Shelf Drilling Ltd

Good day and thank you for standing by. Welcome to the Shelf Drilling First Quarter 2025 Earnings Conference Call. At this time, all participants are in listen-only mode. After the speaker's presentation, there will be the question and answer session. To ask a question during the session, you need to press star 1-1 on your telephone keypad. You will then hear an automated message advising your hand is raised. To withdraw a question, please press star 1-1 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to our first speaker today, Greg O'Brien, CEO. Please go ahead.

Thank you, operator, and welcome everyone to Shelf Drilling's first quarter 2025 earnings call. Joining me on the call today is Douglas Stewart. This morning, we published our Q1 financial results and our latest fleet status report. In addition to our press release and the Q1 2025 financial statements, we published a presentation with highlights from the quarter. A recording of this call will be made available on our website within the next few days. Before we begin, let me remind everyone that our call will contain forward-looking statements. Except for statements of historical facts, all statements that address our outlook for 2025 and beyond, activities, events, or developments that we expect, estimate, project, believe, or anticipate may or will occur in the future are forward-looking statements. Forward-looking statements involve substantial risks and uncertainties that could significantly affect expected results. Actual future results could differ materially from those described in such statements. Also note that we may use non-GAAP financial measures in the call today. If we do, you will find supplemental disclosure for these measures and an associated reconciliation in our financial reports. I will start with an overview of the company's performance for the first quarter and provide our latest views on the market environment I'll then hand over to Douglas to walk you through our Q1 financial results and provide updated guidance for 2025 before we open the call for Q&A. As always, our number one priority is the safety and well-being of our people. In Q1 2025, we reported a total recordable incident rate of 0.24 with three recordable incidents during the period. This result is below our expectations and led to the implementation of a structured HSC turnaround action plan, which we believe is taking hold as we had no recordable incidents in March or April. Our operating execution remains strong with fleet-wide uptime of 99.4% for the quarter, continuing our excellent operating results from 2024. In Norway, the Shell Drilling Barsk commenced drilling operations at the Sleipner B platform for Equinor earlier this month following its role as an accommodation and support unit since November last year. We are committed to delivering outstanding operational performance for Equinor. We are also working closely with them and the regulatory authority to address the recent audit observations related to IT systems on board the rig, and we do not foresee issues in completing the remaining scope in the coming months. We've also successfully completed two additional rig relocations. The Highland 2 and Shelf Drilling Victory mobilized from the Middle East and arrived in West Africa in April, with both rigs now well-positioned for near-term programs in the region. Following the sale of the Main Pass 1 and Q1, we have now completed the disposal of the Trident 8 for recycling as part of our ongoing strategy to streamline our fleet. We intend to divest one to three additional units this year for non-drilling applications to generate additional cash, reduce costs, and support market balance in key regions. During the quarter, as we previously announced, Chevron extended the contract for the Shelterlink Scepter in Nigeria for an additional year. In Egypt, we added three months of backlog to the Trident 16 contract with Petrobel. In Saudi Arabia, we're in advanced discussions to extend the Highland 5 contract with Saudi Aramco for a multi-year term. And in India, the JT Angel was L1 in category two of ONGC's recent tender and is well-placed for a three-year award, with negotiations underway to try to agree pricing and finalize a contract. Meanwhile, in West Africa and Southeast Asia, we continue to see healthy demand with a steady pace of new opportunities in tendering activity. As of March 31st, our backlog was $1.6 million, with 29 of our 33 rigs contracted at a weighted average rate of approximately $100,000 a day. Our backlog includes nearly $300 million associated with our final two suspended rigs that remain in Saudi Arabia, the Harvey Ward, and the Highland IV. Of the remaining $1.3 billion in backlog, we have strong geographic diversification with a solid mix of IOCs, NOCs, and independents. and we have a series of contract awards that we expect to secure in the next two to three months across our fleet and locations. Adjusted revenue for Q1 was $243 million. Adjusted EBITDA for the quarter was $96 million, resulting in a margin of 40% and a significant sequential improvement following two contract commencements during Q4. Quarter end cash stood at $207 million, up $55 million from year end 2024, driven by strong EBITDA generation and reduced CapEx in the quarter. Douglas will provide more details on our results and financial outlook for full year 2025. The oil and gas market continues to evolve against the backdrop of geopolitical tension, introduction of global tariffs and shifting trading policy, and short-term price volatility. The recent announced increases in production from the OPEC Plus Group have contributed to this near-term uncertainty. Brent crude averaged $75 a barrel in Q1 and have traded in the $60 to $65 range in recent weeks as a result. Despite this near-term volatility, we believe the industry's solid fundamentals remain intact. Various agencies continue to forecast incremental oil demand growth globally in both 2025 and 2026, albeit at a more moderate pace. With the recent reduction in oil prices, supply out of the U.S. is likely to be impacted, as communicated by several of the larger domestic producers in recent weeks. In addition, according to Reistad, offshore project sanctioning continues, with nearly $67 billion in spending projected for 2025, with 70% of these projects viable below $60 a barrel. We're also seeing a disciplined returns-focused investment approach from the majors, who have collectively added $25 billion in upstream CapEx through 2027, reinforcing that current prices remain supportive of continued investment. With energy security and affordability driving decisions across key regions, we remain confident in the long-term resilience of the offshore drilling sector. The jack-up market continues to display healthy utilization, with marketed utilization still north of 90%. Many of the suspended rigs in the Middle East have been absorbed into other regions. Adjusted for the remaining suspensions, utilization is still in the mid to high 80s. Despite a slowdown in new contract awards this past quarter across the industry, we continue to see a positive activity outlook in key markets. The demand profile remains concentrated in short cycle brownfield activity, a segment that is less sensitive to oil price fluctuations and continues to support stable rig activity. Long-term contracts, including the recent extensions announced by Valeris in the Middle East, and active NOC-led tendering further signal ongoing offshore investment appetite. Day rate pressures have intensified in recent months, with softer oil prices a contributing factor. We will likely see these competitive bidding levels continue for the next few quarters until the remaining rig capacity from the Middle East has been absorbed. Over the longer term, we expect to see growth in global jack-up demand as shallow water production will continue to play a crucial role in meeting the world's expanding energy needs. In addition, we anticipate further rig attrition and limited risk of future new builds, which help maintain balance on the supply side. As a result, we expect a much better day rate environment in future years. West Africa remains structurally tight, with eight rigs having relocated from the Middle East in the past year. tendering for 2026 programs is underway, and we continue to see strong demand and more resilient day rates in this region. Six out of our eight rigs are contracted beyond 2025. The Highland 2 is expected to commence its short-term contract this month while we continue to pursue longer-term opportunities for it and the shelf-dwelling victory. We are actively engaged with multiple operators across the region to secure near-term opportunities and extend coverage into 2026 and beyond, including potential deployments under our strategic alliance with Arabian Drilling. In Southeast Asia, tendering activity has held up well, particularly for 2025 and 2026 starts. Despite day rate pressures due to the influx of rigs from the Middle East, rig demand continues to remain solid across Thailand and Vietnam in particular. We are pursuing multiple opportunities for the Shelf Drilling Enterprise, which is expected to complete its contract in Thailand in Q3 of this year. We are confident that the unique capabilities of our rigs and our successful track record in the region, particularly for factory-style offline drilling operations, give us a clear advantage in pursuing upcoming opportunities. Tendering activity in India slowed in 2024, and ONGC's recent tender resulted in a surprisingly low day rate level, dampening the overall market sentiment. As I mentioned earlier, the JT Angel remains competitively positioned for a three-year award. While the recent tendering slowdown will lead to a temporary reduction in the number of working rigs. India remains a core long-term market for shelf drilling. Both the government and key operators have expressed a strong commitment to reversing the decline in domestic production from recent years. In this context, we see a constructive medium to long-term outlook for this historically resilient market, supported by initiatives such as ONGC's partnership with BP and increased policy focus on domestic energy security. Of our nine rigs in the country, six are contracted until 2026 or beyond. The Middle East remains the anchor region for global Jacob activity with over 160 rigs. While the market experienced significant disruption in 2024 due to the reduced expansion program in Saudi Arabia, we believe Aramco has now reached or is close to its baseline rig requirement to meet current production needs. A modest rebound in regional demand is expected from 2026 and beyond, supported by continued activity and multiple long-term NOC-led tenders in progress in the region. We remain closely engaged with customers, leveraging our strong operating history and the additional fleet access we have through our alliance with ADC to actively pursue opportunities. The Mediterranean and North Africa market remains stable. We see opportunities for additional work for both of our rigs currently working in Italy. For our two jackups in Egypt, we continue to engage with the current customers and other operators and expect both units to continue working beyond the current terms. In the North Sea, we see different drivers across the countries in that region. Norway remains stable with consistent rig activity supported by long-term programs with three major operators. Government policy continues to encourage offshore development, providing a supportive backdrop for the ongoing drilling campaigns. The UK has seen a slowdown in activity due to political and fiscal uncertainty, which has delayed operator decision making. However, recent M&A activity in the UK is driving a renewed focus on field life extensions and infill drilling, particularly by independents, as well as alternative demand, such as P&A and carbon capture, supporting stable jack up demand in the near to medium term. In addition, we are seeing an increase in gas directed activity in the Netherlands and expect to see demand for similar projects in Denmark As announced in early April, we received an early termination notice for the Shelf Drilling Winners contract in Denmark. The rig will now complete its contract in August of this year. We are actively marketing the winner, along with her sister rig, the Shelf Drilling Fortress, for opportunities both inside and outside of the North Sea. Our fit-for-purpose operating platform is designed for flexibility, and our sole focus on shallow water ensures that we're well aligned with where the bulk of demand is concentrated. Our core regions are among the lowest cost basins globally, where operators have demonstrated a consistent commitment to production, regardless of oil price cycles. Our redeployment of four rigs to West Africa in the last nine months demonstrates the agility of our platform. Three of these rigs have now secured contracts. which demonstrates our ability to respond quickly to shifting demand and secure backlog. In addition, our backlog coverage in 2025 offers a degree of earning stability amid broader market volatility. Our fleet of high-performing rigs is well positioned to capture near-term opportunities in key basis. While we fully recognize the current macro uncertainties and impact on investor sentiment, our priorities remain clear. Operational excellence, capital discipline, and proactive marketing to secure key near-term contract opportunities. We operate in an inherently cyclical industry, and Shell Drilling has a long and proven track record of managing costs and navigating through market downturns. That experience combined with our sole focus on shallow water, our presence in resilient low-cost basins, and our unique operating platform positions us to execute and create long-term value. Above all, we remain confident in the ability and commitment of our teams across the world. They're the reason we continue to deliver. With that, I'll hand it over to Douglas for his remarks.

Thanks, Greg. Reported revenue for Q1 2025 of $246 million included $3 million for amortization of an intangible liability related to the five rigs we purchased in 2022. We will continue to focus on and refer to adjusted revenue which excludes the impact of this item. For the first quarter of 2025, adjusted revenue was $243 million. This included $221 million of day rate revenue, $12 million of mobilization and bonus revenue, and $10 million of recharges and other revenue. Adjusted revenue for Q1 increased by $17 million, or 8% compared to Q4 2024. The sequential revenue increase was primarily driven by the contract commencements of three rigs in late Q4 2024 and Q1 2025. That's the main Pass 4 in Nigeria, the Shell Trilling Barsk in Norway, and the Trident 16 in Egypt. This was partially offset by lower revenue in Saudi Arabia due to two suspended rigs, the Highland 2 and Highland 4, which earned no revenue in Q1 2025. as well as in India following the contract completions of the JT Angel and Parameswara in late Q4 2024 and Q1 2025, respectively. The contract completions in India and the impact of the suspended rigs in Saudi Arabia contributed to a marginal reduction in effective utilization to 79% in Q1 from 80% in Q4. Average day rate, however, increased to $94,000 per day in Q1 from $88,000 per day in Q4, mainly due to higher revenues for the two rigs in Norway and Nigeria that started new contracts in late Q4 2024. Operating and maintenance expenses of $129 million in Q1 were relatively unchanged from the prior quarter. Lower operating costs for the two suspended rigs in Saudi were partially offset by higher operating costs for the main passport in Nigeria that started a new long-term contract in late Q4 2024, and mobilization costs for the shell-throwing Victory, which was redeployed from Saudi Arabia to West Africa in Q1 2025. G&A expenses of $17 million in Q1 increased from $16 million in Q4 primarily due to an increase in compensation and benefit expenses that was partially offset by a decrease in provision for credit losses. And as a result, adjusted EBITDA was $96 million in Q1. This represented a margin of 40% compared to $85 million of adjusted EBITDA and 38% margin in the previous quarter. Of the $96 million in EBITDA in Q1 2025, Shelterland North Sea generated $28 million of adjusted EBITDA. while the rest of the business generated $68 million of adjusted EBITDA. Income tax expense was $12 million in Q1, representing 5 percent of revenues, up from $7 million in Q4. Net interest expense of $36 million in Q1 was in line with the prior quarter. Non-cash depreciation and amortization expenses totaled $41 million in Q1, down from $48 million in Q4. This is mainly due to the lower amortization of deferred costs for the suspended rigs in Saudi Arabia. Net income for the first quarter in 2025 was $14 million. Turning to CapEx and deferred costs, these were $16 million, sequentially down by $15 million in Q1. This included $4 million at Shell Trilling North Sea. The decrease was mainly due to an increased utilization of existing fleet spares across the fleet. as well as lower contract preparation expenditures for the Shelter and Barsk in Norway and Main Pass 4 in Nigeria, ahead of the commencement of their long-term contracts in late Q4 2024. Our consolidated cash balance as of March 31st was $207 million, up from $152 million at the end of December 2024. Cash at the parent level increased from $131 million to $172 million, mainly due to a sequential decrease in capital spending, a reduction in debt service payments, and the sale of the main pass 1 in Q1 2025. Cash at shelf trillion North Sea increased from $21 million at the end of December 2024 to $35 million at the end of March 2025, mainly due to a higher sequential quarterly EBITDA and, again, a decrease in capital spending. In March, we also amended the $25 million term loan agreement to reflect the transfer of the loan to new lenders and extend the maturity date to March 31, 2027. As of March 31, 2025, our total consolidated liquidity was $332 million, which included $207 million of cash and $125 million available under our undrawn revolving credit facility. As a result of the recent announcement of the early contract termination for the shelf drilling winter in Denmark, we have revised our financial guidance for full year 2025 in our release today. Fully consolidated adjusted EBITDA is now estimated to be between $310 million and $360 million. This compares to our initial guidance provided earlier this year of $330 million to $380 million. At the Shelf Drilling North Sea level, we now anticipate full-year EBITDA between $65 and $80 million, a decrease of $20 million from our original guidance, which assumes the Shelf Drilling winner is idle for the rest of the year. The change in our guidance for full-year EBITDA at Shelf Drilling North Sea implies a level for the rest of the business in 2025-2022. of $245 million at the low end and $280 million at the upper end, which is unchanged from our initial guidance range. We anticipate revenues and effective utilization to improve in the second half of 2025 as rigs mobilized from the Middle East to West Africa in Q1 are expected to return to service. Our total capital spending guidance and deferred costs in 2025 is revised and now estimated to be between $85 million and $115 million, compared to our initial guidance earlier this year of $110 to $140 million. At the shelf-drilling North Sea level, capital spending is estimated to be between $20 to $25 million, compared to our initial guidance of between $25 and $30 million. This implies an expected spending level across the rest of the business in the $80 million range, down $20 million from our initial guidance earlier this year. This reduction is primarily explained by the lower capital spending associated with the mobilization from Saudi to West Africa of the Shelf Drilling Victory and Highland II, as well as the deferral of planned major out-of-service projects in India on one rig. While our updated guidance shows lower EBITDA range by 20 million, our guidance for CapEx is lower by 25 million, resulting in a higher level of expected free cash flow in 2025 than originally estimated. Our strong first quarter results demonstrate the business's strong resilience in the face of challenges as well as our operational excellence and our ability to execute. While oil prices have been volatile during 2025 as a result of certain macroeconomic uncertainty, we believe current prices remain at constructive levels to support activity across our key markets. Though the global jacket market continues to be impacted by contract suspensions in Saudi Arabia from 2024, we believe there to be sufficient opportunities to absorb most of the available rigs. For shelf drilling, we anticipate activity to improve in the second half of the year as several redeployed rigs begin new contracts. We believe we are well positioned to navigate the near-term uncertainty and capitalize on the positive long-term outlook in our sector. We'd like to now open the call for questions.

Thank you. Dear participants, as a reminder, if you wish to ask a question, please press star 1 1 on your telephone keypad and wait for your name to be announced. To withdraw a question, please press star 11 again. Please stand by, we'll compile the Q&A roster. This will take a few moments. And now we're going to take our first question. And it comes from the line of Michael Baum from Sona Asset Management. Your line is open, please ask your question.

Hi, thank you very much for the call and the update. Thank you for the call and the update. I just wanted to ask you one question regarding the ability to move cash between the parent company and SDNS. What capacity do you have at present to upstream cash from SDNS? And I assume that the covenants are quite tight at the SD&S level.

We don't have any financial covenants at the SD&S level, if that's what you meant. I mean, it's easier to send money into SD&S than the other way around. You know, we did a part of the capital that we put into Shelf Dwelling North Sea last year, $10 million of that was in a loan, so that can be repaid. The rest of the injection was a capital contribution. So there isn't, you know, a lot of, you know, quote, unquote, dividend flexibility out of Shelter Bay North Sea. But frankly, we're not really expecting to pull a lot of cash out of that group in 2025. Okay.

Thank you very much.

Thank you. Now we're going to take our next question. And the question comes from the line of Frederik Sten from Quarksen Securities. Your line is open. Please ask your question.

Hey, guys. Thank you for taking my question. I wanted to touch a bit more on the liquidity side there. You're lowering guidance, but you're effectively maintaining and even improving expectations for liquidity towards the end of the year. And you also say that you don't really expect to touch the RCF either this year and next year. And I guess my question has a few different parts. One, what really gives you confidence around liquidity over the next two years in terms of, I guess, firm visibility that you guys have that we might not have for contracting up the rest of 2026? Second, it's more on the CapEx side, if there's anything that's called sustainable on the savings that you have managed to squeeze out so far. And also, like a side question, you do talk about potentially divesting a couple of units for non-renewing purposes to get some cash and do any of your cash projections towards the end of the year, as you show in the slides here. contain any assumptions around asset sales or will any asset sale improve that liquidity beyond what you're showing? Sorry for the lot of multifaceted questions there, but appreciate any call that you might be able to give. Thanks.

Sure. So look, on the asset sale side, we sold the main pass one, I guess we signed in December, closing Q1, that price was $11 million. We have three units that have been um idle for some time too that are still in saudi and then the trident 12 i guess just finished with ongc in india we've talked about those three rigs as units we would consider also selling for non-drilling purposes and folks may have seen that it was in our q4 release we published a revised forward earnings sensitivity which is included in the deck today too that only assumes there's 28 working rigs on a kind of medium term go forward basis. That would imply there's up to five units that we're not expecting to generate meaningful free cash flow going forward. So we will consider options. We're having discussions with a number of parties. There continues to be some degree of demand for these production unit conversion type projects. So I think we're confident that if we want to do that, there will be opportunities to do it. Prices are somewhat tied to where the market is and where oil prices are. So yeah, I'm confident we'll move off of a couple of these units sort of in line with they're not too far from what we did with the main best one in Q1. On the CapEx side, look, we've seen this over 13 years. Like there are ways to pair back and defer when market conditions move. So we've had much lower levels of CapEx weaker market environments. That was the case in 15, 16, 17, obviously again, during the pandemic period. So I think for now, like this is not one of those environments. The market is a much healthier place today than it was in 15, 16, 17, and then during 2021. But we're going to be pretty focused on cost and trying to see what we can do to reduce costs structurally and defer what we can. And it's also tied to activity levels. So if activity shifts to the right, we're going to spend less in ongoing maintenance capex. So the guidance for this year is closer to 100. We've been talking about, you know, 125 to 130 as a, you know, kind of more normalized level. But that's in a normalized environment where activity is solid, rates are in an okay place, and we will find ways to moderate spending based on kind of revenue generation levels, if you will. And then, yeah, I think part of the reason we had more detail in the release today is You look at where our securities prices have traded, there seems to be this belief we're running out of liquidity tomorrow, which obviously we don't think is the case. So we're trying to provide as much comfort and visibility as possible. Douglas talked about how we think the back end of the year will improve from what we'll likely do in Q2 and Q3. The rigs we just moved to Africa, we're confident those rigs will get to work and start generating revenue and contributing margin back end of the year at a minimum. Um, you know, we tried to include some commentary around rates. Obviously rates are lower now than they were six months ago, but we have, I'd say six rigs that we're pretty focused on trying to lock up here in the next few months. If we do that, I think that'll demonstrate much better visibility into 26 with a, um, you know, a reasonable floor. Um, so yeah, that wasn't, we obviously haven't given guidance for 26. We're not going to do that anytime soon. Um, but we feel pretty good as we've looked at different scenarios that we don't think we'll need to draw on the RCF. Um, anytime soon. So hopefully that's helpful.

A key piece of that, obviously, is the level of comfort we have with 2025 and setting this up into 2026. The baseline for us.

That's very helpful. And I really think you kind of touched upon all the bits and pieces that I had. So I'll just leave it at that. Have a good day, guys. Thanks, Fred.

Thank you. Now we're going to take our next question. And the question comes from the line of Matthew Farwell from FA Advisors. Your line is open. Please ask a question. Excuse me, Matthew, your line is open. Please ask a question. Matthew Farwell, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advisors, FA Advis

Just drilling into the SDNS guidance, I was wondering if you could clarify what you're assuming for Fortress. Are you assuming that gets recontracted, or is it going to be idle? Because that would affect sort of the cash flow needs of that entity. And then also on the second half, thanks for providing some color that utilization and revenues likely improve in the second half. Could you give us an idea of any other impacts to cash flow? For example, there was a working capital outflow in the first quarter. You know, what kind of inflows and outflows could we expect that could affect cash flows in the second half?

Okay, so the first question relates to Shelterland North Sea and the fortress. We do have certain assumptions with respect to the fortress going back to work in 2025. We see some opportunities in the areas where we operate that we're taking a look at and have some good dialogue with potential customers. But yeah, so it does, the guidance does assume some level of activity for the fortress in 2025 after it concludes its contract with Total. That's the first piece. In terms of cash and movements and working capital, You know, in 2020, at the end of this year, we will have a drag a bit. We'll have day rate increases in two rigs that are pretty important, frankly, to the story of 2025. And that's the two rigs in Thailand working for Chevron, the SDK and SDC. Those rates will meaningfully increase. And, of course, from a working capital drag, the collections of that revenue and AR won't be until 2026. But in terms of natural fluctuations, obviously from a movement standpoint, you're aware that we have them acute. We had obviously the debt amortization payment in April along with interest payments. We have the shelf filling North Sea interest and amortization payment later this month. And then again in October for the big bonds and amortization and interest payment and shelf filling North Sea in November. But that's kind of how we see 2025 looking like.

Okay, great. And you extended the term loan. I was just sort of curious, did you need any amendments to the bond indenture to get that done?

No, no, actually, and we had spoken about this on previous calls. Inside the indenture, there's capacity for super senior debt of a certain amount. And what we wanted to make sure is if we had repaid that term loan in queue, especially when we repaid it, that the amount of that basket would have ratcheted down and we'd have lost that flexibility. So that was the reason why we actually, among other things, of amending that for two years as we keep that outstanding and take advantage of the super senior basket availability that's provided for under the indenture. So that should speak to your question as to whether we needed an amendment. It was intentionally contemplated by the indenture.

Okay, great. And last question is on the asset sales. Is main pass one sale of 11 million the best proxy we should be using for any kind of asset sale proceeds from the three rigs that you mentioned?

I think that's a decent number. I'd say five to 15, kind of a wide range. I mean, it depends on if it's like a recycling application, it's a pretty small number. We're not really planning to rush to do that tomorrow. because we do think there's decent demand for these alternative uses. So, yeah, I think that's a reasonable number.

Great. Thanks for taking my question.

Thank you. Dear participants, as a reminder, if you wish to ask a question, please press star 11 on your telephone keypad. And now we're going to take our next question. And the question comes from the line of Greg Brody from Bank of America. Your line is open. Please ask your question.

Good morning, everybody, or good afternoon, I should say, for you.

Hi, Greg. How are you?

Hey. Maybe you can talk a little bit about what's going on in the Middle East. You provided some opening comments about you felt that the market had bottomed out, and obviously there was some commentary a couple of weeks ago that there might be another cut out of Saudi Arabia. What are you seeing on your side? And that counters that argument as to how that impact shows.

It's hard to comment too much on market speculation and rumors. There's been so much talk about what may happen in Saudi, given what happened in 2024, and there's been almost kind of perpetual chatter and news flow about it. I think what we said, I think on our last call, is that the third round of offshore reductions in Q4 ended up being a little bit smaller. than we thought it would be for reasons that weren't totally clear. And that left the offshore rig count kind of in the high 50s, so still a handful of units higher than what the rig count was three years ago before this whole ramp up started. There was chatter about potentially a couple units being released in February, March. That didn't happen, and this talk picked up again a few weeks ago. We believe that maybe a few rigs have been impacted in the last couple weeks. Part of the challenge is you have something like eight offshore contractors, not all listed, listed in different places, so the news and communication flow isn't perfectly consistent among the contractors. There was one report that estimated that the rig count could fall pretty meaningfully offshore. We do not think that's the case. we only have two rigs left in operation. One is on a long-term contract. The other is up for renewal now. And we mentioned, we think there's a pretty good chance we'll be able to get that rig extended. So we think that, you know, direct impact on us likely is not going to be much of any in the short term. Um, so yeah, we, you know, in terms of what we know, we don't think there's much else, um, to happen in the short term, but we were wrong at times last year. I think a lot will depend on, um, you know, where oil demand goes, where oil price goes. The fact that the OPEC Plus group is lifting production, and, you know, that's really being driven by the government in Saudi, that's at least a sign that they're not still, you know, holding supply back on a kind of permanent basis. So, you know, could there be a couple of rigs that are impacted that get announced in the short term? That's possible. We think that's kind of already baked in, if you will. But any meaningful leg down offshore we think is pretty unlikely from here.

And then just you mentioned the Highland, too. You're close to a contract for that. What's an expectation for that?

So the Highland 5, we have two rigs still operating in Saudi, the Highland 9 and Highland 5. So the Highland 5, it was scheduled to finish this month. We actually signed a short-term extension we announced today that runs an extra month, and we're trying to negotiate a multi-year contract. Can't really say more than that. I think relatively confident we're able to get something agreed, so the rig continues operating. The Highland 2 is one of the two units we moved to West Africa. That rig does have a contract. We secured a 2L program. It's scheduled to start, we said May. It's the next few weeks, either late May, potentially the very beginning of June. That only runs, call it two to three months, and then we're trying to term out more work for that rig with other operators in West Africa.

we're confident we'll be able to to do so i don't know which rig you were referring to but hopefully that's helpful context i appreciate you clarifying that just a few more of the rigs and those are my final questions just the fortress i don't you mentioned that you're expecting some work this year what's the expectation for the winner and maybe you could talk about the victory as well that's also in west africa

You definitely hit the six rigs we're trying to lock in here pretty soon. So the fortress and the winner, we are marketing both the units. I think we have a pretty good sort of list of opportunities for both the units. Douglas mentioned that our guidance effectively assumes that the winner doesn't work again in 2025. That could be wrong. There's a chance we do secure work and fill in some of that time. in 2025. So, you know, we're marketing both rigs. They can participate in some of the same opportunities. There's some short-term work, there's some longer-term work, kind of back end of this year, and then starting in 26 in the region. And those are, I'd say, key priorities for us in the short term. So there is a range, right? We think it's unlikely that both rigs are idle all of the rest of the year. So the Fortress comes off in the next week or so, And then the winners in August, we're confident that we'll find at least several months of work on one of the units that's not in the backlog today, hopefully more. And then obviously trying to build as much visibility into 26 on those units as possible. But do see good opportunities in the North Sea. And then the victory, you know, we've been targeting really one program for six months. We haven't lost it. It's still there. It's just been slow. to get done. We're still hopeful that happens, but we are now obviously looking at other opportunities in the region, too. So, you know, I think we initially hoped that rig would go to work kind of immediately when it got to West Africa. That's not happening. I think we're hopeful the rig starts before the end of Q3, but, you know, that'll be predicated on finding a contract and getting it going here pretty soon.

Great. I appreciate all the time, guys, and thanks for all the liquidity commentary. It was very helpful.

Thanks, Greg.

Thank you. Now we're going to take our next question. And the question comes to the line of Nikhil Bhatt from JP Morgan. Your line is open. Please ask your question.

Hi. I just have one question left, and you probably touched upon this a bit earlier. It was mainly on your CapEx. You're guiding for CapEx to step down quite a bit outside of the North Sea business. I'm just curious in sort of how... Is that a sustainable level you see going forward in the near to medium term? Can you maintain those levels or would it have to go back up at some point?

I tried to cover this with the answer to one of the questions a few minutes ago. Our capex has not been a static number every year for 13 years. It's very much tied to activity when we secure new contracts when the market is improving and activity is growing we're typically putting rigs into new markets with new customers which drives capex higher um you know the tendering process as we've talked about is slowed down in india so we're clearly going to have less working days there in 25 than we thought a year ago so one of the drivers is that we've assumed that a project for one of the units either gets pushed to the right or doesn't happen so that's part of the reason We reduced the spending guidance for 25, and we're trying to find ways to reduce costs and defer projects where we can. So I think Douglas said that implies sort of 80-ish at the parent company level. We've been lower than that in the past with a larger number of rigs. I think we believe that in the next several years, the market will rebalance, tighten again, rates will get better, we'll probably spend more in CapEx than we're going to spend this year. So I know it's not the most specific answer, but it's really going to depend on where activity levels go.

Got it. Thanks.

Thank you. Dear participants, as a reminder, if you wish to ask a question, please press star 1 1 on your telephone keypad. Dear speakers, there are no further questions for today. I would now like to hand the conference over to the speaker, Greg O'Brien, for any closing remarks.

No, nothing for me. Very good. Thanks, everybody, for joining, and we'll talk again in a couple of months. Thank you.

This concludes today's conference call. Thank you for participating. You may now disconnect. Have a nice day.