Operator: Good afternoon, ladies and gentlemen, and welcome to the Ensign Energy Services Inc. Third Quarter 2025 Results Conference Call. [Operator Instructions]. This call is being recorded on Friday, November 7, 2025. I would now like to turn the conference over to Mike Gray, Chief Financial Officer. Please go ahead, sir.

Michael Gray: Thank you. Good morning, and welcome to Ensign Energy Services Third Quarter Conference Call and Webcast. On our call today, Bob Geddes, President and COO; and Mike Gray, Chief Financial Officer, who will review Ensign's third quarter highlights and financial results, followed by our operational update and outlook. We'll open the call for questions after that. Our discussions today may include forward-looking statements based upon current expectations that involve several business risks and uncertainties. The factors that could cause results to differ materially include, but are not limited to, political, economic and market conditions, crude oil and natural gas prices, foreign currency fluctuations, weather conditions, the company's defense of lawsuits, the ability of oil and gas companies to pay accounts receivable balances or other unforeseen conditions, which could impact the demand for services supplied by the company. Additionally, our discussion today may refer to non-GAAP financial measures, such as adjusted EBITDA. Please see our third quarter earnings release and SEDAR+ filings for more information on forward-looking statements and the company's use of non-GAAP financial measures. With that, I'll pass the call to Bob.

Robert Geddes: Thanks, Mike. Good morning, everyone. Let's start with some introductory comments. The positive third quarter results were reflective of year-over-year market share growth of our Canadian business unit in the high-spec single and high-spec triple rig types coupled with performance-driven market share growth in the U.S. as well as consistent rig activity in our International segment. We successfully generated cash to clip off another chunk of debt in the quarter and expect to maintain our 3-year target of $600 million of debt reduction by the end of first half '26. Operationally, we ran plus or minus 25 drill rigs and 50 well service rigs around the world through the third quarter every day with stronger than expected gross margins. Our Drilling Solutions team also successfully field beta test at the EDGE AutoDriller Max with positive results adding to our technology suite of drilling rig controls technology. The finance team led by Mike Gray, successfully negotiated our banking arrangement out 3 years saving interest expense and improving liquidity. We also added to our forward book with over $1.1 billion of forward contract revenue under contract, increasing our long-term contract base quarter-over-quarter, which now brings us to about $300 million of long-term contract margin forecast in the future. And we also achieved all this with another quarter of industry-leading record safety metrics. For a deeper dive into the third quarter financials, I'll turn it over to Mike Gray.

Michael Gray: Thanks, Bob. Volatile crude oil commodity prices and fluctuating geopolitical events that reinforce producer capital discipline over the near term, impacting certain operating regions. However, despite these short-term headwinds, the outlook for oilfield services is relatively constructive and have supported steady activity in several other regions. Overall, operating days were down in the third quarter of 2025 in comparisons to the third quarter of 2024. The company saw a 4% increase in the United States to 3,194 operating days, a 9% decrease in Canada's 3,509 operating days and a 29% decrease internationally to 935 operating days. For the first 9 months ended September 30, 2025, overall operating days declined with United States recording a 2% decrease. Canada recording a 1% decrease, in international recording an 18% decrease in operating days, respectively, when you compare to the same period in 2024. The company generated revenue of $411.2 million in the third quarter of 2025, a 5% decrease compared to revenue of $434.6 million generated in the third quarter of the prior year. For the 9 months ended September 30, 2025, the company generated revenue of $1.22 billion, a 3% decrease compared to revenue of $1.258 billion generated in the same period in 2024. Adjusted EBITDA for the third quarter of 2025 was $98.6 million, 17% lower than adjusted EBITDA of $119 million in the third quarter of 2024. Adjusted EBITDA for the 9 months ended September 30, 2025, totaled $282.3 million, 16% lower than adjusted EBITDA of $336.7 million generated in the same period in 2024. The 2025 decrease in adjusted EBITDA was primarily as a result of lower base revenue rates and onetime expenses related to activating and deactivating and moving drilling rigs. Offsetting the decrease in adjusted EBITDA was the favorable foreign exchange translation on U.S. dollar-denominated earnings. Depreciation expense in the first 9 months of 2025 was $252 million, a decrease of 4% compared to $261.8 million for the first 9 months of 2024. General and administrative expense in the third quarter of 2025 was 5% lower than in the third quarter of 2024. General and administrative expenses decreased primarily due to nonrecurring expenses incurred in the prior year and tight cost controls. Offsetting the decrease in the annual wage increases and the negative translation effect of converting U.S. dollar-denominated expenses. Interest expense decreased by 23% to $18.4 million from $23.8 million. The decrease is a result of lower debt levels and effective interest rates. During the second quarter of 2025, $40.8 million of debt was repaid for a total of $83.8 million, repaid during the first 9 months of 2025. The company has revised its previously announced debt reduction target of $600 million, which now will likely be achieved in the first half of 2026. The revision is a result of current industry conditions and the reinvesting into the company's -- company through capital expenditure. If the industry conditions change, these targets may be increased or decreased. Total debt net of cash has decreased $98.5 million during the first 9 months of 2025 due to debt repayments and foreign exchange translation on converting U.S. dollar-denominated debt. Net purchases of property and equipment for the third quarter of 2025 was $62.4 million consisting of $13.9 million in upgrade capital and $50.5 million in maintenance capital, offset by dispositions of $2 million. For 2025, maintenance CapEx budget is set at approximately $154 million and selective upgrade capital of approximately $35.5 million, of which $19 million is funded by the customer. The increase in upgrade capital expenditures in 2025 is due to the previously announced awarded 5-year contract for 2 additional rigs in the company's Oman operations as well as rigs being relocated from Canada to the United States. On that, I'll pass the call back to Bob.

Robert Geddes: Thanks, Mike. So let's start with an operational update. The summer was quite active for us right across all of our world in a different country. So as we methodically grew rig count in the very active higher-margin, high spec triple and high-spec single rig type categories in North America. Let's start with Canada. Canadian drilling, we have 43 drilling rigs active today in Canada and expect to add a few more before year-end, and we expect to peak in the first quarter '26 of roughly 55. We're starting to see more and more clients go along in their contracts especially on the higher spec rigs. One example, we just signed 2 of our super high-spec triples on 3-year contracts, locking in $100 million of revenue, roughly $30 million EBITDA out to late 2028. While we have seen some spot market prices drop into the fourth quarter on the cold rigs as people try to get them going, we have generally been raising our prices in our 2 high utilization categories. Again, the high-spec single and the high-spec triple by about 2% a quarter. The trend for the entire year has been steadily moving up on these rig types as supply tightens. The value proposition is still valid for decline as we continue to perform by improving drilling efficiency, offsetting any rate increases. Also because the rig equipment is being run closer to its technical limits more and more, rate increases are quite just to offset the higher operating costs. We continue to see the Canadian market adopt our EDGE drilling rig automation more and more every quarter, which provides a high-margin bolt-on incremental revenue stream of anywhere from $1,000 to $2,600 a day across high-spec triples generally. We continue to address any upgrades that operators request by assisting the upgrade capital to be paid for by the operator with a notional rate increase or we adjust the day rate incrementally in order to achieve a 1-year payout or less on incremental capital with the incremental rate increase. Moving to the U.S. drilling. While the statement, drill, baby, drill, is true in the sense that more footage was drilled year-over-year, the problem is that because the rigs are drilling more footage per day, we have the same number of rigs making more whole. We are finding that the double-digit rig efficiency gains of years past has slowed into the single digits as we get closer to the technical limits of the rig equipment itself. This is good news and an indication that we are at or near a trough. Operators now focused on continued duplication of their best wells. We also have a situation where most operators are starting to look at Tier 2 acreage now as we move along in the future. We also saw the U.S. iredoil production close to 14 million barrels per day. So with the technical limits of rig establishing somewhat of a ceiling and with Tier 1 acreage finishing, we will need to see rig count move up if we were to hang on to 14 million barrels a day of production in the U.S. I have mentioned before, it's interesting to start hearing from operators more and more, the geologic headwinds are stronger than the tailwinds from technology and operational efficiency gains in the last 5 years. Again, another indication we have troughed. So in U.S. today, we have 41 high-spec rigs, mostly high-spec triples, out of our fleet of 70-plus high-spec ADRs operating across the U.S. California to the Rockies down into the Permian. Permian, of course, being our busiest area with roughly 25 rigs operating daily there. We've been able to increase our market share in the U.S. by about 50 bps through the year, the result of our high-performance rigs in cruise in concert with our EDGE Drilling Solutions technology. We're also starting to see some light at the end of the tunnel in California and expect mild increase in rig activity there. On that note, our EDGE Drilling rig controls product line continues to expand with increasing adoption of products like our ADS, the automated drill system, not only do we get a superior rate for our EDGE AutoPilot technology, we capture the upside value generated to the operator through performance metrics. Everybody wins. The operator delivers wellbores for lower cost and help derisk that with our PBI contract for at higher margins than Ensign. Our directional drilling business, which is essentially a proprietary mud motor rental business continues to improve some of the best motors of high-quality rebuild the longest runs in the Rockies. We're expecting a solid year for 2025. International, we have a fleet of 26 high-spec rigs that operate in 6 different countries outside of North America which are 13 are active today, up 2 from our last call. In Kuwait, we have been successful in contract extensions on both our 3,000-horsepower ADRs, taking us well into mid-2026. We started back up in Venezuela with the first rig a few months back. And just this week, we started up our second rig. As you know, there's a lot of things going on in Venezuela. Last call, we mentioned we had an unplanned incident in one of our ADR 2000s. In Argentina, happy to report that we're able to minimize the downtime of the operation by replacing this intersection and recommissioning that rig in record time, which manifested itself into landing another 1-year contract extension on that rig with a major. We have both our rigs in Argentina under long-term contracts now. In Oman, the new rigs we have undergoing extensive upgrades are on budget the on time with the first rig expected to be operational in December this year and the second rig in late March. This will add to the 3 ADRs currently under contract in Oman and bring us up to 5 eventually in '26. In Australia, we have 4 rigs active today with strong bid activity, which we feel will take us to 5 to 6 rigs by year-end. We're also successful in extending the contract out another year to the end of '26 on our Barrow Island rig. Moving to well servicing. We have a fleet of 88 well service rigs in North America, 41 in Canada, of which we operate 15 to 20 on any given day. Plus we have 47 well service rigs, primarily in the Rockies and California where we operate with relatively high utilization rates in the 70s consistently. Our U.S. well servicing business, which is focused primarily on Rockies and California has battled a tougher market and is off about 24% year-over-year for the quarter and is expecting not much change for the remainder of the year. We are seeing operators stick to their budgets and not accelerate any '26 plans into 2025. Our Canadian well service business folks focuses primarily on the heavy oil market, and that's been a very steady business with rates increasing at about 3% per quarter. Our technology, our EDGE AutoPilot drilling rig control system. In our last call, we reported that we successfully beta tested our Ensign EDGE Auto, Two-Phase control in conjunction with the DGS, Directional Guidance System. This paves the way for seamless control of automated directional drilling with those operators who utilized remote operating centers and utilize in-house DGS systems. I'm happy to report that we're now fully commercial with our EDGE, our Two-Phase control and are charging out our 4 rigs today with the possibility of placing that on a fifth rig for the same operator. We've also initiated the development of an Ensign EDGE state-of-the-art directional guidance system, DGS. We expect to be beta testing this mid-2026. With this, we'll be able to provide a complete and comprehensive drilling control system offering with all the bells and whistles -- excuse me. We have completed our bit of testing of our AutoDriller Max which will further increase penetration rates and be charged out with a daily base rate about $1,000 a day plus a variable per foot or per meter rate so that we can start capturing the upside on the cost and operational efficiencies that our technology enhancements provide to the operator. We plan to roll this out commercially later this year on both sides of the border. So with that summary, I'll turn it back to the operator for questions.

Operator: [Operator Instructions]. Our first question comes from the line of Keith MacKey from RBC Capital.

Keith MacKey: Maybe just want to start out in the U.S. Contract book looks like everything is currently under 6 months in length. Can you just talk about what do you think that means for where we are in the cycle and potential contract earnings going forward as we look to 2026?

Robert Geddes: So we probably have, I would say, a quarter we tied up on annual contracts, Keith. It is a good question in the sense that it is a forward indicator of what operators are thinking. When they start to want to contract to sell longer. And we just responded to a bit here earlier in the week with a major -- and it's a 5-year contract. When we start to see operators asking us for 5-year contracts, it tells me they also believe we're at a trough. So that's a key indicator. Some of the other projects, of course, are smaller companies. They don't have the longer-term projects. They tend to contract a rig for 6 months, somewhere in there. So I think the takeaway is we're starting to see some indication. Like last year, we weren't negotiating anything in 5-year contracts. It was all 1-year contract.

Keith MacKey: Yes. Got it. So U.S. operators are starting to, at least on a one-off basis, ask you for longer-term contracts, okay.

Robert Geddes: Correct. And as I mentioned in the call, we also have Canada. We've got -- we signed up 1 for 3 years, and we're in the middle of negotiating another one for a longer term as well. So starting to see some indications.

Keith MacKey: Yes. Okay. So maybe let's talk a little bit about Canada. Rig count is down year-over-year in Q3, certainly. But we've also seen some of your competitors or at least one of them move rigs back to Canada from the U.S. Can you just talk about the competitive dynamics in the deep capacity or the triple market right now? How is the market unfolding? Is capacity really as tight as you think it as we all think it is? Is there some telly doubles that are kind of taking up some capacity now in the market that you hope triples might displace? Just if you can help us reconcile any of those comments, that would be helpful.

Robert Geddes: Yes. So the high-spec triples, the -- but let's say like the 1,200 horsepower class, triples the smaller end of the high spec triples. As you mentioned, we saw a competitor move a couple up into Canada and willing to foot the bill themselves for the upgrades. The higher spec, the 1,500 high-spec triples is tight enough where if an operator asked us to do that, they'd be paying for the whole bill to get it up here and they'd be paying for the upgrades. So it's a tighter market in the 1,500-horsepower class. The 1,200s start to bridge gap between the higher spec deeper telly doubles, but the 1,200s will win that game. So they're filling a little bit of the gap there. But the high-spec triples are definitely, as I mentioned, we were able to negotiate a 3-year contract with a rate increase and it's still a very tight market on the 1,500s. They're running about 80% utilization on those -- on that specific rig category, which is almost full utilization because that's -- you're going to move the rig and everything else. So you never get to 100% utilization. 80%, 85% is almost 100% in essence, from a bidding perspective.

Keith MacKey: Yes. And Canada has always been a bit more of a smaller triple market relative to the U.S., but are you starting to see incremental demand for 1,500-horsepower triples?

Robert Geddes: Well, yes, if the question is building up into another BCF of LNG, I think that's still a year out. We are seeing people wanting to make sure that the good rigs they have, they keep. So they're able to look into the future at least 3 years and go, hey, these good rigs you want to keep. So they're getting signed up. We have conversations ongoing with a few operators on current rigs that they're using. They're saying, what would it cost to upgrade it with the high-torque top drive, notional items like that. It is a tight market, but we're still a long ways away. We're $20,000 a day for any new build metrics.

Operator: Our next question comes from the line of Tim Monachello from ATB Capital Markets.

Tim Monachello: Looking at the international market, you guys have done a pretty good job of reactivating equipment. Venezuela, can you talk a little bit about the dynamics at play there? And maybe your view or visibility to those 2 rigs running into 2026 here?

Robert Geddes: You're talking in Venezuela or...

Tim Monachello: Yes, in Venezuela.

Robert Geddes: Yes, yes. Who the hell knows? Quite seriously. It is a dynamic file for sure. We've got a great team down there that our team are Venezuelans. So we've got a client that runs with OFAC. So it's at the whim. But you all read the same thing we do. There's a lot of tension there. I think that it could play out well. But in any case, we don't have to put any capital into these rigs. When we started them up a year ago, the operator wanted new top drives, we said, you buy them, we'll put it on the rig and we'll own them, but you're going to buy them. So we haven't put any cash into the rigs. And we're able to get U.S. dollars out. That's our contracts. And it's only 2 rigs in our world of 100 rigs running every day. But it's certainly a little bit of excitement there for sure. But I'm thinking that it plays out better in '26 than the up and down we saw in '25. But who knows?

Tim Monachello: Okay. So essentially, they're on like well-to-well programs and kind of...

Robert Geddes: We signed contracts. Yes. We signed 6-month contracts and they just roll over.

Tim Monachello: Okay. Got it. And then is there any I guess, visibility into additional rig deployments in the Middle East for '26?

Robert Geddes: So as you know, we're major upgrades on 2 ADRs in Oman. And we've got quite a good brand in Oman. The Ensign brand is really the gold standard for operations. And we're always in conversation with -- we've got a mobile rig fleet of 186 rigs around the world that we can put in the different areas. As you saw, we moved 2 from Canada to the U.S. could we move 1,500s from the U.S. into the Middle East? Yes, could we move a 2,000-horsepower from the Middle East into the U.S.? Yes. I mean it all depends on the commercial situation. So we've got a lot of flexibility and mobility of rigs.

Tim Monachello: Okay. And then in the U.S., I just want to circle back on the contract terms that Keith was discussing. And I'm curious, given that you see a customer coming looking for 5-year contracts, like the market is not -- I don't think anybody is saying the market is tight in the U.S. So do you think that that's more opportunistic, somebody looking out a couple of years and saying, hey, these are pretty good rates right now, I want to lock them in? Or is there something more structural or something -- some other factor that maybe I'm not considering here?

Robert Geddes: I think that when an operator is going and looking for 15 to 20 rigs of different -- in different areas with certain specs, all of a sudden, that tightens the field that or have the ability to bid and meet those specs. So they -- I find some of the majors every 5 years, they'll want to tighten up their rig spec because they now know what is good for what areas and then they go out to bid and they go, here's what we want, tighten up your rig spec and it's usually a high-spec rig spec and let's go forward. And usually, it involves some capital, different companies address that differently and hence, why they usually go out for a 5-year contract as well because they're going, hey, we want to put this on the rig. They do know that contractors are not going to spend a bunch of money on the way it's going to go well.

Tim Monachello: Would you entertain a 5-year contract at current rates? Or would you need significant premiums to current market rates or spot rates as well?

Robert Geddes: Yes. Yes, we would ask for the operator to provide the grade capital. And it depends on the situation. We have -- we would propose rates at -- with PBI contracts are in the low 30s. That's kind of where we'd be low to mid-30s, which is probably in the upper quartile of our pricing spot bid pricing is lower than that. We would not entertain pricing lower than that for that type of term. And we usually put escalators in those types of contracts as well. Obviously, we have a cost base coverage on any escalation. But if someone said, can you hold your current rate of 5 years, we'd probably be a no to that, and we'd be showing some rate increases forward, and we'd be asking the operator for all the upgrade capital upfront.

Tim Monachello: Okay. That's helpful. And then I wanted to circle back again on your comments in your prepared remarks regarding drilling efficiency and geological decline. Are you -- anecdotally, we've been hearing with that for a long time or at least perhaps anticipating it on the horizon. Are you seeing anything in the field like are you seeing your rigs working in Tier 2 acreage more often now or any other sort of tangible evidence that you're seeing acreage declines?

Robert Geddes: Well, it's one of those things, people define their acreage differently. There's -- I remember, companies 3 or 4 years ago, had 5 levels of tier. And then some today are going, we have Tier 1, Tier 2, Tier 3. And then there's no real strong definition. We do hear people talk more about, hey, in 2026, we'll be starting to go more Tier 2 acreage. But no one comes up and says, okay, we want you to go to this Tier 2 play and go drill it or go to this Tier 1 play and drill it. It's more the notional conversations. And of course, Tier 2 were not as productive as Tier 1. They are drilling the Tier 1 first. But we're seeing and hearing them talk more about it. So there must be some truth to it.

Tim Monachello: I guess on the leading edge, are you seeing any of your operators starting to increase activity?

Robert Geddes: We have, I would say, for '25, it's been a budget exhaustion. They've been holding on to their -- our rigs. We've got 2 operators that increased our rig count because of our performance. But you've seen the rig count. You know the rig count as well as I do, it's stuck at 250 in the Permian, about 550 in the U.S. But we are drilling more footage year-over-year, but the rate of increase is now into the single digits. We're running about 5% to 6% more footage drilled per rig where 2, 3 years ago, we were 14%, 15% year-over-year. So we're starting to hit that speed of sound, the technical limit of the equipment is what we're starting to see. And you're seeing operators start to think more about doing a U-turn coming back on their acreage, relooking at their acreage. So those are indications that to hang on to 14 million barrels a day. They're going to have to -- I believe we've troughed at the rig count that we're at today are pretty close to it, let's put it that way, is what the data would tell us.

Tim Monachello: Got it. And then the U.S. last question for me. Are you seeing any opportunities in gas stations?

Robert Geddes: Well, a little blip in gas this week. But no, and here's why. The gas oil ratio in the Permian as you increase production, the gas oil ratio is going up, which means about a Bcf a year. So takeaway capacity is going up from 3 to 4 to 5 moving up as we increase production of the Permian and gas oil ratios go up. So we're not seeing -- we've got anecdotally, 1 or 2 clients that are saying, hey, we want to maybe go drill a Haynesville well, but it hasn't moved the needle much, no.

Operator: Our next question is from Aaron MacNeil from TD Cowen.

Aaron MacNeil: Mike, this one is for you. I think, obviously, I can appreciate all the reasons for the pushout of the $600 million debt reduction target. I guess the question is, when you inevitably hit that target, what's sort of next from a capital allocation perspective?

Michael Gray: Yes. I think at that point in time, I mean, you look at what's the best use of proceeds. I mean from our point of view, I mean debt reduction is still going to be key. So you'd probably get to that 1, 1.5x debt to EBITDA. So that will be probably another 1.5 years away from that happening. So our view would still be paying off debt, lowering your interest costs which gives you free cash flow into the perpetuity. So yes, I think we'd definitely take a look at it. But debt reduction is still going to be our focus for the next while.

Robert Geddes: Yes, complete full discipline on that, absolutely.

Aaron MacNeil: Fair enough. And then maybe to build on one of Tim's questions. How do you think about scale in all these international jurisdictions that you operate in? And would you ever consider exiting some of these markets as another potential source of deleveraging to the extent that you could find an interested buyer?

Robert Geddes: Yes. Well, we typically don't run. We typically figure out, get through because we understand there's cycles in every area. I suppose Libya is the only area in the world that we've ever left because the Board just took over the equipment. But you've seen how we've managed through Venezuela. You've seen how we've managed through Argentina. To answer your question on scale, we like to get to 5 rigs running in any given area to appropriately manage supply chain and overhead and operational supervision. That's kind of the target. So in Australia, we're there. Venezuela, where we're not, for obvious reasons. Argentina, we only have 2 rigs there. We're in discussions with some people for perhaps a few more rigs. But we'd like to get the 5 there. In the Middle East, we throw a blanket over the Middle East, Oman will be to 5. Kuwait, we have full utilization there with 2 big rigs. And those are 3,000-horsepower rigs, and those rigs don't grow on trees. There's $60 million to $70 million rigs rates are not conducive to add any into that area nor are they looking. So that's how we look at the world. We're also not interested in going into any new markets either. We'd rather double down and get more of the markets we're in and increase efficiency that way.

Operator: Our next question is from Josef Schachter from Schachter Energy Research.

Josef Schachter: Bob and Michael. Mike, I just want to cover 1 issue that's been covered in the new issue. Going back to the debt, if EBITDA grows and we get $70, $80 oil a couple of years down the road, is the target to have something like $500 million of debt from the $925 million. And are you looking in your guidance for 2026 to give us a number like $100 million each year kind of number? Like I'm trying to get a feel for the progression of debt reduction.

Michael Gray: Yes. No guidance for '26 as of yet. But I mean if you kind of look at break consensuses and how CapEx kind of flows out, I mean, it should be $100 million, in excess of $100 million. When we look at the overall debt level, I mean, yes, that $500 million is probably a good number to get to, just given the volatility we see in the market and pre-the Trinidad transaction, we were kind of around that $500 million-ish. Give or take, so I think around that would be a reasonable bumps to kind of run forward, and that gives you the kind of the flexibility to deal with the ups and downs.

Josef Schachter: Okay. And then, Bob, I'm reading stuff from -- and listening to interviews, Comstock is talking about drilling 19,000 vertical insulating pipe because 400 degrees Fahrenheit and needing to stack 30,000 feet of pipe. Is that a totally new class of rig? Or can you handle drilling for these deeper zones that are -- that Comstock and others that are going after?

Robert Geddes: Yes. No, we absolutely have -- over the last 1.5 years, we've been -- we have a few rigs that can rack 30,000 to 35,000 feet of pipe. We've got no less than 4 or 5 rigs right now that have been modified to that to be able to handle that with 5.5-inch pipe and handle that 30,000-plus racking capacity on pad work with 5.5-inch pipe. So that's not uncommon for us now. We have lots of those kind of conversations.

Josef Schachter: Any potential signing up? Or is it just early conversation days?

Robert Geddes: No, no, these are rigs that have been modified and are under contract. Yes, it's not a notion. It's happening, yes.

Josef Schachter: Yes. Is this your highest day rate rigs?

Robert Geddes: Yes, it would be. Yes.

Operator: Our next question is from [ Marvin Mameda ] from [ Mucinex ].

Unknown Analyst: Congrats on the release. I had a quick question about the client funded CapEx. When will we see that hitting your cash flow statement, I don't think it has yet, right?

Michael Gray: Part of it has. So you'll see it throughout the next sort of 6 to 12 months. So contractually, there are some things that need to be completed for some of the funding to go through. Yes, you'll see it sort of over the next 6 to 12 months.

Unknown Analyst: Basically, you're getting paid by the clients after you spend the money within 6 months?

Michael Gray: I know there's some prepayments as well.

Unknown Analyst: And could you clarify on those 2 rigs signed in Canada. So you said it would be $100 million over the course of 3 years in revenues for each or...

Michael Gray: Correct.

Robert Geddes: $100 million total for 3 years, yes.

Unknown Analyst: But over 3 years at 30% EBITDA margin.

Robert Geddes: Right, for both rigs combined.

Unknown Analyst: Yes, thank you.

Operator: There are no questions at this time. Please continue.

Robert Geddes: Okay. I'll move forward to closing statement then. Obviously, the last few months have been a roller coaster with the global markets unsettled and the tariff negotiations, which has impacted, to some extent, some cost of business notionally until now could impact it more if they stay on the cost side of certain pieces of equipment that, again, we typically pass on to operators as escalation. Looking forward, we continue to execute the plan on reducing debt while delivering the highest performing operations safely around the world. As I mentioned earlier, we increased our forward contract booked by roughly $0.25 billion now up close to $1.1 billion of forward revenue booked under contract. We continue to push operations or operators to fund upgrades, and we are still very stingy on capital. We are right on track with our maintenance CapEx program and can manage nicely operating 95 to 100 drill rigs and 50 well service rigs daily around the world in this commodity pricing environment. So with that, we'll look forward to our next report in the New Year. Thanks for calling in.

Operator: This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.