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. 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 adjacent to the website is the fourth quarter earnings slides presentation that we will reference 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 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. Our near-term commercial pipeline for 2023 and 2024 confirms as much. We're also observing an interesting increase in licensing bid rounds in several frontier regions that further support the demand story. All of these improving demand signals are a result of an upstream sector that is finally inflecting after a decade of structural underinvestment. The world runs on oil and gas and will continue to do so for decades. In the new energy order, the largest producers are prioritizing the lowest lifting costs and lowest carbon profile barrels of production, both of which align squarely with Noble's fleet positioning. And while the value over volume imperative for upstream producers has both validity and a sense of permanence, it is not to be mistaken for a cap on growth. On the contrary, the call on hydrocarbon production growth over the next decade is real, with international deepwater set to command a rising share of investment, as indicated by an expected sharp increase in greenfield FIDs over the next two years relative to prior decade levels. The supply side of the offshore rig market has been comprehensively redefined by fleet attrition, capital flight and tightening, and a much more economically rational competitive structure, all of which, of course, stands in complete contrast with the fast and loose growth-at-all-cost market conditions that derailed the broader energy industry during prior commodity upcycles since the early 2000s. Meanwhile, threshold utilization for most rig classes has been eclipsed over the past year, and day rates continue to rise in direct correlation with incremental demand growth. Deepwater, in particular, has taken another significant leg higher over the past several months. The contracted UDW rig count in the first half of 2022 averaged plus or minus 80 rigs, with 86% utilization of the marketed fleet. Today, the contracted UDW count has reached 91 rigs, and rising, with 91% marketed utilization, while utilization of the approximately 45 tier 1 drillships remains above 95%. Consequently, not only are our tier 1 drillships pricing firmly in the low to mid $400,000s per day with an upward tilt, the lower capability UDW rigs are also being pulled higher. Yes, there has been some recent transacting and capital formation behind a handful of sideline UDW rigs, of which there are approximately a dozen 7G drillships between cold stack units and stranded new builds; however, the majority of these are not necessarily fully tier 1 ready in terms of being equipped with two BOP stacks. In any event, this pool of sideline capacity is both finite and fully required to meet expected incremental demand growth, especially given the most recent developments with UDW utilization moving into scarcity territory. Also, the fact that established drilling contractors are prioritizing investment in 7G drillships stranded in shipyards is also a very clear indication, in our view, that most of the stack 60 rigs in the world are becoming more and more marginalized with the passage of time. Moreover, the timing of the reactivation of the sidelined drillships will continue to be spread out due to disciplined contractor bidding, significant lead times for reactivation, and a limited number of multi-year tenders in the market that would be adequate to underwrite a compelling guaranteed return for a major capital project. As a reminder, we have selectively marketed our cold stack tier 1 drillship Meltem, which we are budgeting as a $100 million all-in reactivation project, with at least a one-year delivery timeline. We continue to take a very disciplined approach with bidding the Meltem, which is to say that we would require a firm guaranteed contract with an attractive full payout plus return on capital in order to move forward with its reactivation. Looking forward at the global deepwater demand outlook, all indicators from our internal commercial perspective and customer dialogue to analyst and consultant research point to a probable multi-year rise in UDW rig demand. Rystad, for example, is currently forecasting total floater demand to increase by 11% from 113 rig years in 2022 up to 125 rig years in 2023, on the way to a peak of 150 by 2026. While we would certainly love to see that level of demand materialize, the truth is that even a modest increase of demand this year could likely exert further upward pressure on day rates. The fulcrum of demand growth for deepwater continues to be the Golden Triangle, especially South America and West Africa. Starting in Brazil, Petrobras has been by far the most active operator in terms of securing rig capacity recently, comprising nearly 40% of all drillship rig years contracted throughout 2021 and 2022. A lot of this has been renewing and extending existing capacity, but still Petrobras' deepwater rig count has recently increased from around 20 rigs throughout most of the past two years to 24 weeks today and is on the way to 26 with recent signings. Some research indicates that Brazil could absorb an additional 10 to 11 rigs over the next year or so, although it's frankly hard to see where that much capacity could be sourced. Nonetheless, we do believe that Petrobras could realistically take an incremental five to seven floaters over the next 12 to 18 months. Beyond Brazil, other South America represents nine floaters of demand currently and could add an additional one to two rigs through 2023 and 2024. We're also seeing some pretty interesting leading indicators in this part of the world beyond the tangible near-term rig requirements. I'm referring to the emergence – or reemergence of frontier markets like Colombia on the deepwater side and Argentina on the jackup side, as well as increasing licensed bid round activity in places like Uruguay, Ecuador, in parts of the Caribbean. After South America, West Africa has become the second most dynamic region for deepwater rigs. We're seeing a significant increase in tendering driven by Angola, Nigeria and the emergence of Namibia as an important exploration basin. West Africa was a late mover off the bottom, but it's now moving higher in a meaningful way with several multi-year drillship requirements surfacing. Current marketed utilization of UDW units in the region is 18 out of 19 rigs, and we see a likely supply deficit of around three units by 2024. The deepwater Gulf of Mexico has been more of a steady market with between 20 to 22 rigs of demand for the past couple of years, and we're not counting on a significant change here over the near term. However, the bias looks flat to perhaps up by one or two incremental rigs through 2024. The shorter-term nature of most of the contracting and the role played by more nimble independent E&Ps on the demand side makes the Gulf of Mexico a little harder to forecast. So that gets us to a global roll-up of about 12 to 15 incremental UDW rigs over the next 12 to 18 months. If this demand level does materialize, then we should expect to see a combination of upward day rate movement and more sidelined capacity entering the market. These are not mutually exclusive outcomes. Now for a few comments on our own deepwater fleet status and outlook as summarized on pages six and seven of the slides. Since our last fleet status report in early November, we have secured 24 months of additional backlog across 4G, 6G and 7G drillships at an average day rate above $420,000. This includes the nine-month contract for the Gerry de Souza which started recently in Nigeria, the six-well program for the Stanley Lafosse in the Gulf of Mexico, a one-well contract for the Faye Kozack in the Gulf of Mexico at $450,000 per day, and a 70-day P&A scope for the Globetrotter I, also in the Gulf of Mexico. The Globetrotter I's preceding contract with Petronas in Mexico has encountered a delayed start, however, and remains off contract awaiting permit approvals. We believe this delayed permitting process represents a deviation from past precedent by the regulator there, and we continue to work diligently towards a solution. Our fleet status report now indicates an expected start date for this contract in March. However, the permitting process remains fluid. Our 16 marketed UDW rigs are currently 75% contracted throughout 2023 with visibility towards securing additional utilization for a portion of the remaining availability for this year, although some contract gaps and SPS time will remain uncontracted. The average day rate across our $2.7 billion floater backlog today is approximately $400,000. With over half of our 2024 floater days uncommitted, an upward trajectory for repricing the fleet is visible based on current market dynamics. So we're very optimistic about how our deepwater fleet is positioned at the moment, with a good balance of backlog, but also 15 out of our 16 working rigs exposed to current or future market rates over the next year. And next on to jackups, which is an improving but still later cycle dimension to our fleet. Globally speaking, the roughly 400-rig jackup market eclipsed 90% effective utilization in the middle of last year, driven primarily by the demand surge in the Middle East. However, in the North Sea and Norway region, where our harsh and ultra-harsh jackup fleet is now principally positioned, the market has been softer recently. Current activity in the North Sea Norway region is at 28 rigs, with utilization at 85%. This is down from a 31 to 33 rig count during the first half of last year. The net impacts of tax policy levers out of the UK have not been stimulative for jackup activity in the North Sea over the short term, but we continue to see encouraging demand indicators that support the case for an improving market from here forward, including crucially visible demand improvement in Norway from mid-2024. We believe this could provide decent earnings upside for Noble in 2024/2025 compared to a fairly anemic jackup EBITDA contribution in 2023, which, depending on contracting results this year, is about 10% of our total EBITDA guidance. Naturally, a significant key to better margins is utilization, not just day rates, and whitespace will certainly weigh on margins over the near term. This includes the likelihood of losing at least most of this year to the Regina Allen. On the positive side, during the fourth quarter, the Noble Innovator was awarded a one-year contract with BP in the UK North Sea at $135,000 per day, with a one-year option with day rate escalation. This is a premium rate for the UK based on the Innovator's high technical capability as a CJ-70. Nonetheless, we do see day rate improvement for other harsh environment class rigs into the $110,000 to $125,000 range, up from sub-$100,000 rates through the recent trough. I'd also like to highlight that the Noble Resolve recently commenced the onsite pilot scope at Project Greensand, the world's first industrial-scale offshore carbon capture project offshore Denmark. Long-term market growth potential from offshore carbon capture could prove quite significant. In the meantime, we're proud to be an early leader in this field. Further east, Noble Tom Prosser has recently completed its contract with Santos in Australia in late January. While we don't have future work for the Prosser reflected on our fleet status report, we do have strong visibility for a significant amount of work for this rig starting around the middle of this year. So, overall, we do have some space to fill across our fleet over the near term, but the opportunity set looks promising. That wraps up the market overview. And with that, I'd like to pause now and turn it to Richard to go over the financials.

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 and the delayed contract start for the Noble Globetrotter 1 in Mexico had adverse impacts on the quarter's financial results. 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 provides a summarized schedule of backlog for floaters and jackups over the next five years. Our balance sheet remains in terrific shape, with December 31 net debt of approximately $200 million. Subsequent to the end of the fourth quarter, we have elected to repay the $150 million Danish ship finance loan with excess cash on hand. In conjunction with our banking partners, we are currently evaluating alternatives to further optimize and simplify our capital structure. Before discussing our guidance for 2023, I would like to first provide an update related to the business combination. Our integration activities continue to progress strongly as we work towards realizing the target of $125 million in annual run-rate cost synergies by October 2024. We expect to have realized over three quarters of these savings on a run-rate basis in the fourth quarter of this year, and we achieved the first $15 million of run-rate synergies as we exited 2022. As previously disclosed, we expect in the aggregate for the one-time cash costs to achieve these synergies to be within a range of $1 to $1.25 for every dollar of annual synergies realized. In calendar year 2023, we expect to have one-time cash costs of approximately $70 million to $85 million related to achieving the cost synergies, leaving minimal thereafter. Now I will cover our guidance for 2023. We anticipate total revenue to be between $2.35 billion and $2.55 billion. Adjusted EBITDA, which adds back merger and integration costs, to be between $725 million and $825 million, and capital expenditures, net of client reimbursables, to be between $325 million and $365 million. Additionally, note that total revenue guidance is impacted by two items. Firstly, revenue includes the non-cash amortization related to net and variable customer contracts, a function of accounting rules for both the recent combination and our emergence. Secondly, revenue includes various client reimbursables, which generally carry a minimal margin. In total, these items are expected to contribute approximately $200 million of revenue in 2023, split somewhat evenly across the two items. Additionally, we expect our cash taxes in 2023 to be just over 10% of our adjusted EBITDA. Incorporating our guidance is the anticipated impact of the recent contract termination for the Noble Regina Allen, as has been previously disclosed. We continue to develop the repair plans and the rig has applicable insurance coverage with a $5 million deductible. Given this insurance coverage, our guidance excludes any projected expense or capital required to repair the rig. However, there could be a timing difference between the payment of repairs and receipt of funds from our insurance. While we are not providing quarterly guidance, I would like to provide the basic directional comment that we had a couple of key factors at play that we anticipate should drive a progressively stronger contribution of both EBITDA and free cash flow as the year unfolds. One expected factor is the momentum of day rates with the fleet continuously repricing into an improving market. The second factor is we expect operating days to increase in the second half of the year. We currently expect to generate approximately 65% of our 2023 EBITDA in the second half of the year. Additionally, our 2023 adjusted free cash flow generation will be heavily weighted to the second half of the year. On last quarter's call, we cited recurring high-single-digit percentage inflation rates across major OpEx and CapEx categories persisting throughout 2023, and that view is indeed embedded in our 2023 guidance today. Also, as previously stated, CapEx for this year, and likely to an even greater extent next year, is influenced by a higher-than-historical average number of SPSs across our fleet. As the majority of our working fleet approaches its 10-year SPS, we have approximately half of our fleet due for these surveys over the course of 2023 and 2024. The reality with a typical rig lifecycle is that the first five-year survey is usually inconsequential in terms of capital and downtime. In addition to the capital for deepwater rig, our 10-year SPS generally requires 30 to 60 days out of service. For 2023, excluding the Regina Allen repairs, we have seven rigs combined across our jackup and floater fleet planned for major projects. While we expect the peak number of 10-year SPSs to drive CapEx in 2024 to a level somewhat higher than 2023 with our schedule currently showing 10 major projects in 2024, our plan is to achieve five-year average annual CapEx in the $275 million area between 2023 and 2027 as the 10-year surveys taper off after 2024. It is important to note that there is a tightening impact on effective supply that results from structurally high global fleet downtime caused by these SPS surveys over the next couple of years. An additional consideration is how the shipyard and OEM supply chain will respond to a handful of deepwater rig reactivations layered on top of the SPS spike. This is a recipe for pinch points, cost inflation, and delays. However, we feel very confident that we have the right team and plans in place to complete these major projects in an efficient manner. Now I'd like to wrap up with a quick refresh on capital allocation. We believe our conservative balance sheet and strong free cash flow results and outlook are differentiating factors for Noble. Since authorizing a $400 million share repurchase program in Q4, we have repurchased nearly $100 million in shares through January, including the mandatory purchase associated with a squeeze out of legacy Maersk Drilling shareholders. Returning capital is central to our capital allocation strategy. To restate our current priorities regarding the use of cash, they are as follows: to maintain what we believe is a conservative through-cycle balance sheet coupled with significant liquidity; to invest in the maintenance and maximum potential of our existing working fleet. Once these objectives are achieved, we will look to return at least 50% of our free cash flow to shareholders and target disciplined and accretive investment opportunities. That concludes my prepared remarks and I'll now address any questions.

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 in 2023. Noble will not deviate from our disciplined and conservative financial position and capital allocation framework. 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.

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. You alluded to the potential about – we're looking at potentially – looking for that right contract or to reactivate 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. As you look at potential opportunities for the Meltem, how are you thinking about that rig and where those opportunities potentially could be?

Look, I think the Golden Triangle is going to host the vast majority of the opportunities. 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. As we said, I didn't repeat it in the script today, but we have said previously 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 near term, I think those opportunities exist through the Golden Triangle. They're very few and far between. Today, it's more likely to be outside of a Petrobras contract than with Petrobras, but the market is moving. 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. We're maintaining constant dialogue with customers globally. I think we are picking our opportunities very carefully to ensure 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 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 are on in the North Sea. So, as you think about that and those dynamics, is it kind of a let's just wait it out for 2024, which is expected to see some improvements, or could we think about maybe trying to find another base and where some of these rigs could go to 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 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. It essentially put the market, which does have some movement back and forth between the UK and Norway, on its heels. We have a portion of our jackup fleet scattered outside 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. 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. In particular, for Norway-class vessels, we now have visible demand in 2024, but it doesn't meet the total supply from what we see today. It's 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. We stick to the view that late 2024 is going to bring back the demand for our CJ-70 fleet. Those rigs will contract before and stay active longer than other Norway-class rigs because of their performance capability. They also have the ability to work in certain transitions and waters that would otherwise go to harsh semis. That's 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, 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? How do you think about contracting strategy in this type of environment? Because I would think you'd want to sign shorter contracts today in anticipation of higher day rates maybe 12, 18 months from now. 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 have some rigs, as I mentioned in the script, that are coming into the marketplace that were previously sidelined. These can carry some slightly different economic motives behind them, which is fine and expected. We've said that for a couple of years. Given that at play, the fact we're experiencing this wide range of short-term contracting, you will see whitespace in schedules. I think given those two dynamics, people managing time between contracts, et cetera, you will see a range of fixtures in the near term. However, I think with 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. I don't know that that rate will be reached in 2023, but I think there's very much a potential for a fixture this year that's above $500,000. I'm even more confident in that if you include a total contract value analysis of what an operator ultimately needs to pay for a rig this year. As it relates to our strategy, we've been fortunate to have contracts in Guyana with Exxon, where we've had long-term visibility for four of our top drillships. We only have the Meltem cold stack and then the Scirocco, which is a 6G cold stack. We haven't been pressed into any crucial decision around taking a strategy towards long-term contracts or not at this point, but we've been willing to take one or two long-term contracts at current day rate levels. This allows us to produce significant amounts of cash flow even though we see a rising market. Our strategy thus far has been to take advantage of rising day rates, enabled by the visibility we have in the Guyana/Surinam region.

Shifting over to the SPSs, as you mentioned, you have several 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 there's definitely an element of OpEx there as well. It's 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. A 30 to 60-day SPS means you aren't earning day rate for that period of time. With rates north of $400,000 a day, I think that can have a material impact on the overall financial statements. So, I would encourage you to think about it both, obviously, from a cost perspective, and again, which is very rig dependent, but also the lost revenue.

Let me just add to that if I could, Eddie. You're going to see a 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. That was an instance where we were able to work 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 are unable to be as efficient. It’s hard to sign a contract when you have the SPS in the way, trying to manage a shipyard project timing on top of rolling between customers. 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. I really appreciate the color commentary. My follow-up here would be on CapEx and the CapEx guidance you provided, not just for this year, but 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. I know there's probably going to be some 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. Let's say, somewhere in the order of half, something like that. A big piece of that is when would the timing occur. As Richard mentioned in his script, we're on an upward trajectory on free cash flow here, and we're not looking to fall off that track. We'll see what the world brings us this year. I think things are set up quite well in the industry for the next few years, so as we move forward in time, that number is more likely to go down than up.

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

No, actually, it's not. So, think of the guidance we have out there for 2023. We've talked about just given the number of SPSs next year, we expect that number to be higher. Thereafter, as you think about the 2026 through 2027 timeframe, you can infer that 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. 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. If you looked at your backlog chart a bit earlier, I think you had $1.65 billion, $1.66 billion secured for 2023 already. 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 into where you think you'll be able to secure contracts that will contribute to close that gap. Any color would be super helpful.

Let me just say a couple of words, and then I'm going to hand it to Blake who's leading our global efforts there. I mentioned in my script that 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. Some we expect to have some good news soon. Others are closer to the bidding stage. This includes some of the big recurring whitespaces, and a couple of filler jobs where you see some gaps. We're working all of it right now. Maybe, Blake, just give some rig class color.

The first comment I'd make is that you asked about floaters versus jackups; I think it comes from the floater side more than the jackups, the additional backlog and EBITDA contribution. We've previously discussed the SPS as it affects whitespace, but also the short-term nature of some contracts that have hit in the UDW creates inefficiencies in the market. We're seeing just the timing of different projects or programs with mobilization and regional and contract-specific requirements. Depending on where we pick up the work and the timing, that will define the whitespace. However, converting that whitespace to operating days moves the needle for us. As Robert mentioned, when you look at the drillships, the demand backdrop is incredibly encouraging. I would say equally encouraging is our ongoing discussions with customers. We should have some highlights here soon on that. When you consider our profits for 2023, two of our D-class semi-submersibles are part of that mix. Those are some of the most capable DP plus moored units available globally. They traditionally compete for both programs that require that niche DP plus moored capability, as well as UDW capacity where there are gaps or availability on the back end. We are having ongoing conversations in both of those spaces and see several opportunities that could start for these specific rigs 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, when we adjust for the reimbursables, you still come in on the revenue side a bit higher than I had expected. My EBITDA number was also a bit higher in the range. So, around $800 million, you guide $725 million to $825 million. You mentioned that the guidance numbers take inflation into account. I think the inflation thing and then cost increases has been seen in some of your peers that have reported already. I was wondering, are you able to provide insight into how that has been factored in on a percentage basis, and how you view that going into 2024 as well, your cost base?

We've been pretty consistent around inflation for a few quarters now. 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. We expect that in 2023. As you look forward to 2024, as we expect global rig demand to continue to increase, we don't see that inflationary pressure stopping. Therefore, you should expect in a rising rig demand market, inflationary pressures in that high single-digit type area to continue through 2023 and also into 2024.

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.

In the current market, typically, contracts reflect current cost bases. Speaking generally about the industry, in the market where most contracts were signed, we are producing revenue today. A few that have some cost recovery. But it hasn't been the norm over the past couple of years. Perhaps that comes back into the market as we progress this year, but with the churn of contracts, especially 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 the commentary that your floater backlog is averaging north of $400,000 per day. Given this backdrop, how are you viewing options like potentially granting options with new contracts? Are the days of price options gone for the industry? How do you think about that in terms of long-term contracts drying, weighing price versus open-ended option pricing?

Good question separated into two answers between floaters and jackups, unfortunately. We've been probably more aggressive than the average on not giving priced options here over the past couple of years. It hasn't been a hard no, and we do have a few exceptions out there, but generally speaking, we pushed back aggressively on priced options about a year and a half ago. As the market tightens, you can expect us to continue or even stop giving options. But the jackup side is a little different. It's a soft market with more tentative economics for our customers. Options do ensure that certain wells can actually get sanctioned and drilled, which is still a portion of the market we see.

Maybe 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 we're predicting plays out, I think the market quickly reaches a point where the price for time between contracts begins to affect operators, whether that’s through mobilization or day rate recovery on a move. That’s something we’re thinking through. The growth markets I described in South America and West Africa, just by math, are the most likely to draw some more supply from us. We have decades of experience there, and as the demand in those two regions draws in supply, those are probable places you will continue to see the Noble brand build.

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. 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 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 you've mentioned. Mobilization and cost recovery; we're able to get mobilization costs not just for our actual expenses but also for the opportunity cost of lost operating days while mobilizing. 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 wanted to make sure I'm reading that right, especially for the Viking options.

You're exactly right. We don't have exposure to low-priced options or options priced earlier in the cycle. I think the exception would be the Venturer; but no, I'm sorry, all those are exercised. The remaining ones reflected are unpriced and subject to market.

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

A couple of questions for me. One is, when you state that you 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. Also, in terms of the synergies, as we think about 2023 – sorry, 2024. How should we expect to see that in OpEx and CapEx and SG&A, disregarding inflation doing whatever it does, obviously?

On the first question, we're very comfortable with our debt today, right? Our balance sheet is a strategic asset, and we're going to protect that over time. I wouldn't expect us to layer on a lot of debt on top of where we are today, but I would say we're incredibly comfortable with what it looks like right now. 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. This will come out of both G&A and OpEx, as some of that shore-based runs through all OpEx. You should expect to see the impact of that as we move through the year. Inflation, obviously, is counter to that. However, as we move through this year, we realized about $50 million – we had realized $50 million as we exited 2022. This will migrate to $80 million to $85 million by the end of the year.

Effectively, $80 million to $85 million improvement, all else being equal.

If you think about it, we realized $50 million as we exited 2022. Not all of that would show up in Q4. Some of that would. It's an exit rate. As you get to Q4 this year, you'll be realizing $85 million on a run-rate basis. Work through the year and calculate versus the Q4 baseline. You can envision an impact of about $40 million to $50 million.

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. 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.