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 Q3 earnings call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. Please limit your question to one initial and one follow-up question. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, again, press star and one. I would now like to turn the call over to Ian Macpherson, Vice President of Investor Relations. Thank you, operator, and welcome everyone to Noble Corporation's third quarter 2023 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. This conference call will be accompanied by a slide presentation that you can also find located at the Investor Relations section of our website. Today's call will feature prepared remarks from our President and CEO, Robert Eifler, as well as our CFO, Richard Barker. Also joining on the call are Blake Denton, Senior Vice President of Marketing and Contracts, and Joey Kawaja, Senior Vice President of Operations. 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. With that, I'll turn the call over to Robert Eifler, President and CEO of Noble. Good morning. Welcome, everyone, and thank you for joining us on the call today. I'll begin with some opening remarks on our quarterly results and then provide some comments on the market outlook and commercial activity before turning the call over to Richard to cover the financials. Following Richard's financial overview, I'll wrap up with some additional highlights on technology innovation underway here at Noble and the strong progress we've made with our merger integration. And after that, we'll look forward to taking your questions. First, we've reported a solid third quarter, with total revenue of $679 million and Adjusted EBITDA of $283 million. On these metrics, this was our strongest quarter since the Noble-Maersk's drilling combination closed a year ago, and these results reflect an exceptional collective effort by our employees around the world who have leaned into this merger and executed simultaneously on both the integration and the day-to-day business. So well done, and thank you all. Next, we're pleased to announce an increase of our quarterly dividend to $0.40 per share this quarter, which represents a 33% increase and demonstrates our continued commitment to maximizing value for shareholders via return of capital. Following the dividend initiation last quarter, we have signed additional contracts to bring our 2024 scheduled backlog to $1.8 billion currently, with near-term visibility to additional bookings that could increase 2024 backlog to over $2 billion. So we have taken the decision to make this upward revision just one quarter after the dividend initiation. While you should not expect us to continue to adjust the dividend each quarter, we will remain focused on maximizing free cash flow generation and as previously stated, returning the significant majority of free cash via dividends and buybacks. Turning now to the market outlook. Offshore drilling fundamentals remain robust, with the marketed utilization rate for ultra-deepwater rigs in the 90s% and leading-edge day rates for working high-spec drill ships in the mid- to high-$400,000. Leading-edge fixtures for harsh jackups outside of Norway have been in the $130,000-$150,000 per day range. During the third quarter, the drill ship, Noble Valiant, was awarded a six-month contract with LLOG in the U.S. Gulf of Mexico at a day rate of $470,000, excluding potential additional revenue for MPD services. This program is scheduled to commence in early January in direct continuation of the Valiant's current contract. Also, in the Gulf of Mexico, both of the Globetrotter drillships have recently been awarded additional contract scopes from Shell that are expected to keep both of these units working into March of next year at extension rates just below $400,000 per day. On the jackup side, we're looking forward to the redeployment of the Noble Regina Allen with a three-well program for TotalEnergies in Argentina that's scheduled to commence in mid-2024 at a day rate of $150,000, excluding mobilization. The Fenix field provides a significant source of domestic natural gas for Argentina, and this program aligns very well with the JU-3000 rig's technical capabilities and well-established operational track record in this unique, harsh environment location. So we're very excited to be participating in the revival of Argentina's offshore upstream activity with the Regina Allen next year, which will mark Noble's third drilling campaign in the country with a JU-3000 jackup. In the North Sea, the Noble Resilient has been awarded a 120-day contract with Petrogas at $133,000 per day. It's scheduled to commence next summer. Of note, the Noble Resilient sustained damages while in port two weeks ago when a floating production vessel experienced a mooring failure and collided with our rig, which was stationary in position near Quayside. There were no reported injuries. An investigation and damage assessment is underway, and we expect damages to be covered by the liable party or our own insurance, subject to applicable terms and limits. The timeline for required repairs could impact the extent of the Resilient availability for additional work before the Petrogas contract next summer. However, we do not expect the timing of the Petrogas contract to be impacted. Moving on, also in the North Sea, the jackup Noble Reacher has been extended by 15 months, with TotalEnergies via exercise of priced options, extending the rig to mid-2025, with one year of priced options remaining. These are legacy-priced options, so the day rates for the Reacher will remain materially below the more recent leading-edge fixtures. These recent jackup contract awards have significantly firmed up 2024 visibility for our non-Norway fleet, which has been a positive development. Within Norway, the timing of demand recovery continues to be hard to predict. At this point, we remain generally cautious on the outlook for this market through 2024. Thus, our idle CJ70 jackup, Noble Interceptor, is still confronted with a limited opportunity set. You can find a summarized schedule of our backlog on page five of today's earnings slide presentation. As shown, our backlog stands at $4.7 billion currently, down slightly from $5 billion as of last quarter. However, excluding our long-term commitments from ExxonMobil in Guyana and Aker BP in Norway, our backlog was essentially flat quarter over quarter. Accordingly, we're much more focused on the quality of backlog additions rather than the absolute dollar total as we progress through time, and we remain overall quite constructive on the recontracting opportunities confronting our available rigs. Two of the defining features of our floater backlog are that it is both more in step with current market pricing than most of our competitors and also more exposed to near-term rollovers than average. Putting numbers to it, our average day rate in floater backlog is $408,000, and 62% of 2024 available days across our marketed floater fleet are currently exposed to market repricing. Approximately one-third of this 2024 repricing exposure relates to the CEA rigs in Guyana, and two-thirds relates to uncontracted rig days across the balance of the UDW fleet. We think this is clearly an advantageous exposure to hold in a strong and improving day rate environment, and it also provides a measure of flexibility in how we approach shorter and longer-term contract opportunities as they arise. There is a partially offsetting negative effect from the utilization inefficiency that results from the churn of shorter-term contracts. Within this context, as previously discussed, we continue to see more white space impacting our sixth-generation floaters over the near to medium term, specifically the two Globetrotters and the Developer and Discoverer. That said, we still see a good pipeline of follow-on opportunities next year, and we do hope to announce some additional fixtures here in the fourth quarter, which would resolve some of the nearer-term rollovers in our fleet. So stay tuned. Overall, the supply-demand situation and outlook for both deepwater and harsh jackups remains very similar to what we described last quarter. The contracted UDW rig count has hovered in the low 90s since early this year, with utilization of the marketed fleet of 99 rigs stable in the low 90s%. During the third quarter, 22 rig years of UDW floater contracts were awarded. Leading-edge fixtures have priced in the mid- to high $400,000s per day for working Tier-1 rigs, a step lower in the low $400,000s for contracts awarded to rigs that are being reactivated, and mid-$300,000s to mid-$400,000s for sixth-generation rigs. Although contracting activity and utilization rates have remained firm throughout this year, we recognize there has been some concern in the market recently over the lack of apparent demand growth over the past few quarters, as indicated by the contracted UDW rig count. We see nothing to indicate any type of underlying problem with demand growth, although it has been slightly slower to materialize in the short term. Over the past few years, we've seen a similar pattern of seasonality in which volume of total UDW contracts in a given year has been slightly weighted towards the first half of the year, and this appears to be playing out similarly this year. Additionally, eight of the 14 long-term contracts that have already been awarded this year have gone to non-active rigs that are being reactivated at discounted pricing. We had originally anticipated some of these programs to go to working rigs, which, combined with normal blips here and there, with certain programs slipping to the right, has resulted in a slightly more moderate slope of appreciation in the UDW market in 2023 compared to 2022. So we're approaching the $500,000 day rate threshold a bit more slowly than we had previously expected. But if you scratch a little deeper, what you find is that the UDW market is still, in fact, tightening due to the steady absorption of the sidelined capacity. Looking ahead throughout 2024, we continue to expect a double-digit increase in UDW rig demand globally, driven primarily by incremental requirements throughout the Americas and West Africa. Brazil continues to be a major fulcrum of demand growth, and despite customary delays with their award process, Petrobras's total floater fleet is poised to expand from 24 contracted rigs currently to approximately 30 rigs over the next year, based on recent and pending awards. Additionally, major projects in Namibia and Suriname are poised to drive incremental rig requirements in established UDW basins, such as Angola and Nigeria, continue to trend higher. The methodical absorption of sidelined capacity has had a bifurcating effect on day rates over the short term. However, we believe the structural trend with day rates will continue to correlate positively with demand growth over time, which in fact, is one of the key reasons why we are beginning to see the emergence of more long-term tenders in the market as the inventory of sidelined capacity continues to dwindle and the economics for new rig construction are at such a dramatically higher plane, as we discussed in detail during last quarter's call. Just to reiterate that point, we believe that the economic threshold to support new drillship construction would be something along the lines of a 10-year contract at or above $650,000 per day, with a three- to four-year delivery time preceding contract commencement. Given these fairly straightforward supply and demand parameters, and with mounting evidence that our customers are reengaging in their long life offshore resource portfolios in a more deliberate way than we've seen in over a decade, we believe the outlook for our business is very encouraging. Now, let me turn the call over to Richard to discuss the financials. Thank you, Robert, and good morning or good afternoon, all. In my remarks today, I will briefly review the highlights of our third quarter results, as well as our outlook for the remainder of the year. Contract drilling services revenue for the third quarter totaled $671 million, up from $606 million in the second quarter. Adjusted EBITDA was $283 million in Q3, up from $188 million in Q2. Diluted earnings per share was $1.09, and adjusted diluted EPS was $0.87. Cash flow from operations was $139 million, capital expenditures were $99 million, and free cash flow was $40 million. As anticipated, revenue and Adjusted EBITDA improved from second quarter levels, with higher day rates being the primary driver. Our 16 marketed floaters were 92% utilized in the third quarter, up from 90% in the second quarter, with average day rates increasing to $404,000 per day in Q3, up from $363,000 per day in Q2. Our 13 marketed jackups were 61% utilized, with an average day rate of $141,000 in the third quarter, compared to 59% and $129,000 per day in the second quarter. As summarized on page five of the earnings presentation slide, our total backlog as of October 31st stands at $4.7 billion, versus $5 billion as of July 31st. It's important to recognize that our unique long-term commitments with ExxonMobil in Guyana and with Aker BP in Norway have an outsized impact on our total backlog profile. As such, the sequential decrease in backlog this quarter is really attributable to the six rigs operating under the ExxonMobil CEA and the Aker BP programs, which did not take on additional backlog bookings over the past three months. Current backlog includes approximately $1.8 billion that is scheduled for revenue conversion in 2024. It is important to note that our backlog excludes reimbursable revenue as well as revenue from ancillary services. Last month, we celebrated the one-year anniversary of our business combination with Maersk Drilling, and integration activities continue to progress extremely well. Our synergy realization is ahead of plan. Within one year of closing, we have realized run rate synergies of approximately $100 million, which represents 80% of the $125 million target. This is well ahead of what we communicated upon the transaction announcement and is a testament to how the two legacy companies have come together to create value for both our shareholders and customers. Referring to page nine of the earnings slides, we are adjusting our full-year 2023 guidance for revenue, Adjusted EBITDA. For total revenue, we now expect a range of $2.5 billion-$2.6 billion, versus the prior range of $2.35 billion-$2.55 billion, and for Adjusted EBITDA, our expected range is $775 million-$825 million, which is the top half of the prior range and about a 3% increase at the midpoint. These improvements in guidance ranges are driven by our strong results year to date, with revenue also benefiting from higher than expected reimbursable revenue. Full year guidance for capital expenditures remains unchanged at a range between $325 million-$365 million, excluding customer reimbursable CapEx. For reference, reimbursable CapEx has totaled $13 million through the first nine months. Notwithstanding the enhanced full-year expectation for Adjusted EBITDA, the upwardly revised range still implies a sequentially lower fourth quarter compared to the third quarter. This is consistent with our prior directional view and primarily reflects greater anticipated downtime for various rigs in the fourth quarter. The primary drivers include the Noble Faye Kozack, which has recently finished a contract in the Gulf of Mexico and is preparing for its next contract in Brazil that is expected to start in March. The Noble Developer, which finished its work scope in Brazil in late September, and the Noble Voyager, which is about to finish its current work scope in Mauritania. Looking beyond 2023, at a high level, we continue to expect a nice step up in Adjusted EBITDA and free cash flow in 2024 versus 2023, and also envision a higher weighting of 2024 EBITDA in the second half of next year compared to the first half. As previously discussed, 2024 will be the peak year of 10-year SPSs and major projects across the fleet, and as such, we continue to expect a moderate increase in CapEx next year compared to this year. Additionally, we continue to see persisting inflationary trends across our cost structure that are very consistent with the type of industry upcycle that we're currently experiencing. Therefore, we do expect something in the range of mid-single digit type percentage inflation rates on average from 2023 into 2024 across our full cost structure. Finally, I would like to provide a comment on cash flow. As our past few quarters have shown, the quarterly variability of working capital can create some short-term swings in free cash flow. During the third quarter, we generated $40 million of free cash flow, despite over a $100 million build in working capital. While some of this is a function of a growing top line, we do expect a portion of this build to reverse in Q4. As Robert stated, we remain committed to returning the significant majority of free cash flow to shareholders over time via share repurchases and dividends. We continue to believe that maintaining a conservative through-cycle balance sheet in support of a high free cash flow payout is the appropriate capital allocation formula for our business, and therefore, you can expect Noble to abide by this framework going forward. That concludes my remarks, and now I'd like to pass the call back to Robert for closing comments. Thanks, Richard. Before we move to Q&A, I'd like to close here with a couple important highlights. First, an exciting new technology that we're developing, and second, a few reflections on the one-year anniversary of our merger. On the technology side, I'm very excited to highlight Horizon56, a software platform that we've developed to promote the digitalization of well planning and execution. The benefits of digitalizing work streams and closing the gap between our customers' well programs and our drilling crews are far-reaching, impacting safety, drilling speed, management of change, elevation of lessons learned, and overall risk management. We believe the digitalization enhancements provided by Horizon56 can ultimately drive drilling efficiency gains, which obviously translates into very significant value uplift for customers, including but not limited to, well cost and emission factors. Overall, we feel fortunate to have this very talented Horizon56 team at Noble, a group that came to us by way of the Maersk Drilling combination as one of the many outstanding aspects of Maersk's human capital and technology suite. We talk frequently about the new industry landscape in which we aspire to be, as we say, first choice offshore. That ambition can only be realized with two major prerequisites, which are inexorably linked: A, scale, and B, a culture of tireless innovation and service posture, both of which we have very purposefully promoted as part of the industrial logic behind our strategic actions of the past few years. Accordingly, we remain keen to invest in and focus on areas like Horizon56, where Noble can drive incremental value for our customers. Finally, a brief reflection on the state of the company as we approach 2024. Noble recently celebrated the one-year anniversary of our business combination with Maersk Drilling, and we could not have asked for a better integration effort than we've seen so far. Within the first six months of close, we achieved operational stability and a true culture of One Noble that proved critical to our first-year success, all while exceeding synergy targets and consistently executing for our customers. Year to date, our operational uptime of 97% has been outstanding, especially for year one of an integration of this scale. And ultimately, I believe the company's third quarter results are a very clear demonstration of the power of this combination. So I would just like to conclude here with a special offering of gratitude and congratulations to our fantastic employees around the world for your tremendous efforts and for the great results that you're producing on behalf of Noble. We're off to a great start together, and the best is yet to come. With that, we'll pause here and open up the call for Q&A. At this time, I would like to remind everyone, in order to ask a question, press star, then the number one on your telephone keypad. Please limit your question to one initial and one follow-up question. Your first question comes from the line of Eddie Kim with Barclays. Your line is open. Hi, good morning. My first question is just on what feels like a pause in contracting activity over the past, you know, two to three months, at least compared to what we were seeing through kind of July or August this year. ... just in terms of the number of contracts and multi-year durations we were seeing. Should we view this as really more of a temporary pause? It seems like if based on your prepared remarks, it feels like we should. And when do you expect we'll see multi-year contract announcements start to pick up again? Yeah, thanks, Eddie. Yeah, so it is very much a temporary phenomenon. If you look back through time at just contract awards per quarter, this is not unusual at all. I think it's great-gained, you know, it's had a lot of attention, understandably. But they ebb and flow, and as we mentioned in the remarks, the second half of the year, you know, sometimes traditionally, I guess, is a little lower volume than the first half of the year. And I think that's related just to normal budget cycles for our customers. You're gonna see the working rig count increase next year. And we believe that you're gonna see duration increase as well, to your question. I think one of the potential drivers for this current pause is that certain operators, not all, but certain of the operators, some of whom are some of the bigger players, have been regrouping and connecting some of their programs together so that rather than going out to tender for one or two wells, which has been the norm for the last couple of years, they're pooling those together and probably going out to tender for some longer duration type contracts. So, no hard evidence to that yet. That's our belief, and I think that's what you're gonna see as we move into 2024. Okay, got it. Great to hear, and thanks for that color. Just my follow-up is on the comments around cost inflation next year. I believe you said we should expect kind of a mid- to high-single-digits level of cost inflation next year. Could you just expand upon that a little bit more? In what areas do you expect cost inflation to be highest next year? Is it labor, spare parts and equipment, the costs of SPSs? Any additional color here would be great. Sure, Eddie. Yeah, we said mid-single digit type inflation next year is our expectation as we sit here today. And obviously, that's an average, right? And so, as you know, you know, some elements of the cost structure are gonna be higher than others. You know, I would say on the labor side, you know, Gulf of Mexico, obviously, we're seeing inflation there from a labor perspective. So it's very, very regional, very regional dependent as well. So, you know, it's hard to give maybe more specificity than that, but I think on average, I would think about it as a kind of mid-single digit type level next year. Okay, understood. Thank you very much for the comments. I'll turn it back. Thanks, Eddie. Your next question comes from the line of Kurt Hallead from Benchmark. Your line is open. Hey. Hey, good morning, everybody. Morning. Appreciate the color. So, you know, there, I guess in the context of, you know, the progression on headline day rate and the fact that we haven't quite yet reached the $500,000 per day mark, I think I want to get your perspective, right? How important is day rate versus total contract value, right? 'Cause at the end of the day, the day rate is making up, is no longer 100% of the contract value because there's a lot of upfront costs that are being paid, some mob fees, and so on and so forth, right? So, it seems like investors are just so intently focused on the headline day rate, that they're missing the bigger picture, that the total cash value of these contracts are going up. So just want to get your perspective on that and see, is it really, you know, important to you guys about the day rate, or is it more important for you to maximize the cash value of the contract? It's a good question, and you're spot on that there seems to have been an almost myopic focus on the $500,000 number here recently. And understandably, it's a visible threshold. You know, we're headed there. We've said that before. You know, timing's maybe a little bit behind, but to your point, there's a couple of other things that go on. One, between contract contribution and efficiency does matter. Some mobilizations, et cetera, matter. I would say we're probably somewhere mid-cycle-ish on that component. So you're seeing obviously mobes and demobes. We're a ways away from kind of full revenue type mobes and demobes at this stage in the cycle, and that's a point that we reached last cycle, as you'll remember. But also, just within contract drilling margins, there is a variation between contracts, regions, types of rigs, et cetera. And so we're very much focused on maximizing our margins and our cash flow. And I think we've got some places where, you know, we're very proud to have what we think is a good combination right now and is one of the things that's driving our cash flow right now. Okay. Appreciate that color. Now, you guys referenced, you know, the prospect of seeing, you know, increased duration, and obviously, one of your competitors yesterday indicated that they've been seeing the same dynamic. So maybe give us some perspective on, you know, as you look out in potential contract awards that will come forth in 2024, you know, what sort of duration are we talking about? And relative to what we've seen so far? Like, are we seeing now a greater propensity of three- to five-year term, or are we seeing a greater propensity of, you know, two-year terms? It's the latter. But, I think what you're going to see, if I recall, if I'm citing this correctly, if you exclude the Petrobras contracts, the average contracted UDW term is like 11 or 12 months right now. And so we would anticipate that that statistic would go up, fairly dramatically next year, because we think, as I mentioned, that there are a few companies, that are moving away from one and two well contracts and into, you know, one to three-year contracts, which covers your two-year example. Okay, great. So, is this just an extension of that question, right? So we're seeing, you know, all kinds of information that's suggesting that demand for, you know, 7th-gen ultra-deepwater drillships is going to exceed supply, you know, in 2024 and 2025. In prior cycle periods, that's tended to, you know, cause some angst among the oil companies about, "Hey, am I going to get what I need when I need it? And therefore I need to basically reach further into the future and book it for a longer period of time." Based on your commentary, there's some movement toward that, but it doesn't seem like it's to the same extent. So what, why are oil companies not willing to maybe book three years versus two years, let's just say? Just again, I know it's a theoretical question, but I just want to get a sense from you guys on what kind of pushback or what kind of color you're getting in your conversations with the oil company. Sure. Yeah, I mean, you know, my view is that the market is pretty well balanced right now, and that it will continue to be pretty well balanced going forward. We've had eight or 10 rig reactivations announced this year, so that's new, so good new supply coming into the market. And there's a few, you know, small handful left, including our Meltem, that we anticipate would come into the market, just broadly across the industry, continue to come into the market through 2024 and 2025. Oil companies have, and I mentioned this kind of briefly, but they have been selectively pushing some of the programs to the right. And I think some of that is... In a couple of instances, it's, I think, been to avoid headline rate, perhaps. I think more broadly, it's trying to pull together programs, as I mentioned earlier, to get some term, to tender for some term. I think it's part of what's creating this air pocket. Takes a little longer to pull together multiple wells than just one or two wells and go to tender on all of it. I don't know whether, you know, I'm not calling for the last upcycle level of urgency in the near term. I see this as a relatively balanced market with upward movement on day rates as we move through next year and into 2025. That's great, Robert. Thanks. Appreciate that. Your next question comes from Gregory, Gregory Lewis with BTIG. Your line is open. Hey, thanks, and good morning, everybody, and thanks for taking my questions. Morning, Greg. Hey, hey, Robert. You know, realize the ink's not even dry and a lot still has to happen before, you know, and, you know, Chevron can buy Hess. But, you know, just given, you know, Hess's position in Guyana with Exxon, you know, do you have any kind of broad thoughts on what that does? Or does that change anything or accelerate anything? Just kind of as you think about, you know, that changing of a partner, I'm kind of curious if you have any thoughts around that. Sure. I mean, I think all of the most interesting answers are obviously have to come from Chevron and Hess. But from our view, you know, we feel we had an excellent relationship with Hess. We have regular contact there. And so we hope that that translates over and would hope to continue that. In looking a little bit outside of that, we of course talk a lot about Guyana. It's very important to us, and we've put a whole lot of focus on that operation, and I think the results very much speak for themselves. There's data that demonstrates our efficiency there, and we think we've got some really, really great performance from the rigs down there. So, you know, hopefully, the Chevron as a new owner of that, will see our performance. And that's a customer that, you know, we haven't done as much work for. So I see it as a potential opportunity, someone who will get a first-hand look into what we're doing. Okay, okay, great. And then, you know what? Congratulations on, you know, getting that bolt-on work on the Globetrotter rigs. It was, it was a good update to see. But, you know, as kind of we look out in 2024 and really all signs point to, you know, a definite, a pickup and acceleration, but maybe some of the work that's kind of being out there doesn't start up until, you know, mid-2024. Any kind of rough way to think about or maybe handicap as we see some kind of rigs roll off contract over the next, you know, one to two quarters? Any kind of rough way to think about, you know, idle time in between contracts? Kind of curious if you have any thoughts around that. ... Yeah, thanks, Greg. It's Blake. So maybe the best way would be to walk through a couple of the rollovers. So if I start with the floaters, and you look at the rigs that have options, the Stena Forth here in the Gulf of Mexico working for Murphy, we feel good about the prospect of continuing to serve their drilling needs. So not expecting an interruption in service there. Gerry de Souza is a similar story there for TotalEnergies in Nigeria. Don't wanna opine on what their decision will be around that option, but the election is this quarter. We know they have work there, and we believe we're performing well for them. So we like our, we like the prospect there as well. So then when you look, you look out toward the Voyager and the Valiant, you know, pleased to announce the contract we got with LLOG on the Voyager that'll start round about the turn of the year. And then there's options on the back end of that, that if exercised, would take it through the end of the year. So feeling pretty good about the Voyager. Or I'm sorry, feeling pretty good about the Valiant. The Voyager is available for 2024. It's wrapping up a program right now, mobilizing back to the Americas. And I guess we would expect with the ongoing dialogue, some work that would pick up in the first quarter of next year. The other thing to think about when we're looking at that rig class is there's roughly 30% of the forecasted UDW demand next year that still remains to be contracted. So there's some awards we think, as Robert, you know, outlined in his prepared remarks, some awards we expect in the fourth quarter that'll provide some more visibility. Super helpful. Thank you. Yeah, the only last point I would say, and it's right again, on the back of Robert's prepared comments. On the Globetrotters and the D rigs- Your next question comes from David Smith with Pickering Energy Partners. David, your line is open. Our final question comes from Pelle Bibow with Clarksons Securities. Your line is open. For our audience, please stand by. Our speakers are dialing back in. Thank you so much. Hello? Yes, thank you. Your next question comes from Pelle Bibow with Clarksons Securities. Your line is open. ... Hey, guys. Thank you for taking my, my question here, and congratulations on a stellar quarter. I guess most of my questions have been answered already, so I'm left with the final one on my list here, and I appreciate that you did touch upon this during the prepared remarks as well. But my question relates to the North Sea market and particularly the harsh environment jackup fleet. I guess we touch upon this topic every single time we have these calls, but it would be really great if you could give some more color on what opportunities you see going forward for the region. At least on our part, where we're sitting here in Norway, we see some signs, with emphasis on some, of increasing activity in 2024 and some more in 2025, but an additional color on your end would be really great. Yeah, thanks for the question. I guess I'll jump right on the back of your last statement, in that we do see some signs of increased activity, increased dialogue. I think most of those for Norway are more 2025 related than 2024. I mean, we do believe the next demand goes to us. The CJ70s are the most well suited to compete in the competition zone there in Norway. There's also the potential upside of incremental production that could come from infill drilling if there was any sort of gas shortage, whether that's a regional event or a global event. So there's a little bit of upside. I don't think there's firm demand yet to declare 2025 is, you know, it's gonna explode there in Norway from a demand perspective, but the dialogue is encouraging. In the non-Norway space, a little bit more positive in terms of the nature of the conversations with our having customers that we're having with our customers there. And of course, we've got the Intrepid that'll be locked up all of next year. So the capacity is really limited for 2024 to the Interceptor now. And we like the capability of the rig if that demand comes to pass or if unexpected demand comes to the market. Yeah, great. I think that basically answers my questions here. Thank you, guys, for taking the call, and have a great day. Thank you. Your next question comes from David Smith with Pickering Energy Partners. Your line is open. Hey, thanks. Can you hear me okay? Yeah, we can hear you. Sorry, there were some technical issues there. Good deal. Kudos on the quarter and, especially the dividend increase. That's just, great leadership on the shareholder return front. Thank you very much. Wanted to revisit your comments about the sidelined ultra-deepwater capacity. You referenced a number of rigs added over the past year, whether reactivations or previously stranded new builds, and we've seen they can make, you know, very solid returns with, you know, term duration at rates below leading-edge. But I wanted to ask your thoughts about the remaining sidelined capacity. Maybe how many, you know, high-spec drillships you think might still be brought out at rates in the low $400,000s? Yeah, I mean, I think, look, there's a small handful. It's four to six, that kind of range. From there, you start to have, I think some concessions on marketability, and you start to get into... It's all a fighting scale here, but you start to get, in our opinion, a little bit closer to 6th-Generation territory, where the rigs might be missing one of the critical components to finding a 7th-Generation. In certain instances, of course, we don't really know. Not many of them or most of them are not our rigs, but, you know, could perhaps have some higher reactivation costs, from their stacking status, et cetera. Great. We were coming up with five rigs, so really happy to hear your answer. Just a little bit of a housekeeping question. I think you're still managing the former Noble Lloyd Noble. And just wanted to ask if so, maybe how much that contributed to Q3 costs and really how much longer you expect Noble to manage that rig? Yeah, Dave. So, I think that was part of the beat from a top-line perspective in Q3. So, we are continuing to manage the CJ70 in the North Sea. You know, I think our expectation is that that will continue through kind of mid part of this quarter. But, you're right as well. If you- Sure. ... if you strip that out, I think from a cost perspective, I think it was a very nice beat in Q3. I also think, as you look at the operational performance in Q3 and the uptime, I think that was obviously a big, big component of the beat as well. Good deal. I appreciate that. If I can get greedy and sneak one more in, I recognize your semis aren't harsh environment, but they're certainly very high spec. I wanted to ask if there's any reason they wouldn't be competitive for some of the regions we've seen, you know, the Norwegian semis pulled to, right? Outside of the North Sea, you know, specifically, you know, Namibia. Yeah, look, those are some of the most capable semis in the world. As you said, they're not harsh environments, so they're not gonna go to the extreme cold weather environments. But in regions where a semi is preferred, generally, they compete very well. They can get... You know, I guess I would offer, they are generally, because they're more to NDP, they can compete down into relatively shallower waters. Semis, many semis, compete a little bit less favorably in the deeper water you get, because upwards in the 10,000-ft kinda range, you start to have some weight limitations that are specific to semi-submersibles and less so to drillships. So look, you know, like we've said before, those rigs, when they're operating in their specific niches, are gonna compete very much on a seventh-generation level. And when up against an alternative in a drillship or for whatever other reason, they may have some concession on their operation, they're gonna compete more like a 6th-generation rig. Perfect. Thank you so much. Thank you. There are no further questions at this time. Ian Macpherson, I will turn the call back over to you for closing remarks. Thank you, everyone, for sticking with us through the technical difficulty there, and thanks for dialing in today. We look forward to speaking with you again next quarter. Have a great day. This concludes today's conference. You may now disconnect.