Thank you for standing by. My name is Bailey, and I will be your conference operator today. At this time, I would like to welcome everyone to the Noble Corporation First Quarter 2025 Earnings Call. [Operator Instructions] I would now like to turn the call over to Ian MacPherson, Vice President of Investor Relations. You may begin.

Thank you, operator, and welcome everyone to Noble Corporation's first quarter 2025 earnings conference call. You can find a copy of our earnings report, along with the supporting statements and schedules on our website at noblecorp.com. We will reference an earnings presentation that's posted on the Investor Relations page of our website. Today's call will feature prepared remarks from our President and CEO, Robert Eifler, as well as our CFO, Richard Barker. We also have with us Blake Denton, Senior Vice President of Marketing and Contracts. During the course of this 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 certain 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. Also note, we are referencing non-GAAP financial measures on the call today. You can find the required supplemental disclosure for these measures, including the most directly comparable GAAP measure and an associated reconciliation in our earnings report issued yesterday and filed with the SEC. Now, I'll turn the call over to Robert Eifler, President and CEO of Noble.

Thanks, Ian. Good day, everyone, and thank you for joining us as we present our results for the first quarter. I'll begin with financial and operational highlights from the first quarter, recent commercial activity, our perspective on the market, and then hand it over to Richard to cover the financials. As usual, I'll wrap up with closing remarks before we go to Q&A. In the first quarter, we delivered strong results with adjusted EBITDA of $338 million and free cash flow of $173 million. We continue to execute on our return of capital program, paying $80 million in dividends and repurchasing $20 million of shares during Q1. Yesterday, our Board declared another $0.50 per share dividend for the second quarter of 2025. And I'm pleased to highlight that we have now surpassed $1 billion in combined dividends and buybacks since Q4 2022, including this quarter's announced dividend. On the integration front, our progress has been right on target. The legacy Diamond fleet recently went live on Noble's ERP system ahead of schedule, positioning us to achieve our previously stated synergies of at least $100 million by the end of the year. We are also pleased to share a number of significant commercial and operational successes. As we announced yesterday, we have recently been awarded long-term contracts by two major oil companies, comprising nearly 14 rig years of additional backlog across four rigs with a total revenue potential between $2.0 billion and $2.5 billion. First, the Noble Voyager and another 7G drillship to be named were awarded four rig years each by Shell for operations in the U.S. Gulf. These contracts provide for a base dayrate value of $606 million per rig, plus the potential to earn up to an additional 20% based on the operational performance of each rig. Voyager…

Good morning or good afternoon, all. In my prepared remarks today, I will briefly review our first quarter results, provide an update on our integration progress, and then discuss our outlook for the remainder of the year. Starting with our quarterly results. Contract drilling services revenue for the first quarter totaled $832 million, adjusted EBITDA was $338 million, and adjusted EBITDA margin was 39%. Adjusted EBITDA was positively impacted by approximately $20 million related to insurance proceeds, the legacy repair work on the Noble Regina Allen, which is accounted for as a reduction in operating expense, as well as overall strong cost management. Q1 cash flow from operations was $271 million, net capital expenditures were $98 million, and free cash flow was $173 million. We continue to remain focused on controlling costs, which includes managing our stacking costs accordingly. To that end, the sale of the Meltem and Scirocco will eliminate associated stacking cost of $40,000 to $50,000 per day on a combined basis, as well as bring in net proceeds of over $35 million. As summarized on Page 5 of the earnings presentation slides, our total backlog as of April 28th stands at $7.5 billion, up approximately 30% versus the prior quarter. This includes approximately $1.9 billion that is scheduled for revenue conversion over the remainder of 2025, and on the back of our recently announced contract awards. This now includes approximately $2.1 billion and $1.5 billion scheduled for revenue conversion during 2026 and 2027. As a reminder, our backlog excludes reimbursable revenue, as well as revenue from ancillary services. Our integration remains on track, and we continue to expect to realize $100 million of annual cost synergies on a run-rate basis by the end of the year. As of the end of the first quarter, we have achieved…

Thank you, Richard. To wrap up, I'd just like to emphasize that our first choice offshore strategy remains at the core of everything we do at Noble. We've been working very hard over the past four years at taking the company to the next level. And now we are really beginning to see the fruits of our labor. Throughout today's call, we've highlighted a number of proof points. Significantly increasing and enhancing our backlog with strategic contract awards, moving up our integration synergies, delivering customer programs with a focus on safety and efficiency and reaffirming the resiliency of our cash flow and dividend. On the latter point, we're now eclipsing $1 billion of capital return to shareholders over the past couple of years, which represents almost one-third of our market cap from where we sit today. We also acknowledge the challenges of an exceptionally volatile macroeconomic environment. We're doing what we can to demonstrate reliability for our customers and shareholders. With the crucial backlog infection now at hand and additional tangible contracting opportunities also within view, we remain confident about the medium to long-term fundamentals for our business. And recent fixture activity in the low-to-high 400s is solid. With our demonstrated commitment to the dividend and its current nearly 10% yield, the recent 30% increase in our backlog, over $1 billion in capital returns thus far and tangible results building up from our scale and first choice offshore strategy, it seems the value proposition in Noble is compelling to say the least. Operator, we're ready to go to questions now.

[Operator Instructions] Your first question comes from the line of David Smith, Pickering Energy Partners. Your line is open.

Hi, good morning. Congratulations on the strong quarter and the very impressive backlog addition.

Thank you.

I wanted to ask about the relatively large performance bonus opportunity in the Shell and Total Energies contracts. And if - is it fair to think that your willingness to take some rate risk on the performance component might be somewhat informed by your lived experience, generating some pretty strong efficiency gains with your drillships in Guyana? And is it fair to think that performance component risk is - yes, has a lot to do with the duration of the programs and maybe the homogeneity of the drilling program? So we might not necessarily be expecting these kind of performance bonus opportunities for shorter duration or multi-basin type programs?

It's a great question. What I would say is, first of all, we're extremely happy with both of these programs and very honored to have been entrusted with them. This is something we've been looking at for quite some time, and we think our customers have wanted something like this for even longer. I would repeat what we said earlier. We see it very much as a win-win. But to your point that it definitely doesn't work in every scenario. In fact, I would say that it only works in a relative few scenarios from what you see globally. We mentioned in the remarks, but we've spent a lot of time looking at our own performance data and getting our organization to a place where we were comfortable not only analyzing our capability, but also projecting those capabilities against programs like this. And we got to a place that we think works for both sides. And I'd say, I guess, that these are - we mentioned the word strategic, that's obviously deliberate. These were very - our approach here, I think, is very, very strategic, not only in the structure that we've described a little bit, but also in where that structure is applied to basins, the type of program, et cetera.

Appreciate that color. And the follow-up, if I may. If we start to see more performance-based contracts industry-wide, can you talk about how the CEA index pricing mechanism takes performance-based contracts into account, right, for, yes, the drillship in Suriname, right? There appears to be a - maybe about $140,000 a day spread between the base rate and the full bonus potential. Where on that spectrum would we look for the rate that contributes to the CEA-indexed rate?

It's also a good question. Not one obviously that was forecasted or contemplated when we came up with this, when it was a six or seven, eight years ago, longer maybe now. So, I guess what I would say is that mechanism is not mechanical. It was designed to be flexible and it was designed to take in a number of different market considerations at each six-month turn. And so, we've had this come up in certain other kind of nuances that they go into rates, whether it's types of costs or taxes or whatever. And it's flexible enough to also take into account this type of structure. And so, we haven't had this conversation yet. So I don't want to really say anything more than that. But it is a mutually agreed rate that we get together and decide on every six months. We, both sides, put in data as both sides see it, and we take that data and mutually agree. And as to the extent that we have trouble with that, sometimes we'll bring a third-party in as well. So we spent a fair amount of time on the prepared remarks, giving some thoughts and ideas as to where our - where we think we could land on achieving these larger performance components. And we're going to have to go through some type of that as we move through the CEA.

Perfect. Really appreciate it.

Thanks.

Your next question comes from the line of Arun Jayaram with JPMorgan. Your line is open.

Yes, good morning, gentlemen. Robert, I wondered if you could go through some of the competitive tensions in maybe both of these awards and maybe specifically on the Shell award, is this incremental demand? Are you displacing an incumbent, but talk to us about opportunities for these really interesting opportunities with Shell?

Yes. Well, thanks. So, look, what the Suriname contracts are obviously incremental. The Shell contracts in the U.S., that's a key basin for them. And I think the thing that really was even - as attractive as anything else here for us was that these rigs, if we perform, we've set up a contract that rewards performance. Our customers obviously expect performance out of us. And we firmly believe that if we perform and deliver what's expected of us that these rigs will spend decade plus without really having to make a substantial mobilization. So when we say strategic, that's a big piece of it for us. These rigs are getting to be - they're about a little over 10 years old. So if you think about accounting lifes, et cetera, there's an outside chance that these things can close it out right there in the Gulf of America. We do believe that we're displacing that this is not incremental right now. But for us, the bigger piece of this was the longevity of the potential work here.

Great. And maybe my follow-up. Richard, you went through kind of the sequential changes in your OpEx expectations. Could you maybe elaborate on what you see in 2Q and maybe give us a sense of how you see the back half of the year in terms of OpEx, because that was significantly lower than our model in 1Q?

Yes, sure. Very good question, Arun. So we noted in the prepared remarks that obviously, we had a $20 million impact from the Regina Allen. So I mean, that was a net against cost. Obviously, that's not going to reoccur, if you will, in Q2 going on. So if you back that out, our operating costs, if you will, on the income statement, I think would have been about $480, $485. Inflation is real. So we do expect some inflationary pressure here as we've talked about before in the low mid-single-digit type area through the rest of the year. So I think that kind of guides, if you will, how we think about operating costs for the rest of the year. Obviously, we talked about from a guidance perspective, low end of revenue equals midpoint of EBITDA as well. And really cost management is really what's driving that. So we're obviously very focused on managing cost here, and we would expect, hopefully, to continue to be aggressive from an OpEx perspective going forward.

Great. I'll turn it back. Thanks.

Your next question comes from the line of Scott Gruber with Citigroup. Your line is open.

Yes, good morning, and congrats on the new contracts. And I appreciate your assumption on the bonus capture there. How will the bonuses be paid out if achieved? Are they reviewed after a certain number of wells? Is your performance review kind of on an annual basis? Just some color on when you could collect on the bonuses? That would be great.

It's well by well. n actually, both contracts, it's well by well. So, collection would happen after. You'd have to do some sort of reconciliation of data, et cetera, and then have payment terms or whatever, but they are well by well bonuses.

Okay. They're fairly frequent throughout the contracts, then. Okay. And then can you provide some more color on the downtime associated with the rig upgrades required on the Shell contracts? And then how should we think about finding some shorter-term work for those rates before the long-term contracts start?

I think it's kind of a couple of months to - for us to do the actual work that would pull us out of being able to carry out other work. And so, we said we've got a number of conversations ongoing right now for things that would fit in between. And we'll see how that plays out. But yes, in the scenario where we're able to fill substantially all of that time, we would need a couple of months to do the final installations.

Okay. I appreciate those. Thank you.

Thank you.

Your next question comes from the line of Eddie Kim with Barclays. Your line is open.

Hi, good morning. Just wanted to ask about the performance-based nature of the contracts, which make up a meaningful proportion of the total potential value of the contract. Could you maybe just give us a sense or an example of what sort of metrics or milestones this is based on? And you mentioned that kind of normal operations would more or less equate to achieving around 40% of the performance bonuses of the contracts? And please correct me if I heard that incorrectly. But what more would be needed to get closer to realizing the full value of those performance bonuses?

Yes. So they're very different - they're different mechanisms, I'd say, between the two contracts for sure. I think the important takeaway here is that both of them have a very heavy component of time drilling, so days per well. And so that's where we spent a lot of time. And, I'd say - I don't want to give any real breakdown or specifics. It's proprietary to our customers as well as us. But, there's obviously other components to performance. There's safety and other things, all of which we pride ourselves on. But I think, think about a very important driver being the time against the curve on a well. And that's really - I mean, all of it is where the win-win comes in. But in a big development, there's probably more to play with there in terms of the self-funded pool.

Got it. Got it. That's very helpful. My follow-up is just on the contract expenses, or I guess, contract prep expenses on these. So you mentioned the upgrade CapEx on the two rigs with Shell, but are the contract prep expenses for these larger than some of your other multi-year contracts you've announced previously, or are they more or less in line?

I was going to say much, much more in line, obviously, the CapEx, the capital on the Shell contracts, we've spoken about that. But think about kind of the contract prep expenses is very much in line, Eddie.

Okay, great. Thanks for the color. I'll turn it back.

Your next question comes from the line of Greg Lewis with BTIG. Your line is open.

Hi, thank you, and good morning, and thanks for taking my question. Robert, we appreciate the decision to maintain the dividend. Obviously, that's a Board decision that you go through frequently. As we think about that over the next two years, three years longer term, as I imagine you're working through the dividend, clearly, this year it's going to be paid out with free cash flow. It looks based on some of the announcements today, that's going to be the case. How do you at a big picture, think about the dividend just balancing all the moving pieces of, you know, are - a lower oil price against a strong backlog. Just kind of like any kind of - how is the Board thinking about that dividend? Kind of curious on that?

Yes. So we're committed to the dividend. I would say, we have got - if you look at our first quarter results and our guidance, you can do the math to put us to about a $250 million per quarter EBITDA run rate here. And we said in the remarks, we see that ticking up with these contracts we've just announced. And I guess the color I would add to that is that we mentioned twice in the script, very deliberately, that we also have line of sight to a number of additional contracts. And so there is - there are multiple different paths to that uptick occurring sooner than the start of these contracts. It's too early to tell. So I don't want to say too much now here - sitting here in early 2025, but we're encouraged, frankly, by the level of conversations we're having, by the behavior we're seeing - the contracting behavior we're seeing out there in the market. And so, yes, where we - we're pretty confident here in our return of capital structure.

Okay, great. And then just on the realizing you might be limited in what you can and cannot say. But in terms of the timing of the contracts with Total and with Shell, a question we often get asked is, okay, well, that's great, but when did the negotiation around the pricing actually start? Just kind of any kind of color around that? And then on the - I guess, in the press release, we talked about the Noble V-class rig. Was there something specific about those rigs that the customer wanted, i.e., as opposed to, like, I guess, one of the black rigs is rolling-off and it looks like a rig like that could be able to potentially have been slotted in for that one? Thanks.

Sure. Yes. Look, I'd say initial pricing happened a little while back, but the reality is that final pricing is - happens effectively when you sign a contract, especially in a volatile market like this. So yes, I'd say these are very, very current - this is very current pricing, the V-ships - both of these customers are very strong supporters of the V-class rigs. The Valiant one - excuse me, rig of the year from Total last year and both Shell and Total had the V-ships multiple times through time. And so they're just big supporters of those rigs, and those really were the preferred vessels. So in the case of the U.S., which has some different - kind of a different type of work required higher - required - excuse me, requires higher hook load in some instances. There is a more limited number of higher hook load rigs out there. So we were really happy to upgrade these as part of that contract. And along with the other few upgrades we mentioned for the U.S. work, these are going to be right there with the - with some of the highest spec rigs on earth. And that's going to be something that I mentioned before, we hope that to be right where we are for a very long time. But that's something also that would be valued by a very wide variety of clients, should things change. And so, yes, look, everything kind of matched up nicely. They have really high thruster power, so they can hold position in Suriname, which is important, but just the specs matched up very nicely for both of these programs.

Great. Super helpful. Thank you.

Your next question comes from the line of Fredrik Stene with Clarksons Securities. Your line is open.

Hi there. And I guess it's been said many times already, but congratulations on the very long and very nice contracts. And I also have a couple of questions relating to those contracts. So first, I think you said that on the back of the bookings that you've made so far and my understanding from the prepared remarks was that the comments then kind of pointed to the Shell and the Total work that there could be more coming down on the same line. And I was wondering if you could give some additional color on that because obviously, these four rigs will be tied up for three years or four years. So to me, it's kind of natural to assume that this could be a similar long-term programs for maybe other rigs and Shell, for example, they have other rigs that are rolling off similarly to when the startups are for the two that they've already contracted. So any color on what you meant by these comments would be super helpful. Thank you.

Sure. Yes, I guess the comments in the prepared remarks were really intended to address some more near-term white space in our fleet where we have a number of active conversations right now. And so, too early to tell and all that. And there's obviously competition. But we're encouraged with the level of detail in the number of conversations that we're having right now, as you look kind of at spots with near-term availability in our fleet. I would say - I said earlier kind of my bit about the U.S. Gulf, it's a premium basin. There, we think that those rigs could stay there a very long time. And I would say also our experience elsewhere, perhaps in relation to Suriname, but it really applies anywhere is that in a collaborative setting where the collective team is delivering very strong results, you do open up additional work. So yes, we're addressing the - to some extent, we're addressing the issue of efficiency, where we get paid for higher efficiency. But I think sometimes the unnoticed piece of that is that efficiency leads to more work in and of itself. And so, we're particularly excited really about both of these basins, but especially in really a new basin like Suriname about the potential of really unlocking kind of the maximum amount of work ultimately in the area.

Yes. That's actually very helpful, which brings me to my follow-ups, which goes back to the incentive structures of this. I think for the Shell work, you're talking about the 20% of the base rate that you can earn, and it seems that to be related to the speed of the wells really, but it's worded a bit differently for the Total contract. Does that mean that this potential additional revenue - is that potential additional dayrate revenue for you guys with no additional cost or is it any other type of additional revenue that might be a lower-margin revenue or related to additional services or anything? If you could give some clarity on that, that would also be very helpful. Thanks.

Sure. Yes, it's a very good question, actually, now that you've brought it up. No, it's all dayrate. There's nothing in there that's like - that's margin, it's all 100% margin potential there. The wording is different only because we work with our customers to print what works for all parties and we're - we just - that's where we ended on the wording. But no, there's nothing to read between the lines there. These are truly dayrate bonuses.

All right. That's very clear. Thank you so much. Have a good day.

Thank you.

Your next question comes from the line of Noel Parks with Tuohy Brothers. Your line is open.

Hello. Just wanted to follow up on sort of a housekeeping thing. During the remarks - the financial remarks, there was something about lease items left over from our - from the acquisition. So could you just cover those again?

Sure, Noel. It's - so it's the Diamond BOP leases. So, essentially just wanted to state that those are running through operating expenses, if you will. So, just want to be clear on where that hits on the financial statements. So it's about $26 million here in 2025.

Great. Thanks. Thanks for the clarification. And I wonder at this point and I realize, of course, we have a backdrop of uncertainty, any inkling of whether tariffs have the potential to move the needle on suppliers' input costs on to a degree that anything could get passed on as you look out to future projects?

Sure. The short answer is yes, right? It's a very fluid situation right now. And we talked about, as it relates to 2025 for Noble, we estimate this will impact less than 5 million, obviously - sorry, 15 million and that can change as things play out. So on the steel side, that's something we're obviously focused on a lot. But ultimately, we would expect cost increases to generally get passed through to us. We're obviously managing that as well as we can. And so, that's why we wanted to provide some guidance as we see the world today from a 2025 perspective. But obviously, if things change materially from that, then obviously, we would expect a bigger impact to us here going forward, maybe into 2026 as an example.

Okay, great. Thanks a lot.

There are no further questions at this time. Mr. Robert Eifler, I will hand the call back over to you.

Thanks, everyone, for joining us today. We look forward to catching up with you at the next quarter.

Thank you so much. This concludes today's conference call. You may now disconnect.