two we’ve made and that we are able to put those into long-term contracts with an extremely important customer of ours.

Thanks. And I would say, well done on both of those as well. Thank you, Robert.

Your next question comes from the line of Scott Gruber from Citigroup. Please go ahead.

Yes, good morning.

Good morning, Scott.

Adam, you quoted about a $100 million of spend for projects this year, about $30 million for Subsea spares, no reactivation CapEx. How should we generally think about spending on projects and spares beyond 2019? I realize the project spend can be lumpy and is a good portion of hits reimbursables. But just assuming the current fleet composition, assuming the reactivation, kind of what’s a reasonable figure to these buckets beyond 2019?

Yes, Scott. Thanks for the question. I think it’s important to frame that. As we think about our needs and what that means from a CapEx budget standpoint, for a fleet our size, regular sustaining capital plus the inevitable projects you have year in and year out would be about $150 million for us annually. So, I would think about that as a starting point for capital budget. So absent doing anything, reactivations or spend around repurchase – or purchases of rigs et cetera, we’d be kind of right at 150. And so, the increase you see this year is driven of course by the rig purchases and the ready to drill spend associated with that as well as reactivations. So, I would think about as going forward in a regular year by 150.

Got it. Appreciate it. And then the North Sea market has been tightening for a bit of time now. Are you starting to see any inflation on your North Sea cost and is t here inflation protection in the contracts?

We do not have inflation protection in any of our current contracts. But we have also not seen any meaningful inflation in the regions either on the labor side or on the equipment side.

Is that that a risk you see going forward as you starting to push for cost inflation protection in places like the North Sea?

So, I would say, when we are thinking about longer term contracts, yes. That’s on our list. In the North Sea, I think we are less concerned about inflation there right now. We really haven’t seen it. In fact, I think prices there have surprised – excuse me, cost there have surprised on the low side. And I just point out of course, we are operating in essentially the non-Norway sectors there. So, I am not at all speaking to the Norwegian sector. But in that sector, Denmark and the UK, we are pretty comfortable with our cost structure there.

Got it. That’s it for me. Thank you.

Your next question comes from the line of Sasha Sanwal from UBS Securities. Please go ahead.

Thank you and good morning.

Morning, Sasha.

Yes, maybe for the first you kind of touched on this in the commentary. But just wanted to see if you could get some of your thoughts on leading-edge pricing for floaters for programs starting in 2020. And then, Adam, just with the Danny Atkins, you kind of preempted this question, but would it kind of be fair to say that be really need a dayrate north of kind of $250,000. Would you guys really seriously think about bringing those rigs back?

Sure. So, on the first piece of that, there isn’t a clean fixture for anything that starts in 2020 just doesn’t exists right now. So we are watching that closely as everyone that follows the industry. Certainly, in our bidding strategy, we are looking for higher prices for anything that starts out in that time period and at the same time we are analyzing potential for some sort of indexing type mechanism that would help bridge a gap to get us there, because there exists a wide range of opinions on where rates might be a year or more out right now. So, the market doesn’t exist today on just a clean top-tier drillship fixture in my opinion. And so, I think everyone still wait and see.

Yes, with regard to the Danny Atkins and what kind of environment we need to reactivate those. I wouldn’t want to peg it to a specific dayrate other than to say it needs to be substantially above where rates are today. I wouldn’t have an issue with the $250,000 that you threw out as a good number as any. I think more than anything else, we are just trying to make clear that our appetite to take risk there is not there today and we would – whether it’s been rate on a shorter term or a longer term contract, we would need substantial payback and visibility to recovering all of that ultimately in a fairly short period of time before we’d undertake that kind of spend.

Great. Thank you. That’s helpful And just as a follow-up, I guess, kind of following the purchase of the Joe Knight, just want to think if not on just what – on what further optionality it might be out there for similar acquisitions and just how that might fit into the capital allocation priorities for 2019?

Sasha, as we said earlier, we will continue to look at every opportunity that’s out there. As Robert noted in his comments or in his response to a question earlier, we are probably not going to look to duplicate exactly what we have done. It’s certainly not in this budget for this year. But we are continuing to look at every opportunity out there and if there is something that fits an opportunity that a customer is bringing up, so an opportunity that’s out there that we can match up to contracts, we will certainly look earnestly at it and find the way to get it done.

Okay. Thank you. I’ll turn it over.

Thank you.

Your next question comes from the line of Sean Meakim from JPMorgan. Please go ahead.

Thank you. Good morning.

Good morning, Sean.

So, maybe we could just talk on the drillships, have you been engaging more in direct negotiations versus open tendering? Just curious kind of how that mix is looking in terms of your discussions with your customers and are you getting any more progress in terms of customer willingness to reimburse promote fees? I am just curious if kind of at the margin, kind of those conversations are evolving in the last few months.

Sean, we’ve been likely to be able to deal with sometime, some operators obviously directly on direct negotiations. Obviously, that’s still improving the performance that we are giving for them. But certainly there are other opportunities, on what Robert add color to that.

Sure. I think the mix of tendering versus direct negotiations is definitely increased, especially if you look back over the past, call it 18 months, and that’s encouraging. On the mode side, a number of our recent discussions have included some sort of mode. And as an indicator, I think that’s probably today something closer to cost reimbursement than it is to some sort of recognition of loss revenue like it had been at the market high. But certainly, it’s encouraging to see that operators are now willing to contribute to get the right rigs into the regions where they were.

Yes. Thank you. I appreciate that. And then, just the follow-on then would be, thinking about rigs like the Romano, as that – as the market evolves and those opportunities shift a bit, does that begin to change your thinking or do you cast the wider net in terms of where you are willing to potentially send that rig or bidding that for projects or Gulf of Mexico has sufficient in terms of opportunities. So that seems unlikely you’d be willing to take those types of - you’d be searching for those types of opportunities further away?

Sure. So, I mentioned in the comments. The Romano is bid outside of the region, but not – I would say, not far outside the region. That rig has had a incredible history. One downside on the designs, as that they don’t turn very quickly and there are not a lot of heavy lifts to move them on. So, long way of saying that we think, certainly that the most likely future for that rig is in the U.S. or in the Caribbean. I’d note, there are not very many more rigs in the region, right now. And in fact, more - only rigs I believe were the only available unit in the region right now and so in that mid-water sector there is some demand and we are watching it closely and hopeful that something could produce itself during the year.

Fair enough. Thanks for that feedback.

Thank you Sean.

Your next question comes from the line of Taylor Zurcher from Tudor, Pickering and Holt. Please go ahead.

Hey, good morning.

Morning, Taylor.

On the jackup side, most of your jackups are positioned in the Middle East, in the North Sea which coincidentally are two of the healthiest markets in the world. And so, the question is, can you compare and contrast for us the different pricing dynamics you are seeing in both of those markets at least as it pertains to 2020 type start dates?

Yes, sure, Taylor. So, the North Sea has been ahead of the Middle East on pricing in our opinion and we saw and we are able to start moving prices there earlier. The Middle East is a more diverse environment for rigs, because you have a lot more demand for standard spec units in the region than you do in the North Sea right now. And so, pricing I think is wider in the Middle East. I will say that for a number of reasons, there has been a bunch of high specification jobs that have come up during the past year and specifically now, as we are looking at it. There are number of options for some HPHT work in a lot of the gas drilling in several different countries there. So, we have tried really hard to position, especially our JU 3000 class rigs into work that requires a higher level rig. And we are extremely pleased that in the Middle East those opportunities seem to be coming forward in great numbers. So, in those instances, there is a pricing disparity and we are getting some and hopeful to get some higher pricing on some of those more difficult jobs. It remains though especially with the tightening we are expecting in the North Sea in the 2019 that pricing is a little bit ahead in that region still today.

Okay. That’s helpful. On the floater side, I would assume that the full year 2019 revenue and cost guidance would bake in some healthy utilization for the Don Taylor which rolls off its existing contract I think in a couple months here. So, curious if you could just frame for us how you are thinking about following work prospects for that rig and how we should think about potential gaps beyond April for that rig?

And so we are chasing a number of different opportunities in the region. If you look at when that rig rolls, there really aren’t – I am not sure that there are any comparable rigs in the region available at that time. And so, we are pretty bullish about the prospects for the rig throughout the rest of this year. Now, there could be certain revenue gaps if we need to change customers. But those we are hopeful would be just transition gaps and that we will be successful in securing some good utilization through the remainder of the year. Same cost.

Got it. Thanks.

That’s probably the same cost Taylor, but I’d just add that rig has some options available to the client afterwards and we are hopeful that we are successful that the operator is successful in extending that contract. So, but that’s yet to be seen.

Thank you. That’s it for me.

Thanks, Taylor.

Your next question comes from the line of Greg Lewis from BTIG. Please go ahead. Your line is open.

Yes, hi. Thank you and good morning.

Good morning, Greg.

I guess, and this question is for Robert and Robert, I apologize if you have already elaborated on this earlier in the call. But I believe you mentioned that, clearly some of the volatility in oil prices has kind of shifted around some potential opportunities that you were seeing. But – so I guess, my question is, as you look at the landscape of opportunities out there today, could you sort of segment them out between like, what – how much of that work do you think is – that you are seeing is out there for 2019 versus how much of the work that is out there you are seeing for like 2020 and beyond?

Sure. The majority of what we – part of this is driven by our fracking test in our fleet, but the majority of what – of the discussions we are having right now are 2019 starts. There are a number of 2020 start opportunities out there. Some of them have existed for a good uptime right now. I am not aware of really conclusion to a lot of that, but certainly what we are chasing right now due to our availability is primarily 2019.

And that’s equal for both jackups and floaters?

Well, so, jackups, that’s a little bit different and again, this includes our contracting dynamics. But, we do have a number of 2020 opportunities on the jackup side right now, which I find pretty bullish considering the lead time for jackup contract is normally significantly stronger than on the floater side. But we don’t have a whole lot of availability – excuse me - during 2019. So, we are passing up a number of jobs that we’ve seen – or tenders, I should say, that we’ve seen. I’d note that kind of through the fourth quarter and 2019 so far on the jackup side, there seems to be a great deal of tending activity and unfortunately we have in the past a number of those just due to availability.

Okay. Great. And then, just one more on potential opportunities that are out there. At this point, I mean, clearly you guys are very successful in buying those two jackups from the shipyard. It looks like there were a couple other jackups that were sold this week from shipyards. As you look at the potential opportunities out there, at this point, are they primarily only coming from shipyards? And I guess, what I would ask on follow-up to that is, as you think about potentially doing some of these acquisitions, would Noble be willing to use its stock as currency in potentially acquiring some rigs?

We are willing, Greg, to look at all options. And yes, certainly if it makes sense for shareholders, we would certainly look at using stock for the right opportunities. To your first question, most of the opportunities are coming from shipyards right now. But, we are also looking everything and we are looking, we are willing to look at things that match up with contracts and looking at various options to be able to pay for those.

Okay guys. Thank you. Great. Perfect. Great answer, Julie. Thank you.

Thank you, Greg.

Your next question comes from the line of Eduardo Royes from Jefferies. Please go ahead.

Hey guys. Good morning.

Good morning, Eduardo.

Just a quick question. As we see more and more of these kind of very short-term deepwater contracts, maybe it’s one well - multiple wells on the back of that, I am just curious versus 10, 12 a year, or 18 months ago, if you are able to start negotiating firmer pricing increases at least on those option bids. I know it’s not a whole lot. I am not talking about rates doubling or anything, but some more willingness from the customers to say, yes, okay, if we do that next well, we have no problem paying x percent more or if that hasn’t really changed versus the troughs?

Sure. So, it’s been - I’ll say, at least one of our current contracts includes pricing increases in the option structure. And that was quite some time ago now. And I think the markets improved since then and our willingness today to consider price options has diminished significantly. And generally speaking, I think, we are less willing to give any sort of options on the floating space that would take us out into the kind of 2020 especially mid-2020 timeframe right now, as we see and are hopeful that this market firms up.

Great. Thank you. And just one quick follow-up for me. I know we are at the hour. Does the OpEx guidance for this year, Adam, include any sort of – is this an above average year I guess, from an SPS perspective or any small-scale stuff that maybe elevates that a lot. Obviously, there is a lot of rigs coming up on five years, all I know those aren’t huge buckets, but do you see some of your peers have slightly higher guidance and I think a lot of it is you add up a bunch of small things, whether it’s small projects or just SPS things that aren’t necessarily capitalized. Just wondering if that’s at all the case for you guys?

No, it’s really, Eduardo, in this case, nothing is significant to callout there. It’s not driven by that. It’s frankly driven by - we’ve got a whole lot more assets working. So we are going to be up in terms of rig operating days about 800 days year-over-year. So, it’s really that. Not some SPS or other funky stuff that might enter into the equation.

Great. Got it. Thank you. I’ll turn it back.

Christa, with that, we are going to go ahead and close today’s call. We appreciate everyone's participation today and your continued interest in Noble. Christa, thank you again for coordinating the call. Good day, everyone.

This concludes today's conference call and you may now disconnect. Have a great day.