Good afternoon, ladies and gentlemen, and welcome to the Ensign Energy Services Q3 2025 Results Conference Call. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question-and-answer session. If at any time during this call you require immediate assistance, please press star zero for the operator. 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.
Thank you. Good morning and welcome to Ensign Energy Services Q3 Conference Call and Webcast. On our call today, Bob Geddes, President and COO, and myself, Mike Gray, Chief Financial Officer, will review Ensign's Q3 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 discussions today may refer to non-GAAP financial measures such as adjusted EBITDA.
Please see our Q3 earnings release and Cedar Plus 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.
Thanks, Mike. Good morning, everyone. Let's start with some introductory comments. The positive Q3 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 attain our three-year target of $600 million of debt reduction by the end of Q1 2026. Operationally, we ran plus or minus 25 drill rigs and 50 well service rigs around the world through the Q3 every day, with stronger-than-expected gross margins. Our drilling solutions team also successfully field beta-tested the Edge Autodriller Max with positive results, adding to our technology suite of drilling rig control technology.
The finance team, led by Mike Gray, successfully negotiated our banking arrangement out three 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 forecasted future. We also achieved all this with another quarter of industry-leading record safety metrics. For a deeper dive into the Q3 financials, I'll turn it over to Mike Gray.
Thanks, Bob. Volatile crude oil commodity prices and fluctuating geopolitical events have reinforced 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 has supported steady activity in several other regions. Overall, operating days were down in Q3 2025 in comparison to Q3 2024. The company saw a 4% increase in the U.S. to 3,194 operating days, a 9% decrease in Canada to 3,509 operating days, and a 29% decrease internationally to 935 operating days. For the first nine months ended September 30, 2025, overall operating days declined, with the U.S. recording a 2% decrease, Canada recording a 1% decrease, and 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 Q3 of 2025, a 5% decrease compared to revenue of $434.6 million generated in Q3 of the prior year. For the nine 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 Q3 of 2025 was $98.6 million, 17% lower than adjusted EBITDA of $119 million in Q3 of 2024. Adjusted EBITDA for the nine 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 a result of lower base revenue rates and one-time 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 nine months of 2025 was $252 million, a decrease of 4% compared to $261.8 million for the first nine months of 2024. General and administrative expense in Q3 of 2025 was 5% lower than in Q3 of 2024. General and administrative expenses decreased primarily due to non-recurring expenses incurred in the prior year and tight cost controls. Offsetting the decrease is 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 the result of lower debt levels and effective interest rates. During Q2 of 2025, $40.8 million of debt was repaid for a total of $83.8 million repaid during the first nine months of 2025.
The company has revised its previously announced debt reduction target of $600 million, which now will likely be achieved in Q1 of 2026. The revision is a result of current industry conditions and the reinvesting into the 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 nine 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 Q3 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 five-year contract for two 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.
Thanks, Mike. Let's start with an operational update. The summer was quite active for us right across all of our world in eight different countries 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. We expect a peak in Q1 2026 of roughly 55. We're starting to see more and more clients go long on their contracts, especially on the higher spec rigs. One example, we just signed two of our super high-spec triples on three-year contracts, locking in $100 million of revenue and 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 two 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 the client as we continue to perform by improving drilling efficiency, offsetting any rate increases. Also, because our rig equipment is being run closer to its technical limits more and more, rate increases are quite justified to offset the higher operating costs. We continue to see the Canadian market adopt our Edge drilling rig automation more and more every quarter.
This provides a high margin bolt-on incremental revenue stream of anywhere from $1,000-$2,600 a day across the high-spec triples generally. We continue to address any upgrades that operators request by insisting the upgrade capital be paid for by the operator with a notional rate increase, or we adjust the day rate incrementally in order to achieve a one-year payout or less on the 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 our rigs are drilling more footage per day, we have the same number of rigs making more hole.
We are finding that the double-digit rig efficiency gains of years past have 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 focus on continual duplication of their best wells. We also have the situation where most operators are starting to look at tier two acreage now as we move along into the future. We also saw the U.S. hit record oil production close to 14 million barrels per day. With the technical limits of rigs establishing somewhat of a ceiling and with tier one acreage diminishing, 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 five years. Again, another indication we have troughed. In the U.S. today, we have 41 high spec rigs, mostly high spec triples. Out of our fleet is 70-plus high spec ADRs operating across the U.S., California to the Rockies, down into the Permian. The 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 basis points through the year as a result of our high-performance rigs and crews 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 well bores for lower cost, and we help de-risk that with our PBI contract form at higher margins to Ensign. Our directional drilling business, which is essentially a proprietary mud motor rental business, continues to improve some of the best motors with high-quality rebuild to 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 six different countries outside of North America, of which 13 are active today, up two 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 they were able to minimize the downtime with the operation by replacing the center section and recommissioning that rig in record time, which manifested itself into landing another one-year contract extension on that rig with a major. We have both our rigs in Argentina under long-term contracts now.
In Oman, the two rigs we have undergoing extensive upgrades are on budget and 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 three ADRs currently under contract in Oman and bring us up to five eventually in 2026. In Australia, we have four rigs active today with strong bid activity, which we feel will take us to five to six rigs by year-end. We were also successful in extending the contract out another year to the end of 2026 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 15-20 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 70% range consistently. Our U.S. well servicing business, which is focused primarily on the 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 2026 plans into 2025. Our Canadian well service business 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 a DGS Directional Guidance System.
This paves the way for seamless control of automated directional drilling with those operators who utilize remote operating centers and utilize in-house DGS systems. I'm happy to report that we're now fully commercial with our Edge Auto Two-Phase Control and are charging out our four 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 beta testing of our Auto Driller Max, which will further increase penetration rates and be charged out with a daily base rate of 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. With that summary, I'll turn it back to the operator for questions.
Thank you. We will now begin the question and answer session. To join the question queue, you may press star and one on your telephone keypad. You will hear a tone acknowledging your request. If you're using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star and two. We will pause for a moment as callers join the queue. Our first question comes from the line of Keith Mackey from RBC Capital Markets. Your line is open.
Hey, good morning. Maybe just want to start out in the morning. Just wanted to start out in the U.S. Contract book looks like everything is currently under six months in length. Can you just talk about what do you think that means for where we are in the cycle and potential contract churn going forward as we look to 2026?
We probably have, I would say, a quarter of our fleet 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 us out longer, and we just responded to a bid here earlier in the week with a major, and it's a five-year contract. When we start to see operators asking us for five-year contracts, it tells me they also believe we're at a trough.
That's a key indicator. Some of the other projects, of course, are smaller companies. They don't have longer-term projects. They tend to contract a rig for six months somewhere in there. I think the takeaway is we're starting to see some indication. Like last year, we weren't negotiating anything in five-year contracts. It was all one-year contracts. Yeah, got it. U.S. operators are starting to, at least on a one-off basis, ask you for longer-term contracts. Okay. Correct. As I mentioned in the call, we also have Canada. We signed up one for three years, and we're in the middle of negotiating another one for a longer term as well. We're starting to see some indications. Yeah. Okay. 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 is, or 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'd be helpful. Yeah. So the high-spec triples, let's say the 1,200-horsepower class, triples are the smaller end of the high-spec triples. As you mentioned, we saw a competitor move a couple up into Canada and wanting to foot the bill themselves for the upgrades.
The higher spec, the 1,500 high spec triples, is tight enough where if an operator asks 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. It is a tighter market in the 1,500-horsepower class. The 1,200s start to bridge the gap between the higher spec, deeper telly doubles, but the 1,200s will win that game. They are filling a little bit of the gap there. The high spec triples are definitely, as I mentioned, we were able to negotiate a three-year contract with a rate increase. It is still a very tight market on the 1,500s. They are running about 80% utilization on that specific rig category, which is almost full utilization because you have to move the rig and everything else. You never get to 100% utilization.
80, 85 is almost 100 in essence from a bidding perspective. Yeah. Canada's 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? Yeah. 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. They're able to look into the future at least three years and go, "Hey, these good rigs we want to keep." 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 from any new build metrics. Yeah.
Yeah. Okay. All right. That's it for me. Thanks very much.
Thanks, Keith.
Our next question comes from the line of Dean Monacelli from ATB Capital Markets . Your line is open.
Hey, good morning. 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 two rigs running into 2026 here?
Yeah. You're talking in Venezuela, or?
Yeah, in Venezuela.
Yeah. Yeah. Who the hell knows? Quite seriously, it is a dynamic file for sure. We've got a great team down there. Our team are Venezuelans. So we've got a client that runs with OFAC. So it's at the whim. You all read the same thing we do. There's a lot of tension there. I think that it could play out well. 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 them on the rig and we'll own them, but you're going to buy them." We haven't put any cash into the rigs, and we're able to get U.S. dollars out. That's our contracts. It's only two rigs in our world of 100 rigs running every day. It's certainly a little bit of excitement there for sure. I'm thinking that it plays out better in 2026 than the up and down we saw in 2025. Who knows?
Okay. Essentially, they're on well-to-well programs and kind of.
We signed contracts. Yeah. We signed six-month contracts, and they just roll over.
Okay. Got it. Is there any, I guess, visibility into additional rig deployments in the Middle East for 2026?
As you know, we're major upgrades on two ADRs in Oman. We have quite a good brand in Oman. The Ensign brand is really the gold standard for operations. We are always in conversation with, we have a mobile rig fleet of 186 rigs around the world that we can put into different areas. As you saw, we moved two 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. We have a lot of flexibility and mobility of rigs.
Okay. In the U.S., I just want to circle back on the contract terms that Keith was discussing. I'm curious, given that you say you have a customer coming looking for five-year contracts, the market's not, I don't think anybody's saying the market is tight in the U.S. 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 some other factor that maybe I'm not considering here?
I think that when an operator is going and looking for 15-20 rigs in different areas with certain specs, all of a sudden, that tightens the field that have the ability to bid and meet those specs. I find some of the majors every five years, they'll want to tighten up their rig spec because they now know what is good for what areas.
They go out to bid, and they go, "Here's what we want. Tighten up your rig spec." It is usually a high-spec rig spec, and let's go forward. Usually, it involves some capital. Different companies address that differently. That is why they usually go out for a five-year contract as well because they are 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 a rig that is going to go out well to well. Would you entertain a five-year contract at current rates, or would you need significant premiums to current market rates or spot rates as well? Yeah. Yeah. We would ask for the operator to provide the upgrade capital. It depends on the situation. We would propose rates that 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. We usually put escalators in those types of contracts as well. Obviously, we have cost-based coverage on any escalation. If someone said, "Can you hold your current rate out five years?" we'd probably be a no to that, and we'd be showing some rate increases forward. We'd be asking the operator for all the upgrade capital upfront.
Okay. That's helpful. I wanted to circle back again on your comments and your prepared remarks regarding drilling efficiency and geological decline. Anecdotally, we've been hearing about that for a long time, or at least perhaps anticipating it on the horizon. Are you seeing anything in the field? Are you seeing your rigs working in tier two acreage more often now, or any other sort of tangible evidence that you're seeing acreage declines?
It is one of those things. People define their acreage differently. I remember companies three or four years ago had five levels of tier. Some today are going, "We have tier one, tier two, tier three." There is no real strong definition. We do hear people talk more about, "Hey, in 2026, we'll be starting to drill more tier two acreage." No one comes up and says, "Okay, we want you to go to this tier two play and go drill it," or, "Go to this tier one play and drill it." It is more the notional conversations. Of course, tier two are not as productive as tier one. They are drilling in tier one first.
We're seeing and hearing them talk more about it. There must be some truth to it. I guess on the leading edge, are you seeing any of your operators starting to increase activity? I would say for 2025, it's been budget exhaustion. They've been holding on to their rigs. We've got two operators that increased our rig count because of our performance. 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. We are drilling more footage year over year. The rate of increase is now into the single digits. We're running about 5-6% more footage drilled per rig, where two, three years ago, we were 14-15% year over year. We're starting to hit that speed of sound.
The technical limit of the equipment is what we're starting to see. You're seeing operators starting to think more about it, doing a U-turn, coming back on their acreage, relooking at their acreage. 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 or pretty close to it, let's put it that way, is what the data would tell us. Got it. In the U.S., last question for me. Are you seeing any opportunities in gas stations? A little blip in gas this week, but no. 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.
Takeaway capacity is going up from three to four to five, moving up as we increase production of the Permian, and gas oil ratios go up. We're not seeing—we've got anecdotally one or two clients that are saying, "Hey, we want to maybe go drill a Haynesville well," but it hasn't moved the needle much, no.
Okay. I appreciate it. Thanks very much. Good quarter.
Thanks, Tim.
Our next question is from Aaron MacNeil from TD Cowen. Your line is open.
Hey, morning all. Thanks for taking my questions. Mike, this one's for you, I think. Obviously, can appreciate all the reasons for the push out 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?
Yeah. I think at that point in time, I mean, you look at what's the best use of the proceeds. I mean, from our point of view, I mean, debt reduction is still going to be key. You probably get to that one, one and a half debt dividend. That will be probably another year, year and a half away from that happening. Our view would still be paying off debt, lowering your interest costs, which gives you free cash flow into perpetuity.
Yeah, I think we definitely take a look at it, but debt reduction is still going to be our focus for the next while.
Yeah. Complete full discipline on that. Absolutely.
Fair enough. Maybe to build on one of Tim's questions, how do you think about scale in all these international jurisdictions that you operate in? 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?
Yeah. We typically do not run. We typically figure out, get through, because we understand there are cycles in every area. I suppose Libya is the only area in the world that we have ever left because the war just took over the equipment. You have seen how we have managed through Venezuela. You have seen how we have managed through Argentina. To answer your question on scale, we like to get to five rigs running in any given area to appropriately manage supply chain and overhead and operational supervision. That is kind of the target. In Australia, we are there. Venezuela, we are not for obvious reasons. Argentina, we only have two rigs there. We are in discussions with some people for perhaps a few more rigs, but we would like to get to five there. In the Middle East, we throw a blanket over the Middle East. Oman will be to five.
Kuwait, we have full utilization there with two big rigs. And those are 3,000-horsepower rigs, and those rigs do not grow on trees. They are $60 million-$70 million rigs. Rates are not conducive to add any into that area, nor are they looking. That is how we look at the world. We are also not interested in going into any new markets either. We would rather double down and get more of the markets we are in and increase efficiency that way.
Okay. Fair enough. I'll turn it back.
Thanks, Aaron.
Our next question is from Josef Schachter from Schachter Energy Research. Your line is open.
Thanks very much. Good morning, Bob and Michael. Mike, just want to cover one issue that's been covered and then a 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? I'm trying to get a feel for the progression of debt reduction.
Yeah. No guidance for 2026 as of yet. 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, yeah, that $500 million is probably a good number to get to, just given the volatility we see in the market. Pre the turnaround transaction, we were kind of around that $500 million-ish, give or take. I think around that would be a reasonable amount to kind of run forward. That would give you kind of the flexibility to deal with the ups and downs.
Okay. Thanks. Bob, I'm reading stuff from and listening to interviews, Comstock's talking about drilling 19,000 vertical insulating pipe because of 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 Comstock and others that are going after?
Yeah. No, we absolutely have. Over the last year and a half, we have a few rigs that can rack 30,000-35,000 ft of pipe. We've got no less than four or five rigs right now that have been modified to be able to handle that with 5 1/2 in pipe and handle that 30,000-plus racking capacity on pad work with 5 1/2 in pipe. That is not uncommon for us now. We have lots of those kind of conversations.
Any potential signing up, or is it just early conversation days?
Oh, no, no. These are rigs that have been modified and are under contract.
Okay.
Yeah. It's not a notion. It's happening. Yeah.
Yeah. Is this your highest day rate rigs?
Yeah, it would be. Yeah.
Yeah. Okay. Good. Thanks very much for answering that.
Yep. No problem. Thank you.
Our next question is Marvin Mameda from Ukinox. Your line is open.
Hi, Bob. Hi, Michael. Thank you and 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 do not think it has yet, right?
Parts of it has. You'll see it throughout the next sort of 6 to 12 months. Contractually, there are some things that need to be completed for some of the funding to go through. Yeah, you'll see it sort of over the next 6 to 12 months.
Basically, you're getting paid by the clients after you spend the money within six months?
No, there's some prepayments as well.
Could you clarify on those two rigs signed in Canada? You said it would be $100 million over the course of three years in revenues for each, or?
Correct. $100 million total for three years, yes.
Total for three years at 30% EBITDA margin?
Right. For both rigs combined.
Right. Yeah. Thank you. Thanks.
There are no questions at this time. Please continue.
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 till 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 an escalation. Looking forward, we continue to execute the plan of reducing debt whilst delivering the highest performing operations safely around the world. As I mentioned earlier, we increased our forward contract book by roughly a quarter of a billion dollars and now have 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 95-100 drill rigs and 50 well service rigs daily around the world in this commodity price environment. With that, we'll look forward to our next report in the new year. Thanks for calling in.
This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.