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Operator: Good day, and welcome to the Valaris Third Quarter 2024 Results Conference Call. All participants will be in listen-only mode. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Nick Georgas, Vice President Treasurer and Investor Relations. Please go ahead.

Nick Georgas: Welcome, everyone, to the Valaris third quarter 2024 conference call. With me today are President and CEO, Anton Dibowitz; Senior Vice President and CFO, Chris Weber; Senior Vice President and CCO, Matt Lyne and other members of our executive management team. We issued our press release, which is available on our website at valaris.com. Any comments we make today about expectations are forward-looking statements and are subject to risks and uncertainties. Many factors could cause actual results to differ materially from our expectations. Please refer to our press release and SEC filings on our website that define forward-looking statements and list risk factors and other events that could impact future results.

Also, please note that the company undertakes no duty to update forward-looking statements. During this call, we will refer to GAAP and non-GAAP financial measures. Please see the press release on our website for additional information and required reconciliations. Earlier this week, we issued our most recent Fleet Status Report, which provides details on contracts across our rig fleet. An updated investor presentation will be available on our website after the call. Now, I’ll turn the call over to Anton Dibowitz, President and CEO.

Anton Dibowitz: Thanks, Nick and good morning and afternoon to everyone. During today’s call, I will begin with an overview of our performance during the quarter and provide an update on the offshore drilling market. I will then hand the call over to Matt to highlight our recent contract awards, discuss the floater and jackup markets in more detail and provide some additional color on our contracting outlook. After that, Chris will discuss our financial results and guidance before I finish with some closing comments. To begin, I want to highlight a few key points. First, we delivered excellent operating performance and financial results in the third quarter, which helped us generate $111 million of free cash flow during the period.

Second, we maintain our conviction in the strength and duration of this up cycle, and we believe Valaris is well positioned to drive long-term value creation. While we have seen some customer demand deferred, the pipeline of future opportunities in 2026 and beyond remains robust. We are focused on securing attractive long-term contracts and prudently managing our fleet to support our earnings and cash flow growth. Third, as expected, our free cash flow profile improved relative to the first half of the year, and we repurchased $100 million of shares during the third quarter. We remain committed to returning all future free cash flow to shareholders unless there is a better or more value-accretive use for it. Turning to operations. We delivered another great quarter of operating performance with fleet-wide revenue efficiency of 98%.

Achieving sustained high levels of operational performance has been an area of emphasis across the organization this year, and I’m pleased that this is our third consecutive quarter of at least 97% revenue efficiency. These results demonstrate the entire company’s focus on this key objective since delivering safe, reliable and efficient operations is vital in building longstanding customer relationships. I’d like to thank the amazing men and women offshore and all those onshore, who support them, for their efforts in helping us to achieve such outstanding performance this year. I’d particularly like to congratulate the crews of VALARIS DS-7 for achieving 100% revenue efficiency during the third quarter. This is a fantastic accomplishment for a rig that began its contract late in the second quarter following the reactivation, and demonstrates the organization’s ability to deliver complex capital projects and provide exceptional operating performance for our customers from day one.

On the safety front, we are proud to be recognized for the second year in a row by the Center for Offshore Safety with its Safety Leadership Award for the development of our restricted zone analysis tool. This innovative visual planning tool identifies safe, restricted and no-go zones for activities like pipe handling, pressure testing and complex lifts. By helping to ensure that only authorized personnel access high-risk areas, this tool significantly reduces exposure to hazardous zones, enhancing the safety of our offshore operations. In addition, we had several rigs celebrate safety milestones during the quarter. VALARIS Stavanger reached three years without a recordable incident and DS-8, DS-9, DS-17, 122 and Thunder Horse all achieved one-year recordable free, an excellent accomplishment by each of these teams.

Moving to our financial performance. Adjusted EBITDA increased to $150 million in the third quarter, up from $139 million in the second quarter. This was better than our guidance, primarily due to the team achieving strong operating performance during the quarter. This strong operating performance also contributed to solid free cash flow generation, and we repurchased $100 million of shares during the third quarter. Chris will provide further details of our financial results and guidance a little later. Turning now to the broader offshore drilling market. In terms of market fundamentals, global demand for hydrocarbons continues to increase and offshore production, particularly deepwater, is expected to play an increasingly important role in providing secure and affordable energy to meet the world’s growing energy needs.

Deepwater production is attractive to customers due to the size of deepwater fields, compelling program economics and the lower carbon emissions intensity relative to other sources of production. While spot Brent crude prices declined during the third quarter and have shown increased volatility of late, longer dated Brent crude prices have remained relatively stable. The five-year Brent forward price is around $70 per barrel, a level at which more than 90% of undeveloped offshore reserves are expected to be profitable. As a result, commodity prices remain very supportive of continued investment in long-cycle offshore projects. The commodity pricing environment and the demand drivers for deepwater in particular, have provided a strong project pipeline.

That said, this year, we have seen a year-over-year decline in the pace of contracting and a meaningful amount of customer demand being deferred into 2026. The primary drivers of these deferrals are availability of production equipment, delayed FPSOs, protracted regulatory approvals and customers’ capital discipline. While these factors have created some headwinds for next year, it is important to note that projects are being delayed as opposed to being canceled, demonstrating our customers’ commitment to deepwater production as a key component of their production portfolios. Our conviction in the strength of the market is bolstered by recent developments, including major FIDs such as TotalEnergies $10.5 billion GranMorgu development, offshore Suriname and Exxon’s reported $10 billion investment in a deepwater project offshore Nigeria.

In addition, we have seen further progression of tender processes for several long-term programs for work offshore Brazil, West Africa, and Southeast Asia. And we have also seen continued strength in day rates, particularly for high-specification drillships. Average day rate for seventh generation drillships have continued to increase year-to-date, averaging approximately $500,000 in the third quarter. The fact that average day rates remain strong despite a recent modest decline in marketed utilization demonstrates that customers see this relative softness as temporary, and they are willing to pay solid rates to secure the best assets for their projects. From a floater fleet management perspective, our first priority is securing attractive long-term contracts for our assets, and we see a solid pipeline of opportunities for our high-spec floater fleet in 2026 and beyond.

We’re also focused on securing well programs that can provide a meaningful bridge to this longer-term work. At the same time, prudent management of our active fleet and operating costs is also a priority. If a rig is expected to have a meaningful gap between contracts, we will warm stack it to lower daily operating cost as we are currently doing on DPS-5 and DS-10 until we secure its next contract. Moving to shallow water. The global jack-up market remains healthy with contracted rig counts, utilization and day rates all relatively stable. Marketed utilization for the global jackup fleet is currently 93% and average day rates for the key markets where we operate have remained firm. In the North Sea, day rates are in the mid-100,000 and in niche markets where we have a strong presence such as Australia and Trinidad, day rates are in the mid to high $100,000s.

Looking more broadly at the jack-up market, of the 27 rigs suspended in Saudi Arabia earlier this year, eight of these rigs have already been re-contracted elsewhere and is expected to be scrapped. Of the remaining rigs, we expect that less than half are competitive internationally. We mentioned on our last conference call that Valaris jack-ups 147 and 148, which were leased to Arrow had received contract suspension notices from Aramco. Together with Arrow, we elected to terminate these contracts and the rigs are now stacked in the UAE alongside VALARIS-143. We intend to keep these rigs preservation stacked until we see sufficiently attractive opportunities that warrant making the necessary investment to bring them back into our active fleet.

We have five rigs leased to Arrow that are due to complete their existing contracts at the end of 2024 or in 2025, and we are in active discussions with Aramco about extending these rigs. In the North Sea, market conditions remain balanced with all 20 active jack-ups in the U.K., Danish, and Dutch sectors currently contracted and just three rigs stacked in the region. Despite some long anticipated changes to the energy profits levy in the U.K., which were confirmed yesterday in the new U.K. budget, we see continued customer interest in the region, including multiyear opportunities that are expected to start in late 2025 or early 2026. We have good contract coverage through 2025 for our North Sea rigs and see customer demand that lines up well with our limited availability next year.

Now, I’ll hand the call over to Matt to highlight our recent contract awards, discuss the floater and jackup markets in more detail and provide some additional color on our contracting outlook.

Matt Lyne: Thanks Anton and good morning and afternoon, everyone. I wanted to begin by stating that our team is focused on building contract backlog by securing attractive contracts at solid day rates. And we see a few opportunities in late 2025 and a strong pipeline of projects commencing in 2026 and beyond that will further support Valaris’ expected earnings and cash flow growth. Since our second quarter earnings call, we’ve secured new contracts and extensions with associated contract backlog of approximately $257 million. These awards were primarily for our jackup fleet, including a 3-year contract for Valaris 118 with BP offshore Trinidad at a solid day rate. This contract strengthens our position in this attractive niche market, where we currently have 2 jackups with long-term work at day rates in the mid to high 100s.

In addition, we secured a 300-day extension for Valaris 117 offshore Mexico and added backlog to the 247 offshore Australia. Amongst our floaters, a customer recently exercised a 6-month priced option for the Valaris DS-9 ph and we are either in active discussions or participating in ongoing tenders for several of our rigs. While these discussions and tenders can take time, we expect that these will be concluded between now and our next earnings conference call and we look forward to providing updates in due course. Moving on to the opportunities we see in the market. The pipeline for work commencing primarily in 2026 remains strong. We have recently seen some programs awarded and a few other new opportunities arise. And as a result, we are still tracking approximately 30 long-term floater opportunities that we expect will turn into contracts.

Consistent with previous quarters, we continue to see the greatest number of opportunities for programs offshore Africa. We are currently tracking roughly a dozen long-term opportunities, which could lead to incremental demand requiring up to 4 additional rigs in the region by the end of 2026. These opportunities include several multiyear programs with IOCs offshore Nigeria that have expected start dates in 2026. We anticipate that we may see contract awards for at least one of these ongoing tenders before the end of the year, with a further 2 expected to follow in early 2025. We also see long-term demand in several other countries offshore Africa, including Egypt, Ghana and Mozambique. In Namibia, we anticipate the significant exploration success over the past couple of years will lead to long-term development programs commencing later in the decade.

Offshore Brazil, Petrobras recently awarded 2 long-term contracts for its [indiscernible] program. Petrobras has a further 2 tenders in process for up to an additional 7 rigs for which we expect to see contract awards confirmed in the coming months. These programs will keep many rigs occupied into 2028 and 2029, demonstrating the longevity of customer demand in Brazil. This positive long-term outlook is further supported by reports that Petrobras’ new 5-year plan could see an 8% increase in CapEx and a greater focus on maintaining oil and gas production. In addition, Brazil’s National Petroleum Agency recently announced plans to add 3 new pre-salt areas to its 2025 bidding rounds, further reinforcing the country’s focus on exploring and developing its prolific pre-salt resources.

In summary, we expect Brazil to continue to be the largest market for benign environment floaters with potential for incremental demand through a combination of Petrobras and IOC programs. Moving to the Gulf of Mexico. We expect this market to remain fairly balanced with demand largely met by existing supply in the region. While we do not expect the Gulf of Mexico to be a meaningful driver of incremental demand, recent contracting activity in the basin has been positive. With the number of drillship fixtures, rig years awarded and day rates all higher through the first 9 months of 2024 compared to the same period last year. Outside of the major floater markets, we see incremental demand from Suriname supported by Total Energy’s recent FID, which is expected to require two floaters for multiyear programs starting in 2026.

We have also seen an uptick in demand in Southeast Asia, with several operators looking at opportunities that could require incremental rigs in the region with one long-term program expected to be awarded before the year-end. As Anton noted, the global jackup market remains healthy. In the major benign environment regions, we have seen Southeast Asia, China and India all adding rigs so far this year, offset by a decline in the contracted rig count in the Middle East, primarily driven by the decrease in Saudi Arabia. In the North Sea, market conditions remain balanced, and we are currently tracking around 10 opportunities for work with IOCs or independent operators that are expected to start in late 2025 or early 2026. These are mostly new energy projects and plug and abandonment campaigns, as well as a few oil and gas programs that are well-suited for our rigs in the region.

The expected firm duration of these opportunities is more than 1.5 years on average, which is a good sign for the continued health of this market. I’m now going to review our outlook for rigs with 2025 availability, starting with our floaters. The Valaris DS-10 finished its contract in early August after more than six years of continuous work offshore Nigeria. The rig had excellent operational performance for its customer during this time, and we feel very positive about its prospects for future work that is expected to commence in late 2025 or early 2026. The DS-12 and DS-18 are both expected to complete their current contracts in 2025, with DS-12 expected to continue its current program with BP offshore Egypt into February and the DS-18 contracted to Chevron in the Gulf of Mexico until August.

We are pursuing opportunities for both rigs that could commence in 2025 and 2026. Also, in the Gulf of Mexico, DPS-5 completed its contract with ENI in July and is currently idle. We are in active discussions regarding opportunities for the rig in the Gulf of Mexico and other regions. We are focused on building a meaningful work program for the rig next year that generates solid EBITDA and cash flow. But if we are unable to do so, we will consider removing the rig from our active fleet. In Australia, MS-1 is due to finish its current contract in the second quarter, and we are in active discussions for work commencing in the second half of 2025 that would suit a moored rig like the MS-1. Our other floater in Australia, DPS-1, could work into the third or fourth quarter of next year, depending on whether the customer exercises its option.

After that, opportunities we see today for a dynamically positioned rig like the DPS-1 in country are expected to start in mid-2026. In terms of our jackup fleet, we have only two jack-ups operating in the benign environment regions outside the Middle East with meaningful availability in 2025, Valaris 247 in Australia and Valaris 106 in Indonesia. We have good visibility into additional work for these rigs either through new programs or the expected exercise of options. In the Middle East, we are in ongoing discussions with Aramco regarding extensions for five rigs that are due to complete their existing lease terms at the end of 2024 or in 2025. Lastly, we have strong contract coverage in 2025 for our North Sea jackups with less than one year of availability across our 9-rig active fleet.

Aside from some short-term gaps as rigs transition between contracts or complete planned out-of-service periods, we expect our active North Sea fleet to be fully sold out in 2025. In summary, we continue to focus on building contract backlog and capitalizing on the robust pipeline of opportunities that will support our expected earnings and cash flow growth. I will now hand the call over to Chris to take you through the financials.

Chris Weber: Thanks, Matt, and good morning and afternoon, everyone. In my prepared remarks, I’ll begin with an overview of the third quarter results and then walk through our outlook for the fourth quarter. Starting with our third quarter results. Revenue was $643 million, up from $610 million in the prior quarter, and adjusted EBITDA was $150 million, up from $139 million in the prior quarter. Adjusted EBITDA increased in the third quarter, primarily due to a full quarter of operations for VALARIS DS-7 following its contract start-up late in the second quarter and higher average daily revenue for the floater fleet, primarily related to DS-16, which started a new higher day rate contract late in the second quarter. These items were partially offset by lower utilization for DPS-5 and DS-10, which completed contracts during the third quarter and out of service time and repair costs for the 249 due to leg repairs.

Our third quarter EBITDA came in better than our guidance, primarily due to our strong operating performance. Third quarter CapEx came in at $82 million, which is slightly lower than our guidance due to timing as some spend shifted from the third quarter to the fourth quarter. We ended the quarter with cash and cash equivalents of $392 million and our $375 million revolving credit facility remains fully available, providing total liquidity of $767 million. During the quarter, we generated $193 million of cash flow from operations, which benefited from a partial unwind of the working capital build in the prior quarter. This was partially offset by capital expenditures, providing $111 million of free cash flow. We repurchased $100 million of shares in the third quarter at an average price of $57 per share.

In total, we have repurchased $300 million of shares since we started our program last year, and we still have $300 million of remaining capacity under our share repurchase authorization. Moving now to our fourth quarter outlook. We expect total revenues in the range of $570 million to $590 million, down from $643 million in the third quarter. Revenues are expected to decrease primarily due to lower utilization for the floater fleet, largely due to DS-10 and DPS-5 that are expected to be idle in the fourth quarter, DS-15 completing its short contract with BP and reverting to its legacy contract with TotalEnergies, which is at a lower day rate, and lower amortized revenue for VALARIS 247 as mobilization revenue and expense associated with its move from the North Sea to Australia was largely recognized in the third quarter.

We expect contract drilling expense of $400 million to $410 million, down from $462 million in the third quarter. It is expected to decrease primarily due to lower amortized mobilization expense associated with the 247, as I just mentioned, lower expense for DS-4 as its costs are being capitalized during its shipyard upgrade project prior to the start of its next contract with Petrobras later in the fourth quarter and lower costs for the DS-10 and DPS-5 as we transition the rigs to warm stack mode. We anticipate G&A expense of approximately $30 million compared to $31 million in the third quarter. Adjusted EBITDA is expected to be $135 million to $155 million compared to $150 million in the third quarter. This provides an expected full year 2024 EBITDA of approximately $490 million at the midpoint of our fourth quarter guidance range.

This is at the lower end of our prior guidance as we no longer expect DS-10 nor DPS-5 to work for the remainder of the year. Total CapEx in the fourth quarter is expected to be $120 million to $130 million. This is higher than CapEx in the third quarter due to spend related to the upgrade projects for Valaris DS-4 and 144 prior to their long-term contracts offshore Brazil and Angola, respectively, as well as the CapEx spend that I previously mentioned shifting from the third quarter to the fourth quarter. Looking ahead to 2025, we plan to provide full year 2025 guidance on our fourth quarter earnings call when we expect to have better visibility on the outlook for rigs that are completing contracts next year. I’ll now hand the call back to Anton for some closing remarks.

Anton Dibowitz: Thanks, Chris. I want to reiterate some of the key points we covered today. First, thanks to the outstanding execution of the entire Valaris team, we delivered another good quarter with strong operating performance and financial results, including solid free cash flow generation. Second, while we have seen some customer demand deferred, the pipeline of future opportunities in 2026 and beyond remains robust. We are focused on securing attractive long-term contracts and prudently managing our fleet to support our earnings and cash flow growth. Third, as expected, our free cash flow profile improved relative to the first half of the year, and we repurchased $100 million of shares during the third quarter. We remain committed to returning all future free cash flow to shareholders unless there is a better or more value-accretive use for it.

In summary, we believe that Valaris is well positioned to benefit from the strength and duration of the structural up cycle and deliver long-term value to our shareholders. We thank our employees, customers and investors for their support. We’ve now reached the end of our prepared remarks. Operator, please open the line for questions.

Operator: Thank you. We will now begin the question-and-answer session. [Operator Instructions] Our first question comes from Eddie Kim from Barclays. Please go ahead.

Eddie Kim: Yeah. Good morning. And thanks for all that market color. Yeah, just in light of the white space for next year and some deferred demand, I just wanted to ask about your expectations on the trajectory of day rates. We’ve been in kind of the high 400s for some time now. But for next year, I mean, should we expect some pressure for leading-edge day rates to drift lower, maybe into the mid-400s type of range before ramping up again in 2026. Just curious how you’re thinking about the day rate progression over the next 12 to 18 months?

Anton Dibowitz: Hi, Andy, it’s a good question. Let me start off and then maybe Matt can add some color if he wants. Look, I think it’s gratifying to see that day rates have continued to increase kind of quarter-over-quarter through the year. I think we can see some variety in day rates as we go forward to next year, especially with some whitespace. What we see is that customers are willing to pay solid day rates in the ranges you’re talking about, mid- to high 400s and into the 500s as we’ve seen and as we’ve recently contracted, for example, in the 2017 for high-specification assets in the right market. So I think it’s going to be a little bit dependent on the quality of the asset that’s being contracted, the markets being contracted into, but we may see some variety, especially after — as people chase kind of bridge work or shorter-term programs to bridge to longer-term work. But we think the outlook for day rates is solid.

Eddie Kim: Got it. Great to hear. And just my follow-up is on the commentary around seeing some customer demand deferred. Is this both on deepwater and shallow water work? Or was that more of a deepwater comment? And separately, you highlighted the availability of production equipment and delayed FPSOs as some of the reasons why we’re seeing these delays. Any additional color you can provide on maybe when the bottlenecks in the shipyards for FPSOs is expected to lift? I guess the concern is that if these bottlenecks last longer than expected, then it’s possible that whitespace could extend beyond next year as well. So, just any color on that would be great.

Chris Weber : Very fair question. I’d say it’s more a deepwater phenomenon, these kind of large long-term developments. The yards are really, really busy. FPSOs are taking longer to come out of the yard and there have been some delays. And I think our customers are prudently managing their business and tying when the wells are drilled to when the production equipment and the FPSOs are ready to produce that. But as with a lot of things in the supply chain, they become more — even if delivery times, for example, of equipment start being extended and are sustained, it’s about being more prepared and aligning with the realistic time line for production equipment to be developed. So we see it more as a transitory issue than an ongoing issue because expecting that an FPSO will take a year or two longer because the yards are taking longer to build them and they’re busy, ultimately, that supply chain gets stabilized as we saw kind of in our business with delivery of oilfield equipment.

Eddie Kim: Right. Okay. Great. Thanks for the color and I’ll turn it back.

Anton Dibowitz : Sure. Absolutely.

Operator: The next question comes from David Smith from Pickering Energy Partners. Please go ahead.

David Smith : Hey, good morning and thanks for taking my questions.

Anton Dibowitz : Good morning, Dave.

Chris Weber : Good morning, Dave.

David Smith : Regarding the rigs that have been warm stacked, could you share some color on your ability to reduce the cost of that idle period, kind of the timing and magnitude and how we should think about any catch-up costs once that rig secures work?

Chris Weber : Sure, absolutely. Look, I can — I think I think about it this way. So what are we going to do when we warm stack a rig? So one would be reducing manning, so down to class required minimum manning to run the rig. There’d be some maintenance and projects. And if possible, you would bring the rig quayside so you can reduce fuel costs. Now that’s not always possible, but where that is possible. So I think you can think it in terms of over a period of time, maybe about 90 days getting costs down to the kind of $60,000 range and a similar ramp-up. What that means for bringing the rig back to work, very few of these programs, you don’t contract a deepwater rig and then go to work next week. So you certainly have enough time based on the way the contracting cycle works to ramp those rigs up for just about any opportunity that’s available.

What your cost to put that back, one would be ramping up the crews and then also catching up on some of the maintenance as you minimize your spend during the warm stack period. And that’s largely dependent on how long the rig would be warm stacked. But I think about that in terms of kind of the $5 million to $10 million number for a reasonable warm stack period.

Matt Lyne: Yes. And I would add, for a ship, we’re looking at about $60,000 a day for OpEx in warm stack mode. Like Anton said, it takes about 3 months to ramp down to that. So for example, on the DS-10, we expect to be exiting the year at that run rate level. DPS-5 is about $50,000 a day and again expect to be kind of hitting that run rate level by the end of the year.

David Smith: Appreciate that color. And follow-up is I think you touched on it with commentary for the DPS-5, but could you please talk about your process for evaluating whether or not to preservation stack a rig and how that relevant criteria might vary by asset class if it does?

Anton Dibowitz: Okay. Yes, good question. Very broadly, when we think about — when you think about preservation stacking versus cold stacking, there is a cost to preserve equipment in the mid-single-digit millions and then a longer, more protracted period to bring it out of cold stack if you — out of preservation stack. So that’s not something that you necessarily want to do if you see a pipeline to future opportunity, which we do see a strong — I talked about a robust pipeline of opportunities, especially as we head into 2026. So kind of the breakeven on preservation stacking an asset, you need to not have line of sight to opportunities around the 2-year mark. So given what we see in the market, we think it makes sense to warm stack these rigs, be prudent in cash management and capital management until we can see, which we can see the long-term accretive opportunities that these rigs will have.

What you don’t want to do is to keep a rig at full operating cost, chasing short-term intermittent work with full operating cost in between. On the DPS-5 versus the ships, which generally have slightly longer-term contracts, that rig operates in a market where the contracts are by nature, generally shorter term. So our view on that is we can put an EBITDA positive cash-generating program together for it in 2025 and have line of sight to that, we will absolutely keep it warm stacked and seek that work. But just by nature, I was talking about before, chasing short-term work with high operating costs in between. If we don’t believe that is possible, that might be a candidate for preservation stacking. But that’s going to depend on kind of the line of sight to opportunities over the next few months.

David Smith: Appreciate all the color. Thank you. That’s it for me.

Operator: The next question comes from Fredrik Stene from Clarksons Securities. Please go ahead.

Fredrik Stene: Hi Anton and team. I hope you well and thank you for taking my question. So I wanted to — there’s been some press around a certain potential merger between some of your peers over the last couple of weeks. So I was just wondering if you were able to comment on Valaris place in the M&A world currently. If you see opportunities, if you want to be part of anything, are you still happy being a mixed player? Anything that can point to how you see consolidation and the way forward?

Anton Dibowitz: Absolutely, thanks for the question. Look, we still believe that there is room in this market for additional consolidation in the offshore drilling space in general. Some of the M&A that we’ve seen thus far has been drilling contractors looking to high-grade their fleet or chase additional high-spec capacity in order to gain a scaled fleet. We already have the scale that we need to be competitive in this business with the largest fleet on water. And we’re in a very fortunate position. 12 of our 13 ships are seventh gen, the assets that are preferred by customers. So we feel very good about our fleet position. That being said, we will look at opportunities for M&A. If it’s accretive and value creative for our shareholders, we’ll absolutely engage in it. But we’re certainly not in a position, where we need to — we are compelled to pursue M&A to either high-grade our fleet or to gain the scale that you need to be a player in this market.

Fredrik Stene: That’s very helpful. And I guess that kind of brings me to the second part of it. Since you emerged from Chapter 11 some years back now, you have reactivated quite a few assets, and there are still some more high-quality assets on the sideline, the DS-11, 13 and 14. But given the utilization dip that the market is currently facing and that you’ve already discussed the warm stacking of the DS-10 for example. Are you able to give us some updated thinking on how you view those assets that are already on the sideline? And I guess what I’m the most interested in is, call it, an updated time line for the potential activation of the DS-11, 13 and 14, but also if the fact that you now warm stacking some of the floaters and jack-ups for that matter, will accelerate any scrapping or retiring of the less capable assets that are also already on the sideline?

Anton Dibowitz: Sure. You’re absolutely right. I didn’t — one of the things I missed on answering your previous question was we have organic growth built into our fleet with the 11, 13 and 14, the three highest spec seventh gen 2 BOP assets sitting on the time line — sitting on the sidelines. We bought those assets, the 13 and 14 at very attractive prices. And given the pipeline of opportunities that we see 2026, 2027 and on, we continue to believe that those will be accretive purchases for our shareholders that there will be a place for those rigs in the market. You’re absolutely right. We have some headwinds coming and some white space for next year. And our priority is, first, keeping our active fleet highly utilized. Don’t think I can answer the question as far as timing to bring 11, 13 and 14 back to market. They will come back to market when the right opportunities are there to bring those back to market. I think that’s the — did I answer your question?

Fredrik Stene: I guess it’s difficult to exactly pinpoint this. But I was — I guess, is it fair to assume that they will now come slightly later than previously anticipated because you’re prioritizing your war?

Anton Dibowitz: Absolutely. Absolutely. Our first priority is keeping the active fleet highly utilized. Warm stacking is prudent cash management and fleet management in the interim, but we can bring those rigs back on a relatively accelerated time frame, kind of 90 days versus a reactivation from preservation stack, which is around a year. And there will be an opportunity to put 11, 13 and 14. But I think it is fair to say it’s on a slightly delayed time line for what we would have expected kind of six or nine months ago. Sorry, I didn’t answer to the other part of your question. I think this may be an opportunity, and I’m speaking for the market in general overall to potentially see some less capable assets come out of the market because it won’t make sense to preservation stack or keep lower spec sixth-generation assets stacked for a protracted timeline.

So, I think we may see, depending on how the next year or so develops, we may see some additional capacity coming out of the market from an overall market perspective.

Fredrik Stene: Super. That’s very helpful. Anton, thank you for answering. Have a good day.

Anton Dibowitz: Absolutely. Thanks for your questions.

Operator: The next question comes from Kurt Hallead from Benchmark. Please go ahead.

Kurt Hallead: Hey, good morning everybody.

Anton Dibowitz: Morning Kurt.

Kurt Hallead: Always appreciate the colors and the insights. So, I’m kind of curious, Anton, as you have indicated, right, a little bit of a lull here that we’re going through. So, is it — how would you think about the priority or the strategy with respect to these idle assets, right? There was some commentary from one of your competitors on an earlier call about a very robust pipeline as I think you’ve also indicated post 2025. So, are you more interested in getting these assets back into the market? Are you willing to kind of sit tight for a little bit and let other people take a little bit of a lower rate and you can get a better rate maybe late in 2025 into early 2026. So, kind of curious on how you guys are strategizing?

Anton Dibowitz: No, I think the overall market comments are right. From a market fundamentals perspective, we feel good about the pipeline of opportunities especially into 2026 and beyond. One of the reasons you need scale in this business is to be able to manage your fleet as a portfolio. And given the opportunities, have prudent fleet management during the interim period where there is some headwinds, minimize costs, lower operating costs, warm stack rigs, take people off them, manage the maintenance spend and wait for the right opportunity. Our view on it is we are looking at the right long-term opportunities for our assets to support our earnings and cash flow growth over the next few years. If we can find bridge programs, meaningful bridge programs to those, we will put the rigs to work.

That’s what we are going to do. What we’re not going to do is be spending full operating costs chasing well, low-value, not accretive opportunities that at the end of the day, when you add up the periods that you’re at full operating cost plus what you’re working doesn’t make sense for the business and for our shareholders. So we’re willing to put rigs on the sidelines at warm stack for the right long-term opportunity with a bridge to that. And if those opportunities aren’t there, then we will manage the costs accordingly. And we can do that we have a scaled fleet, and we have a number of rigs on long-term contracts.

Kurt Hallead: Okay. I appreciate that. So maybe one follow-up for you then. Again, given how the stock has been trading over the past year, you would think that day rates are about to be cut in half and utilization is going into the tank. But again, it seems like all indications that your customer base has a high degree of comfort or conviction in what their economics are for these programs. So I’m kind of curious as to what you guys can teach us that we don’t know or that the market doesn’t know that you guys do that and your customers know that maybe it can shed some light on the prospects here, right? Because, again, it looks like the stock is trading like the cycle is over.

Anton Dibowitz: I agree, markets are fickle, but I think what we look at is that global demand for hydrocarbons continues to increase. Offshore production and in particular, deepwater is set to be a solid and increasing part of that based on compelling economics of these programs, the need for the demand for secure and affordable energy. And our customers need to find new reserves in order to replace depletion. So we feel really good about the strength and duration of the cycle. And our job is to manage into and through this up cycle. So I don’t want to speculate on why the stock moves back and forth, but I tend to agree with you. We feel good about the future, and we will manage to a market that is driven by macro fundamentals that we see as solid for our business.

Kurt Hallead: Okay. Appreciate it. Thank you.

Anton Dibowitz: Thank you.

Operator: The next question comes from Geoff Jain [ph] from Daniel Energy Partners. Please go ahead.

Unidentified Analyst: Thanks. Good morning. Anton, just to follow up on that point a little bit. I think in your opening remarks, you talked about a $70 a barrel oil price and noted that 90% of offshore projects are still profitable at this level. And I wanted to dig in a bit there. That was for all of offshore, correct, not just deepwater. And then maybe any additional color on the price of which deepwater projects specifically that are being contemplated would not move forward? I know it’s going to vary by region and operator, but maybe just some insights there would be helpful.

Anton Dibowitz: No, absolutely. I mean that number is for all offshore. I think if you go look at our investor deck, we have a slide in there about where — at each price level where the production costs are. I’d say the most significant — the band where the most significant amount of that production is well clear of $70 a barrel in the $20, $30, $40 range. And a lot of these large developments that our customers are chasing are in that range, the $20, $30. So there is plenty of clear space beyond where current even spot and long-term Brent is that justifies. The economics for these programs are compelling. They are compelling at that price level.

Unidentified Analyst: And then maybe just to address sort of — you talked about warm stacking rigs a little bit. And I just wanted to follow-up on that. On a capital equipment call this quarter, it was noted that some drillers who potentially had some pockets of utilization softness might be taking advantage of some rig upgrades while rigs may not be working over the course of 2025. Could you speak to that at all? So sort of in addition to potentially progressive stacking a rig, given your confidence in the cycle in 2026 and beyond, other things you may be looking to do to certain rigs as some of these projects have been pushed to the right would be helpful. Thanks.

Anton Dibowitz: Yes, absolutely. I mean I think as you ramp down, you look to minimize your cost and minimize your cash spend. You have about a 90-day ramp-up period in order to get the rig back to work. And you would take that opportunity to maybe do some stuff so that you don’t have to stop the rig later down the line to put hard piping on, for example, for an MPD system, so you’re ready to operate in MPD mode. We are pursuing the EHSE upgrade so that we can run on less engines and lower the emissions of the rig. So you take the opportunity while you’re working on a rig and ramping up to do prudent things that will serve you as you get back to work. I think that is a fair assumption and something that we focus on. MPD and EHSE upgrades would be two that come to mind.

Unidentified Analyst: Okay. Thanks very much. I’ll turn it back.

Anton Dibowitz: Okay.

Operator: This concludes our question-and-answer session. I would like to turn the conference back over to Nick Georgas for any closing remarks.

Nick Georgas: Thanks, Jason, and thanks again to everyone on the call for your interest in Valaris. We look forward to speaking with you again when we report our fourth quarter 2024 results. Have a great rest of your day.

Operator: The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.