Waqar Syed: And then just to clarify, I was talking about having two stands of pipe vertically held up in the direct. So, that’s kind of what I meant with that.
Kevin Neveu: Right. When you start the well, you don’t have two stands pipe in the deck, you got all the pipe in the pipe rack. You are going to bring that pipe in one joint at a time. On the Super Single, you are always bringing it in 45 feet at a time. So, we are drilling that…
Waqar Syed: But no, but on a pad like moving between wells, that’s what I meant.
Kevin Neveu: But my other comment is that we have that single joint of pipe, up in the pipe arm right up against wall center just before they need the pipe. So, it’s still very efficient drilling ahead compared to a Tele-Double. And we can pull data from our analytics group and show how we can drill wells first well, last well on a pad, every bit as efficient or sometimes more efficiently than Tele-Doubles.
Waqar Syed: Sure. Now, that’s really interesting. And the other thing on the automation looks to be a very interesting opportunity set for you. Do you see the application all across North America, you see the market better in Canada versus U.S. And then also, do you see that applications in the Middle East market as well?
Carey Ford: Automation?
Kevin Neveu: Yes, sorry. Yes, for automation. Yes. I think we will see technology adoption in North America on this type of technology earlier. There is a huge focus on safety. There is a huge focus on consistent, predictable, repeatable, which really plays into any type of pad drilling. So, I think that’s where the automation technology will have its early traction. But we also do expect that Saudi Arabia and Kuwait don’t – never want to be left behind in technology. So, it’s going to – they are going to view themselves as not a fast follower, but a follower. But I certainly see super majors, large cap E&Ps that are highly focused on predictable, repeatable and safety being the early adopters of automation technology like this. We have a little ways to go before we are commercial on this yet, but certainly have line of sight to believing that could happen inside this calendar year.
Waqar Syed: Sounds good. Thank you very much.
Kevin Neveu: Thank you, Waqar.
Operator: Our next question comes from Kurt Hallead with Benchmark. Your line is open.
Kurt Hallead: Hi everybody. Good afternoon.
Kevin Neveu: Hi Kurt.
Kurt Hallead: Kevin, yes, I just wanted to touch base again on discussions we have had in the past and you have had about the dynamics at play where the Canadian E&P companies are looking to lock in rigs for longer duration contracts to basically take advantage of the LNG export capacity. It sounds like there is maybe a little bit of a lull in that dynamic in the near-term here because of natural gas prices. But I was really just looking to kind of calibrate that and an update for you on how much conviction you still have in that structural change in the Canadian market.
Kevin Neveu: Kurt, that’s actually a really good question. So, I will break it up in two halves. So, you talked about LNG. Let me start with heavy oil and Super Singles. We have more contracts on Super Singles today than we have ever had in our history on Super Singles when we didn’t have a newbuild cycle. And that’s for oil plays and tied to oil export through Trans Mountain. So, that activity continues. We have got a number of upgrades right now that will be tied to long contracts with the pad upgrades. That momentum is continuing. I believe we have the right portion of our triples fleet for gas contracted. So, we are not looking to add more contracts. We want to maintain some exposure to spot market as that market continues to improve.
We have some renewals coming up right now. We are working through those with our customers. But I think the proportion of rigs that are locked in with term contracts in Canada and the proportion that are exposed to spot are the right proportion right now. We are not disclosing what that number is. We don’t like to give out too much macro information on a rig fleet of 30 rigs. But I feel really good about our contract book, and I feel that we will maintain a solid contract book and backlog of contracts with our Super Triples. Likely, if we are right and the LNG shipments start late this year, early next year and demand increases, if we move more rigs from the U.S. up to Canada, they are probably going to be contracted rigs.
Kurt Hallead: Right. Okay. Great. And then circling back to one of your other answers earlier in the context of, I think pricing dynamics in Canada. I think you heard you reference that you are trying to keep your customers happy. Some might interpret that as being willing to discount price. Could you provide some clarity on that?
Kevin Neveu: Yes. I would tell you that our customers are always looking for discounts. We are always looking for to increase that debate. That debate goes on at every single deal, whether it’s a long-term contract or a short-term contract. If you look at our market shares, we are in a strong position in kind of every segment we participate. And we want to make sure we maintain good productive relationships with our customers. So, we have to be mindful of their cost drivers also. Carey gave guidance on margins. We don’t expect any margin erosion. And in fact, margins are still trending upwards. So, I will leave that lack of clarity in the answer.
Kurt Hallead: That’s good. Alright. Last one for me, just on the international front. You got a couple of rigs that are still in region you mentioned the possibility of maybe getting something for those rigs later this year, early next year. Can you give us an update on what the range of cost it might be to kind of get those rigs ready to go?
Kevin Neveu: Yes, in the range of $6 million to $12 million for each rig.
Kurt Hallead: Okay. Got it.
Kevin Neveu: So, it sort of depends on which opportunity we are successful on. If it’s $12 million, it will be a higher day rate, and it will pay back within the first year roughly. If it’s $6 million, it will be a lower day rate, but still pay back within the first year.
Kurt Hallead: Excellent. Thanks Kevin.
Kevin Neveu: Great. Thanks a lot.
Operator: Our next question comes from Tim Monachello with ATB Capital Markets. Your line is open.
Tim Monachello: Hi. Good afternoon. I just wanted to compare and contrast, I guess the Canadian and U.S. outlook, I guess 12 months out, you have got some little insight to LNG exports and additional rig demand. It sounds like the Super Triple market in Canada is pretty tight. But you probably I would think that you will see some upside in U.S. activity as well. Are those triples that you are talking about, would those be coming out of an idle state or rigs that haven’t worked in a long time in the U.S., or would that be reducing your optionality for additional rigs to go back to work?
Kevin Neveu: Tim, those would be – in the U.S., we have two categories of Super Triple. We have the ST 1200, which is more common in the DJ Basin and the Marcellus. And then we have the ST 1500, which is a 1,500 to 1,800 horsepower rig that’s common in the Permian and a little bit in the Marcellus and a little bit in the Haynesville. We would not be moving any ST 1500s, probably only ST 1200.
Tim Monachello: Okay. Got it.
Kevin Neveu: And I don’t think it really reduces our optionality in the U.S. We think that the first movers in the U.S. will be Permian for oil, if there is oil response. If there is a natural gas response, it will be Haynesville where we are very well positioned with our 500s.
Tim Monachello: Okay. Got it. And then interesting comment about how busy Q3 and the summer could be in Canada, is that strength across rig classes? Like are you seeing, I guess the heavy doubles picked up in the CWC acquisition, incremental demand for those as well, or is it mostly in the higher tier rig…?
Kevin Neveu: I expect our activity in triples in 2020 – summer of 2024, look like it did in summer 2023, so generally flat on our triples and essentially fully utilized. I think most of the incremental activity will be in our Super Singles year-over-year.
Tim Monachello: Okay. And are those doubles performing well?
Kevin Neveu: Yes. We are doing well with doubles. It’s a little more price competitive. But I think if you look at our activity in Q1, we had – I think we had 12 doubles working during Q1. It’s just more competitive and you are not getting the double-digit EBITDA margins on those rigs.
Tim Monachello: Great. Okay. Well, appreciate…
Operator: Our next question comes from John Gibson with BMO Capital Markets. Your line is open.
John Gibson: Good afternoon. I just had one, and it’s kind of more high level. I guess, just looking at the U.S. market and the recent M&A, you touched a little bit on it in the call here. What our M&A could drive additional high grading, how have conversations gone in terms of changing lateral length? Like I have kind of heard the way maybe we could be seeing another step change on this front? And just kind of want to what you are hearing in that regard.
Kevin Neveu: Well, I will say that – I will answer the question a bit differently. So, we don’t design the well. Our customers design the wells. We have got rigs that have drilled out to 20,000 feet. Those are not very common. We are hearing talk about more of that, but don’t seem very common. 15,000-foot laterals are fairly more common. Everybody wants to have the optionality to drill that length of well, but a few people continue doing it. So, it looks like the range is somewhere between 10,000 and 15,000. It depends on land holdings and how consolidated the land is. But a full Super-Spec rig today that’s got three mud pumps for generators, 30,000-foot rocking capacity, high torque top drive has capacity to drill out to 15,000 or more feet.
