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 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 lowest lifting costs and lowest carbon profile barrels of production, both of which aligns 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 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 sidelines 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 were 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, and 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 plus or minus 20 rigs throughout most of the past two years to 24 weeks today and 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, which represents nine floaters of demand currently, 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 a 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 up by perhaps one or two incremental rigs through 2024.

The shorter term nature of most of the contracting and the role played by more of the nimble independent E&Ps on the demand side makes the Gulf of Mexico a little hard to harder to forecast by nature. So that's outlook for the Golden Triangle which comprises about 75% of the total UDW market and an even higher percentage of the current placement of our fleet. Additionally, however, both Australia and the Med look like they could each contribute a further one to two rigs of demand to global balances. Other peripheral markets outside of these are projecting roughly flat in total. 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 in fact materialize, then we should expect to see a combination of upward day rate movement and more sideline 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 presently 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 the 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. And 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 about 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 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 huge key to better margins is utilization, not just day rates, and whitespace will certainly weigh on margins over the near term. This includes also the likelihood of losing at least most of this year for 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. But nonetheless, we do see day rate improvement for the other harsh environment class rigs into to 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.

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Richard Barker : 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 for floaters and jackup 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 a cost synergy 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, know 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. And 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. And secondly, 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 reoccurring 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 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 was 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 knock out 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. And to restate our current priorities as it relates to the use of cash 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 .

Robert Eifler: 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.

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