Good morning and welcome to Noble Corporation's Fourth Quarter 2022 Financial Results Conference Call. All participants are in a listen-only mode. After the speakers' presentation, we will conduct a question-and-answer session. [Operator Instructions]. As a reminder, this conference call is being recorded. I would now like to turn the call over to Ian Macpherson, Vice President of Investor Relations. Please go ahead.

Thank you, Juliana, and welcome everyone to Noble Corporation's fourth quarter 2022 earnings conference call. We appreciate your continued interest in the company. You can find a copy of our earnings release issued yesterday evening along with the supporting statements and schedules on our website at noblecorp.com. Also, located adjacently on the website is the fourth quarter earnings slides presentation that we will make reference to during this call as well. Joining me today are Robert Eifler, President and Chief Executive Officer, and Richard Barker, Senior Vice President and Chief Financial Officer. Also joining are Blake Denton, Senior Vice President, Marketing and Contracts, and Joey Kawaja, Senior Vice President of Operations. For today's call, we will begin with prepared remarks followed by Q&A. During the course of our call, we may make certain forward-looking statements regarding various matters related to our business and companies that are not historical facts. Such statements are based upon current expectations and assumptions of management, and are therefore subject to risks and uncertainties. Many factors could cause actual results to differ materially from these forward-looking statements and Noble does not assume any obligation to update these statements. Please refer to our SEC filings for more information regarding our forward-looking statements. Investors should carefully read our previous and ongoing disclosure with respect to these events, including our press release issued yesterday and other filings with SEC. Also, note that we're referencing non-GAAP financial measures on the call today and you can find the required supplemental disclosure for these materials, including the most directly GAAP measure and associated reconciliation in our earnings report as well as our filings with the SEC. And with that, I'd now like to turn the call over to Robert Eifler, President and CEO.

Thank you, Ian. Good morning. Welcome, everyone. And thank you for joining us on the call today. I'd like to begin with some opening remarks and a brief update on our integration progress, and then provide some views on the market outlook and regional demand perspectives before turning the call over to Richard to review the financial results and outlook. Starting on page 3 of our earnings slide deck. 2022 was indeed a transformational year for Noble, culminating with the business combination with Maersk Drilling that has created a leading player in ultra-deepwater drill ships and harsh environment jackups. We're now approaching the five-month milestone since closing the business combination with Maersk Drilling, and I couldn't be prouder and more appreciative of our offshore and shore-based teams around the world who have made these first and most crucial few months of this integration go as smoothly as it has. To our employees on the call, we asked each of you to check your egos at the door and to heed the mantra of listen, learn and lean in. Well, that is exactly the response that we've gotten. And so, I'd just like to say a huge thank you for the tremendous effort and commitment that you've given. We still have work ahead of us, but we're off to a great start. Richard will speak more of the financial elements of this in the next few slides during his remarks. Now on to the market outlook. In short, the fundamental setup for our industry is arguably the best that it has looked in the past 20 years based on a confluence of macro supply and demand factors. Leading indicators on offshore project sanctioning uniformly point to a sustained multi-year upturn in offshore investment and rig demand. And our near term commercial…

Thank you, Robert. And good morning or good afternoon all. In my remarks today, I will go over some brief highlights of our fourth quarter results, provide an update on our synergy progress, go through our 2023 financial guidance and highlight a few key points related to our return of capital program. Starting with our quarterly results. The fourth quarter was our first as a combined company with Maersk Drilling. As such, the type of prior period comparisons that we typically reference have less relevance. So, I will dispense with the prior period comps for the purposes of this review. Additionally, as mentioned previously, we have included on our website a handful of earnings slides that summarize some of the key elements of our fourth quarter results. For the fourth quarter, which included 90 out of 92 total days as a combined company, our diluted earnings per share was $0.92. Contract drilling services revenue for the fourth quarter totaled $586 million, adjusted EBITDA was $157 million for an adjusted EBITDA margin of 25% for the quarter. Additionally, we generated free cash flow of $106 million in the quarter. As previously cited, the downtime and cost impacts of the Noble Regina Allen incident, as well as the delayed contract start for the Noble Globetrotter 1 in Mexico had adverse impacts on the quarter's financial results. And on a combined basis, these two weeks represented a $15 million decrease to Q4 EBITDA relative to our expectation. As we work through the closing for the first integrated quarter as a combined company, certain impacts from the merger, including accounting impacts from the purchase price allocation, have served to partially offset this negative impact. Noble's year-end revenue backlog stands at $3.9 billion. Page 5 in the presentation slides provide a summarized schedule of backlog…

Thank you, Richard. So to wrap it up here, we're increasingly confident in our outlook for a sustained multi-year upcycle for our business. It's a tight market today with structurally redefined supply governors that should drive further tightening as demand continues to recover from an unsustainably low baseline. We have an optimally positioned elite UDW fleet with an enviable backlog. And we're looking out into the future for fairly significant upside optionality from our jackup business, which is still under-earning and 2023. Noble will not deviate from our disciplined and conservative financial position and capital allocation framework. And we look forward to returning growing amounts of free cash flow to shareholders over the long run. Operator, we're ready to begin the Q&A segment of the call.

[Operator Instructions]. Our first question comes from Greg Lewis from BTIG.

Robert, I was hoping you could provide a little bit more color. Clearly, one of the big things that people are watching is the potential of rig reactivations. And you alluded to the potential about – we're looking at potentially – looking for that right contract or to reactivate potentially the Meltem. As we look globally, could you talk about some of those opportunities. It seems like most of the rig reactivations we're hearing about are largely focused around Brazil. And I guess what I'm wondering is, as you look at potential opportunities for the Meltem, how are you thinking about that rig and really where those opportunities potentially could be?

Look, I think the Golden Triangle is going to host the vast majority of the opportunities. And specifically, as you mentioned, Brazil and West Africa right now seem to be carrying the term that would be required. Whether it's specifically Petrobras or not is very much up in the air. Recall that to take a rig outside of Brazil into a Petrobras contract, there's a pretty hefty capital requirement. And so, as we said – I didn't repeat it in the script today, but we have said previous and we do hold to the idea that, where we sit in 2023, in the bids that we're considering, we would be looking to get a significant portion of that $100 million upfront, so that we can maintain our cash flow story, which I think is unique to Noble. So, realistically, in the very near term, I think those opportunities exist through the Golden Triangle. They're very few and far between. And today, more likely to be outside of a Petrobras contract than with Petrobras, but the market is moving. And I think as we move through this year, that could change. There are a very small handful of opportunities that could come up for 2024 and even 2025 work that would exist outside the Golden Triangle. But we're just maintaining a constant dialogue with customers globally. And I think I think you said my words for me, we're picking our opportunities very carefully and making sure it's the right opportunity for that rig.

I did want to touch on the jackup market. clearly, post the Maersk acquisition, you guys have a very solid position in the North Sea. That being said, it seems like at least in 2023, that's going to be a little bit of an air pocket not only for floaters, but also for jackups, which is what you guys were on in the North Sea. So, as you think about that and those dynamics, is it kind of a let's just kind of wait it out for 2024, which is expected to see some improvements, or could we think about maybe starting to try to find another base and where maybe some of these rigs could go to to kind of – for employment until we see that actual North Sea shelf recovery?

I'm not going to put any rule down here because we've always been, I think, pretty economic in how we think through bidding and potentially moving rigs. The change in windfall profit tax in the UK was a pretty major headwind that came through a few months ago. And it essentially put the market which does have some movement back and forth between the UK and Norway on its heels. And of course, we have a portion of our jackup fleet scattered out outside of the North Sea. The highest and best use for the units that we own is in the North Sea, whether it's outside of Norway or within Norway, depending on the unit. And we do believe that, ultimately, that's the right home for these rigs. So from current fleet positioning, we are not actively trying to remove rigs from the region. We are mindful of the whitespace in managing costs in the meantime. And I think, in particular, the Norway class vessels, we now have visible demand in 2024. It doesn't meet the total supply from what we see today. But it's also still too early on a sales cycle for even for CJ-70 to fully understand what the back half of 2024 is going to look like. And so, we stick to the view that late 2024 is going to bring back the demand for our CJ-70 fleet. Those are the most capable rigs, Norway class jackups. They will contract before and stay active longer than other Norway class rigs because of their performance capability. And they also have the ability to work in certain transitions and waters that would otherwise go to harsh semis. And that's very much a dynamic that's too early to conclude today, but does exist as a pocket of demand for those rigs in 2024 and onwards. So that was a bit of a rambling answer, Greg. I think to sum it up. Neither UK nor Norway class rigs, we are actively seeking to relocate. We will always remain economic, though.

Our next question comes from Eddie Kim from Barclays.

So very constructive outlook for the floater market, which would suggest that the day rates continue to move higher throughout the year. I need to start with a leading question, but do you think it's likely that we'll see a floater fixture announced later this year with a five handle? And how do you think about contracting strategy in this type of environment? Because I would think you'd want to maybe sign shorter contracts today in anticipation of higher day rates maybe 12, 18 months from now. And it may be the one-well contract for the Faye Kozack at $450,000 a day was evidence of that, though I might be reading too much into that.

Look, I think there's some things that have to fall in place. In the near term, I think we're actually going to see a bit of a wide range of fixtures here even among seventh generation rigs. You've got some rigs, as I mentioned in the script, that are coming into the marketplace that were previously sidelined. And those can carry some slightly different economic motives behind them, which is fine and expected. We've said that for a couple of years. So, I think with that at play, the fact we're experiencing this right now with all the short term contracting, you do get whitespace in schedules. And so, I think with those couple of dynamics, people managing time between contracts, et cetera, you are going to see a range of fixtures in the near term. But I think very much what I laid out in the script and what we see in terms of very tangible demand, coupled with some of this project sanctioning coming through, like we're hopeful this year, puts us on a path to $500,000. And I don't know that that rate is going to be paid in 2023 for anybody. But I think there's very much a path where we could see a fixture this year that's above $500,000 and even more confident in that if you include kind of a total contract value analysis of what an operator ultimately is going to need to pay for a rig this year. As it relates to our strategy, we've been very lucky to have these contracts in Guyana with Exxon, where we have had long term visibility for four of our top drillships. And also, of course, we only have the Meltem cold stack and then the Scirocco which is 6G cold stack. And so, we've been fortunate not to be put really to as I think as crucial a decision around taking a strategy towards long term contracts or not at this point, but we've got right up there with the largest tier 1 fleet in the world. And we'd be willing to take one or two long term contracts at current day rate levels, which we can produce a significant amount of cash flow here at current day rate levels, even though we see a rising market. But I would say, Eddie, that our strategy thus far has been to take advantage of rising day rates and that's been enabled by the visibility we have in the Guyana/Surinam region.

Shifting over to the SPSs, as you mentioned, you have a good number of rigs undergoing programs this year and next. Specifically for 10-year SPSs for one of your drillships, can you just remind us what the typical cost is for that and the approximate split there between OpEx versus CapEx?

Look, obviously, it's very rig dependent, but I think a good kind of rule of thumb from a capital perspective is probably – think about a range of $20 million to $40 million, obviously, very, very rig dependent. A lot of that is capital, but also there's definitely an element of OpEx there as well. It's just going to be very specific to the rig. I do think what's important to note, and I referenced this in the script, was just the impact on top line, right. And so, for example, a 30 to 60 day SPS means you aren't earning day rate for that period of time. And with rates north of $400,000 a day, I think that that can have obviously a material impact on the overall financial statements. So, I'd encourage you to think about it both, obviously, from a cost perspective, and, again, which is very, very rig dependent, but also the lost revenue, if you will.

Let me just add to that, if I could, Eddie, you're going to see a pretty wide range. We've got an example of a rig in Guyana that came out for just 19 days to do its 10-year SPS at a cost – I think it's just under $20 million total. Now, that was an instance where we were able to work very closely with our customer and plan out that SPS. In other instances, that's just not possible to do. If you're between customers and contracts, you can't be quite as efficient. You're not going to get the customer preceding the SPS to allow you to do some of the onboard work that would make you more efficient. And it's hard to actually sign a contract when you have the SPS in the way and you're trying to manage a shipyard project timing on top of rolling between customers. So, you just kind of see a range and that's why Richard says it is very rig dependent.

Our next question comes from Kurt Hallead from Benchmark.

It's a great summary. Really appreciate the color commentary. So, my follow-up here would be on CapEx and the CapEx guidance that you provided, not just for this year, but obviously over the course of the next few years. I'm going to make an assumption here that, at least for 2023, your CapEx guidance does not assume any costs associated with the activation of the Meltem. Maybe let's start there. Is that fair?

Correct. Yes, that's right.

Of the potential activation costs of that $100 million, right, you mentioned you'd want a significant portion of that upfront. And I know there's going to be some probably horse trading between what kind of terms you can get, what kind of day rate you can get, what you want, but at a bare minimum what would be acceptable in terms of upfront payment to activate the Meltem?

It's a multivariable equation, as you alluded to. And so, let's say, somewhere in the order of half, something like that. But a big piece of that is – and that's not a rule. But you asked the question, a big piece of it also is when would the timing occur. As Richard mentioned in his script, we're very much on an upward trajectory on free cash flow here, and not looking to fall off of that track. We'll see what the world brings us this year. But as I've kind of, I think, hit pretty hard, I think things are set up quite well in the industry for the next few years. So as we move forward in time, I think that number is more likely to go down – is more likely to go down than up.

And then just to kind of put a bow on the CapEx, over the 2023 to 2027 period, where you said an average of $275 million of CapEx, then I would assume that you did include the Meltem into that calculation. Is that fair?

No, actually, it's not. So, I think the way to think about it, obviously, there's guidance we've got out there for 2023. We've talked about just given the number of SPSs next year, we expect that number to be higher. And I think thereafter, as you think about the 2026 through 2027 timeframe, you can therefore infer that, if you will, capital on an average basis is going to be plus or minus $200 million in that timeframe. So, it doesn't include the Meltem.

Our next question comes from Fredrik Stene from Clarkson Securities.

I'm if you already said it, again a bit trouble with the line, but wanted to touch briefly on the guidance you gave. And thank you for the color on the reimbursables and amortization. If you subtract those two hundreds, I think we come to the midpoint of $2.250 billion approximately, just from regular revenue. And if you looked at your backlog chart a bit earlier, I think you had $1.65 billion, $1.66 billion secured for 2023 already. So my question relates to this gap here? How should we think about that? Where will those $600 million come from? You think mostly floaters, mostly jackups, et cetera. I guess you have some insights where you find it likely that you'll be able to secure contracts that will actually contribute to close that gap. So, any color you can give on that would be super helpful.

Let me just say a couple words, and then I'm going to hand it to Blake who's leading our global efforts there. I mentioned in my script, we have an excellent opportunity set behind effectively all of the rigs where we have whitespace. Those are works in process, some are very well developed. And we have to have some good news soon. And then others are still closer to the bidding stage. That includes some of the big enduring whitespaces, but also perhaps a couple of filler jobs here where you see some gaps. So we're kind of working all of it right now. But maybe, Blake, just say some rig class color.

The first comment I'd make, you asked about floaters versus jackups, I think it comes from the floater side more than the jackups, the additional backlog and EBITDA contribution. And then I think we've talked about the SPS already sufficiently to describe how that affects the whitespace, but also the short term nature of some of the contracts that have hit in the UDW create this, I guess I'll call it, inefficiency in the market. So then we have just the timing of different projects or programs with mobilization and then, of course, you've got regional and contract specific requirements. So, depending on where we pick up the work and the timing, that'll define the whitespace. But what moves the needle is, of course, converting that whitespace to operating day. So, as Robert mentioned, when you look at the drillships, the demand backdrop is incredibly encouraging, I would say equally encouraging are our discussions ongoing with customers. And so, we should have some highlights here soon on that. And then when you look at the other ones for 2023 are two of our D class semi submersibles. So when you look at these assets, they are some of the most capable DP plus moored units available in the world. And traditionally, they compete for both programs that require that niche DP plus moored capability, as well as UDW capacity where there's where there's gaps or where they're available on the back end. And I think we have conversations in both of those spaces that are ongoing now. And we see several opportunities that start for these specific rig late in the year or early into 2024.

Just a follow-up on the guidance. I think at least compared to my numbers pre-report and when we adjust for the reimbursables, you still come in on the revenue side a bit higher than what I had expected. And I think my EBITDA number was also a bit higher in the range. So, around $800 million and you guide $725 million to $825 million. So you mentioned that the guide numbers takes inflation into account. And I think the inflation thing and then cost increases has been present also in some of your peers that have reported already. So, I was wondering, are you able to kind of give us some insight into how that has been factored in in terms of percentage basis and how you view that going into 2024 as well, your cost base?

Look, I think we've been pretty consistent around inflation here for a few quarters. So on my script, I talked about how we expect high-single digit type inflationary pressures this year. So that's absolutely embedded in our guidance, which is consistent with what we said back in October. So we expect that in 2023. As you look forward to 2024, obviously, as we expect global rig demand to continue to increase, we don't see that inflationary pressure stopping side [ph]. And so, therefore, I think you should expect in a rising rig demand market, essentially, the inflationary pressures that we're seeing in that high single digit type area to continue both – obviously, in 2023, but also through 2024 as well.

I guess it's fair to assume that you'll try to push all these cost increases, and if not more than that, on to your clients.

Yeah. Current market, yeah, typically reflects current costs basis as well. So, just speaking generally about the industry, of course, I don't know about outside of Noble, but the market where most of the contracts were signed, we're producing revenue today, there's probably a few that have some cost recovery. We have a couple that have cost recovery. But it's not been the norm here over the past couple of years of contract signed. So perhaps that's something that comes back into the market as we move through this year, but with the churn of contracts, particularly on the UDW side, the pricing resets can reflect increased costs.

Our next question comes from Samantha Hoh from Evercore ISI.

Congrats on the really great quarter. Thanks for providing that commentary that your floater backlog is averaging north of $400,000 per day. Just kind of curious, given this backdrop, how you're viewing options, like potentially granting options with new contracts? Are the days of price options gone for the industry? Or how do you think about that in terms of, like, just long term contracts drying, in terms of weighing price versus open ended option pricing?

Yeah, good question separated into two answers between floaters and jackups, unfortunately, right now. I think we've been probably more aggressive than the average on not giving priced options here over the past couple of years. And while it hasn't been a hard no, and we do have a couple of exceptions out there, generally speaking, we started pushing back very aggressively on priced options a year-and-a-half ago, I think. And obviously, as the market tightens, you could expect us to continue or even stop giving options. But the jackup side is a little bit different. It's a soft market. And more tentative economics, I think, for our customers. Options do serve a purpose in ensuring that certain wells can actually get sanctioned and drilled. And so, I think on the jackup side, that's still a part of part of the market we see.

Maybe if you can help us think about geographically where you want to have more scale, you're still concentrated in Guyana and the US Gulf of Mexico, but is there a goal in terms of getting to a certain size in the Australian market or in the West Africa region?

I wouldn't say that we have a defined strategy right now to move – in other words, we're going to be governed by economics and how or if we move rigs around the market. If the tightness that we're predicting plays out, I think the market very quickly gets to a point where the price for time between contracts starts to be put to operators, whether that's through mobilization or day rate recovery on a move. That's something that we're thinking through. The growth markets that I described in South America and West Africa, just by math, are the most likely to draw some more supply from us. We have worked – of course, are working currently, but have got decades of experience there. And I think just naturally, as the demand in those two regions draws in supply, those are likely places where you continue to see the Noble brand building.

Congrats again.

Our next question comes from David Smith from Pickering Energy Advisors.

A lot of my questions were answered mostly in the prepared remarks. I did want to say, on the deepwater side, the progression of day rates is really transparent. We don't get to see the changes in contract terms and conditions, which I expect are improving pretty well also. So I wanted to ask if you can give us some color broadly on how T&Cs have been improving in terms of backlog margin protection from early termination, maybe allowance for non-productive time. It sounds like a better environment for getting some cost recovery and paid mobilizations as well.

You're certainly headed in the right direction in terms of being in sync with the market, particularly in the areas that you mentioned. Mobilization and the cost recovery, we're able to get mobilization not only really for our costs, but also the opportunity cost of losing operating days while mobilizing. So that is improving. Termination payouts are also improving. They're largely improving with the market just as you described.

I just wanted to double check something. On the updated fleet status report, it doesn't look like there are any remaining floater options that are much below market rate. I just wanted to make sure I'm reading that right, especially for the Viking options.

Yeah, another good question. It really speaks to some of the Q&A we had just a moment ago about preserving optionality to recovering rate market and the efforts that we had in the strategy that we employed last year. So you're exactly right. We don't have exposure to low priced options or options priced earlier in the cycle. I think the exception there would be the Venturer. Nope, nope. I'm sorry. All those are exercised. And the remaining ones that we reflect here are unpriced and subject to market.

Our last question will come from Truls Olsen from Fearnley Securities.

Couple of questions for me. One is, when you're stating that you guys are targeting a conservative through cycle balance sheet, how should you think about this? Also, thinking about this from a capital return perspective, is it net debt, cash free balance sheet? Is it net debt to EBITDA of some kind of multiples? What's your thinking here? Some color around that would be good. And also, in terms of the synergies, as we think about 2023 – sorry, 2024. How should we actually sort of read or expect to see that in the OpEx and CapEx and SG&A, notwithstanding inflation doing whatever it does, obviously.

On the first question, we're very comfortable with our debt today, right? So, our balance sheet is a strategic asset, and we're going to protect that over time. So, I wouldn't expect us to layer on a bunch of debt on top of where we are today. But I would say that we're incredibly comfortable with what it looks like today. On the synergies point, we talked about having realized about – by the end of this year, about three quarters of the $125 million of synergies. The overwhelming majority of that is shore-based burden. So that will come out of both G&A as well as OpEx as well, just some of that shore-based runs through all OpEx. So, you should expect to see the impact of that as we move through the year. Inflation, obviously, is counter to that. But as we move through this year, obviously, we realized about $50 million – or we had realized $50 million as we exited 2022. And then that will migrate obviously to about $80 million, $85 million here by the end of the year.

So, effectively $80 million, $85 million improvement, all else being equal.

If you think about it, right, we realized $50 million as we exited 2022. Not all of that would show up in Q4. Some of would. It's an exit rate. But as you get to Q4 this year, you'll be realizing $85 million on a run rate basis. So, as you work through the year, you could call it versus the Q4 baseline. You can imagine between now and Q4, somewhere in the order of magnitude of about, call it, a $40 million to $50 million impact.

We have no further questions in queue. I'd like to turn it back over for closing remarks.

Thank you, everybody, for your participation and interest. And we look forward to speaking to you next quarter. Thanks.

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