Precision Drilling Corporation Price & Performance (PDS)

Thank you, operator, and welcome, everyone, to our first quarter conference call. Today, I'm joined by Kevin Nevew, Precision's President and CEO and Carey Ford, our CFO. Yesterday, we reported our first quarter results. To begin a call, Kerry will review these results and then Kevin will provide an operational update and outlook commentary. Once we have finished our prepared comments, we will open the call for questions. Please note some of the comments today will refer to non IFRS financial measures and include forward looking statements, which are subject to a number of risks and uncertainties. For more information on financial measures, forward looking statements and risk factors, please refer to our news release, and other regulatory filings on SEDAR and EDGAR. As a reminder, we express our financial results in Canadian dollars unless otherwise stated. With that, I'll turn it over to you, Kerry.

Thank you, Levon. Precision's Q1 financial results met our expectations for adjusted EBITDA, earnings and cash flow. Adjusted EBITDA of $137,000,000 was driven by strong drilling activity in Canada and steady cash flow generation from our drilling operations in The US and Middle East as well as our completion production services business. Our Q1 adjusted EBITDA included a share based compensation charge of $3,000,000 and restructuring charges of 3,000,000 Without these charges, adjusted EBITDA would have been 143,000,000. Revenue for the quarter was $496,000,000 a decrease of 6% from Q1 twenty twenty four, Net earnings were $35,000,000 or $2.52 per share, representing Precision's eleventh consecutive quarter of positive earnings. Funds and cash provided by operations were 110,000,000 and $63,000,000 respectively. And in The US, Precision's drilling activity averaged 30 rigs in Q1, a decrease of four rigs from the previous quarter. Daily operating margins in Q1, excluding the impacts of Turnkey and IBC were 8,360 USD a decrease of $7.87 USD from Q4. For Q2, we expect normalized margins to be between 7,000 USD and 8,000 USD. Daily operating costs in The US unusually high this quarter, due to rig activations, rig mobilizations, severance costs and standby labor. Without these items, daily operating costs would have been approximately $22,000 per day, which is still above where I would like to see.

As previously mentioned, we are carrying higher fixed costs in The US, to support future activity increases. We maintain active rigs in the Rockies, West Texas, South Texas, Louisiana, and the Northeast. We intend to maintain a strong presence in all these regions. But that presence comes with cost. Our US team is demonstrating its ability to increase activity levels, ultimately driving down the per rig fixed cost burden. As the activity increase will not happen immediately, and should evolve over several quarters, I will continue to push our team on every aspect of our cost structure to drive down operating costs as we work through the year. Also, with planned activity increases, I'll be closely monitoring costs associated with rig reactivations and mobilizations later this year. As these costs may introduce some variability in reported daily cost future periods. Our goal will be to continue to drive down normalized operating costs throughout 2025. Moving to Canada, Precision Drilling activity averaged 74 rigs, an increase of one rig from Q1 twenty twenty four. Our daily operating margins for the quarter were 14,000 hundred and $79 a decrease of $858 from Q1 twenty twenty four. For Q2, our daily operating margins are expected to be between 13,500 and fourteen thousand five hundred.

Internationally, Precision's drilling activity in the quarter averaged eight rigs, International average day rates were 49,419 USD. A decrease of 6% from the prior year due to two arignments. In our C and P segment, adjusted EBITDA this quarter was $18,000,000 down 8% compared to the prior year quarter. Adjusted EBITDA was negatively impacted by a 10% decrease in well service hours slightly offset by higher margins. Well abandonment work represented approximately 27% of well service operating hours in the quarter. Capital expenditures for the quarter were $60,000,000 including $20,000,000 upgrade and expansion and $40,000,000 for maintenance and infrastructure. Our full year 2025 capital plan has been reduced from $225,000,000 to $200,000,000 and it is comprised of $158,000,000 for sustaining infrastructure and $42,000,000 for upgrade and expansion. As of April 23, we had an average of 41 contracts in hand for the second quarter and an average of 38 contracts for the full year 2025. Moving to the balance sheet, our Q1 cash flow performance was better than expected, with neutral cash flow despite a quarter with working capital increases, semi annual interest payments and typical year end payments. In fact, the $46,000,000 decrease in cash from year end was applied almost entirely to debt reduction of $17,000,000 in share repurchase share repurchases of $31,000,000 in the quarter.

As of March 31, our long term debt position net of cash approximately $778,000,000 and our total liquidity position was approximately $570,000,000 excluding letters of credit. Our net debt to trailing twelve month EBITDA ratio is approximately 1.5 times and our average cost of debt is 6.9%. We expect our net debt to adjusted EBITDA before share based compensation expense to continue to decline throughout the year. This quarter on our balance sheet, we recognized the $230,000,000 balance on our 2026 note as current debt. We plan to reduce this balance by at least $80,000,000 in the last three quarters of the year with cash flow and cash on hand during the year, and use our undrawn revolving credit facility to address the remaining balance. Our plan to reduce our revolver balance continues significantly during 2026. Where we expect to reduce the majority of the balance. Our revolving credit facility, as a reminder, matures in the middle of 2027. We are committed to reducing debt by $700,000,000 between 2022 and 2027, and achieving a normalized leverage level below one times. Since 2022, we have reduced debt by $452,000,000 Conveniently, the $248,000,000 remaining on our target debt reduction nearly matches the remaining balance on our 2026 notes.

Our debt reduction target for 2025 is $100,000,000 and we plan to allocate 35% to 45% of free cash flow before debt principal payments. Towards share repurchases. Moving on to guidance for 2025, strong cash flow for the year, depreciation of approximately $300,000,000 cash interest expense of approximately $65,000,000 cash taxes we expect to remain low, and our effective tax rate to be approximately 25% to 30% We expect SG and A of approximately $95,000,000 before share based compensation expense. And we expect share based compensation charges for the year to range between $15,000,000 and $35,000,000 at a share price range of $60 to $100 and the charge may increase or decrease based on share price performance and the performance of our shares relative to Precision's peer group. That, I will turn the call over to Kevin. Thank you, Carrie. Good morning and thank you for joining our first quarter earnings call. So I'll begin by saying that I'm feeling very good about our first quarter financial results and the momentum we're carrying into the second quarter. While macro events and economic uncertainty are somewhat obscuring forward visibility, I'm comforted that capital discipline across the upstream oil and gas industry has dampened the traditional knee jerk reaction of commodity price volatility.

Our customers in both The United States and Canada are telling us that they are cautiously watching the macro events and the impact on oil prices. While they remain optimistic about LNG and gas opportunities. And while our customers are closely monitoring these trends, oil targeted drilling plans remain largely unaffected by the current commodity price range and our customer discussions regarding gas drilling opportunities continue to have a positive tone. Now as Kerry mentioned, we've taken steps to tightly control aspects of our business and strictly manage our spending, and the organization is well focused on free cash flow. While we remain poised and well positioned for any and all emerging opportunities. So beginning in Canada, after a strong winter, we're rolling into spring breakup period with our most active fleet in over a decade. Today we have 47 rigs operating that are essentially at the seasonal low. In this mix, we have 24 Super Triples, and 23 super singles running straight through breakup about 10% above last year's level. We expect to begin adding rigs in the May and should come climb back up into the mid-60s by early July in line or slightly ahead of last year's trend.

The rig mix will remain in the same proportions as this last winter, with approximately 40% of our rigs in the Montney Duvernay Deep Basin drilling gas and condensate targets And those should be relatively unaffected by any WTI volatility. I'll remind the listeners that for many of our customers the condensate volumes these wells produce more than covers the drilling and completion costs and the Canadian market remains short condensate. With LNG Canada's first shipments imminent, and the potential for Phase two approval later this year, we expect long term stability in the Montney. With additional rigs likely required when the first phase is at full capacity early next year [indiscernible] The balance of our Canadian activity will be almost all heavy oil related. And that is Clearwater, Manville, Martin Hills, SAGD, and conventional heavy oil. During the first quarter, we upgraded and reactivated an additional super single [indiscernible] our fleet of 46 rigs available with all of these committed for work through the summer and the fall. We have two remaining super singles cold stacked are ready to reactivate. We believe there are several good opportunities may lead to firing up these rigs before next winter. Despite the macro uncertainties, our Canadian customer base has learned to operate in a lean market with historically wider differentials, exercising capital discipline and operating efficiency as a prime strategy.

And they've been doing this for a decade. Our customers' balance sheets are in the best shape they've been in since early 2000s. The Trans Mountain pipe has narrowed the oil differentials. The drilling and completion costs are tightly managed and our customers are well positioned to continue their programs through periods of market uncertainty. LNG Canada will be the first LNG export facility for Canada and this new capacity will drive stable Montney gas activity for a very long time. My enthusiasm for our Canadian segment is well supported by these fundamentals. And I see a good runway for the next several years. So shifting gears for a moment, I'll discuss our Canadian well service segment. Which is also experiencing strong, although slightly lower than expected customer demand. It seems that during the first quarter, our customers prioritize spending on drilling programs and perhaps held back a little on abandonments delayed some perspective workovers. Despite the 10% reduction in activity this year versus last, rig mix was focused on higher margin projects and net cash flows were almost flat with last year. Our customers continue to give us indications that this activity with the activity this summer. Should be in line with last year.

We will have no problem responding with available rigs and crews. Now we mentioned in our press release that we're exiting we've exited North Dakota where we operated a fleet of 10 service rigs. We originally entered this market to provide services to Canadian customers operating in North America. [indiscernible] And for several years, this business performed well. When our Canadian customers exited the market, we were left competing with local mom and pop service providers for highly price sensitive customers. And although last year was a positive cash flow year for this segment, we did not achieve our targeted return on capital We decided to exit the market. We are moving six of the rigs back to Canada and we'll sell the balance of the assets.

In the market. In our U. S. Building business, as Carey mentioned in his comments, we remain challenged by low utilization and subscale activity levels. With an average of 30 rigs operating in the first quarter. As mentioned in our press release and the curious comments, we've restructured our U. S. Sales and operations group to better focus on our customers' needs, their key performance metrics and enhance our customer relationships. These changes included flattening the organization eliminating several management positions, aligning sales, operations, and technology with collaborative customer objectives, and streamlining decision making and internal communication chain. Early indications are that a restructured organization is working very well. As our current activity level is now 34 rigs up from 30 in the first quarter. And while contract churn will continue, we see a path to increase our U. Activity back to a level of appropriate scale. My opening comments, I mentioned that our customers remain cautious regarding oil directed drilling, yet drilling plans remain in place. How we've seen this play out in one case is where a customer is indicating that our rigs will continue to operate through the year but they will suspend completion activities for a period until they have more confidence in oil price.

I remain cautiously optimistic that our Permian, our DJ and South Texas activity will remain stable through the summer and into the fall.

Now we continue to see a lot of interest in gas directed drilling both in the Haynesville and the Marcellus. And we currently expect to mobilize an additional ST 1,500 rig to the Marcellus later this quarter.

Now we continue to experience very active bidding activity in the Haynesville and expect reactivations later this quarter into the summer. With 10 Precision Super Triple rigs stacked near Houghton, Louisiana, we believe we are very well positioned as our customers begin to pick up more rigs. Regarding leading edge pricing, with customer demand firm and rig supply tight in the gas stations, we are seeing stronger pricing in the Haynesville. And Appalachia. Than in the Permian where contract churn is prevalent. And most of the price competition seems to be focused. I'll also add the customer interest and plans in these gas plays seems to be relatively unaffected by the macro uncertainties pressing on commodity prices. Now turning to our international business, In Kuwait, we continue to operate five rigs. Precision Rig nine zero six, which was due to expire during the third quarter, has been extended and will continue to work through the end of this year We believe that it'll either be extended further or re contracted after that.

The remaining four rigs in Kuwait are contracted well into 2028. We have one idle rig in Kuwait that we continue to bid for projects in Kuwait and other areas in the region. However, contract awards have slowed and we do not expect this rig to be contracted this year. In Saudi Arabia, we are currently operating three rigs, but we have received a suspension notice for one rig, which will take effect in May and reduce our activity for two rigs likely for the balance of this year. Now we have no indications for our customer that either of the two remaining rigs will be affected and they should continue working for the balance of the year. So turning back to our planned reduction in capital spending, as Terry mentioned, we reduced our capital spending from $225,000,000 down to 200,000,000 Let me break this down to $8,000,000 reduction in upgrade capital and a $17,000,000 reduction in our maintenance or sustaining capital. So first on the sustaining capital reduction, I'll point out that we usually take advantage of year end vendor discounts and pre buy drill pipe and other rig components for the coming year. We did that in 2023.

We did that again in 2024. Our 2025 budget, we anticipated a similar year end investment. At this point, we removed that from our budget and comment that the remaining 158,000,000 is in line with our initial activity estimates for the year. Regarding the $8,000,000 reduction upgrade capital, this was a budgeted placeholder for unidentified projects primarily in The United States and international markets. Should either of these markets rebound in 2025, we'll consider additional upgrade spending but only if the financial returns and contract terms meet our financial thresholds. So now regarding the steps we are taking to reduce our fixed costs to restructure our US operations team. Are very difficult steps for the Precision organization, certainly we will miss the dedicated folks who are no longer on our team. And I thank them for their many contributions.

That said, we believe it's essential to be sized and organized with a market that we see. It's also a key component of our core strategy to have tight control over every element of our business and our hand on every level we control. This gives me confidence that we'll continue to deliver on our three strategic objectives, despite whatever macro events impact our industry. We'll continue to provide high value, high performance services to our customers and remain well positioned for any market opportunities we uncover. So I'll conclude by thanking the employees of Precision for their dedication, their loyalty and hard work and the strong safety, operational and financial results our team continues to deliver. With that, I'll now turn the call back to the operator for questions.

Thank you. Ladies and gentlemen, if you have a question or a comment at this time, please We'll pause for a moment while we compile our Q and A roster. Our first question comes from Eric McNeal with TD Cowen. Your line is open. Hey, everyone. Thanks for taking my questions. Kevin, you spoke to the restructuring at the U. S. Sales and operations team. That operations are subscale.

You know, some of your peers have moved to a performance model You've stuck with the day rate model.

I know you're comfortable with the operational performance of your rigs, just given all the investments you've made in automation. I can also appreciate that you've got visibility to adding rigs, so maybe this is off the mark. But guess I'm just curious to hear what your prevailing view is on [indiscernible] performance model versus the day rate model. And if you think the reluctance to move to a performance model is a headwind. [indiscernible] great question. And I didn't give a lot of guidance to our contracts structure in The U. S. Right now. I would tell you that I still like a la carte style of base rate for the rig plus add on prices. It gives us lots of room to enhance our margins. But I comment that we do have right now, think about a third of our U. S. Rigs are operating under some form of performance contract where we receive an incentive to offer our customers better performance. The performance could be related to move times, be related to drilling performance or even fuel consumption. So I feel good about how we're being rewarded for any enhancements can provide our customers for better performance right now.

I don't think it's going to permeate across our entire fleet, but we're certainly open to the idea of having rewards linked to things we can control deliver better performance.

Okay. And I know I was oversimplifying there. But thanks for that. I'm not sure if the next one's for Kevin or Carrie, but both of you have done an admirable job of fixing the balance sheet over many, many years. And have much better insights into the business from the inside than we do from the outside. So I guess with all that in mind, what's the rationale to continue to pay down debt here instead of maybe focusing more free cash flow on meaningfully buying back the stock?

Yeah, Aaron, I mean, I think part of the success we've had is just a commitment to to delever We set out targets every year and we stick to them. And so we have investors all the time asking us to adjust one way or the other. And we think that planning this capital structure for the long term with annual commitments is going to generate the most success for our shareholders. I think for this year, we're sticking with our guidance of a hundred million dollars of debt reduction, and allocating maybe a little bit less than that to share repurchases. And we want to get to the one times level. We've got a really good capital structure in place with a lot of liquidity and turned out debt that's at good coupons, but we've made a commitment to get to below one times, and we're gonna stick with Fair enough.

I'll add to that. And, you know, I don't think I don't think one's a magic number. But I do think that between a combination of being low leverage and having kind of long term maturities, it gives us more confidence to weather through periods of uncertainty. And also focus on maximize liquidity so that we can fund the business when it rebounds after these periods of uncertainty. I feel good about our direction right now. You might notice that during the first quarter, we actually applied a little more cash share repurchases than debt reduction. I think we'll try to be intelligent with how we apply capital. But we'll stay in line with the guidelines we put forward.

Understood.

Thanks, guys. I'll turn it back.

Thank you.

Our next question comes from Keith Mckay with RBC Capital Markets. Your line is open.

Hey, good morning.

Just a point of clarification to start out. So $25,000,000 capital reduction I understand what that's all for but technically, does that mean you end up with more excess free cash flow? Or are you anticipating that you're going to see a decrease in cash from operations and this is a way to even it out? Or are you ultimately expecting to have more free cash flow from spending less capital? Keith, I would just say that we are fully confident that we're going to meet our our capital allocation guidance, whether the capital expenditures were $225,000,000 or 200,000,000 So that meeting that guidance was not a driver for reducing capital, I think it's just running all of our cash outflows as tightly as we can, whether that's operating cost or capital expenditures that's what that's what we're doing. Yeah, understood. And just on the changes you've made in The US, Kerry, The normalized day margin for Q2 is a little bit lower than what we had in our model, not not saying our model is the one that's correct, but nevertheless, you've made some changes in The US, and yet we see margins below where we would have had them before these changes.

So, you just walk us through a little bit more about the impact of the changes you've made and how you see that flowing through margins Q2 and beyond? Yeah, so the margins on balance will reduce our fixed cost our overall fixed cost, and then our fixed cost will per day will be a function of the total fixed cost and activity. So as we add more rigs, that fixed cost per day will go down and margins should go up, based on the lower fixed cost per day. But there are going to be, as I mentioned in my comments, there's going be a little bit of noise in those margins as we increase the number of rigs running with rig mobilizations and rig reactivations [indiscernible] you know, kinda come up when you don't have a steadier rig count? And so I think as we adding rigs throughout the year, we're going to see kind of some bumps on the operating cost. But when we get to, as Kevin said, in a kind of an appropriate scale level, you should see those margins continue to go up.

Okay, got it. Keith, I'll add to that. My comments included the mention of a likely rig mobilization from Texas to the Marcellus That's obviously covered by the contract value, but it's lumpy, we pay for that move upfront and then recover it through the contract.

Got it.

Maybe just to follow-up on that a little bit.

So you're doing some rig reactivations based on natural gas basin demand Sounds like there could be a couple there. But there's also a lot of uncertainty on the oil front. [indiscernible] [indiscernible] what really gives you the confidence to be able to activate new rigs for gas basins instead of just kind of looking to see if you have some spare rigs, you know, spare hot rigs from oil basins that you could just move over, or or is it really just not realistic to work it that way?

Well, no, actually, it's exactly what we're doing. But if the rig is moving to the Marcellus likely we have a rig move tied to that that will be recovering in the contract, we still have to pay for that rig move upfront. In the Haynesville, if you notice my comments, I think we have nine idle rigs Haynesville that are not active right now. It is less expensive to activate those rigs. Than mobilize rigs from the their idle or they may even be hot in the Permian back to the [indiscernible] Okay.

Got it.

Thanks for that. I'll turn it back. We'll always make the decision that has the minimum cash impact and utilize the closest best available rig. Thank you.

Our next question comes Our next question comes from Makar Saad with ATB Capital Markets. Your line is open.

Kevin, Carrie, is is there a rule of thumb that we can use for rig mobilization or rig reactivation costs for for rig, you know, rig pickup in the Haynesville and in Appalachia?

It depends on which rig we're picking up and when it's happening. But it's typically between $500,000 and $1,000,000 either reactivate or remobilize a rig, something in that range.

And are you seeing that So pure reactivation give you a little more clarity, those rigs in the Haynesville have been down now for approaching two years. So if we reactivate a rig, we have to change the fluids, change some of the rubber products.

That's probably something in the $500,000 range. If we're moving an active rig, the mobilization cost be more than that, but the rig doesn't require that startup cost.

It doesn't it feels that, you know, if the rig is down for two years, a half a million or a million dollar re reactivation cost may be at the lower end? Are comfortable with those numbers? Yeah. We are.

It really is just rubber products. I mean, what the industry often does it's been down for a long time is not us specifically. The industry will sometimes take drill pipe off a rig and borrow some spare parts off the rig. Reactivation costs can be higher if you're backfilling borrowed drill pipe or backfilling spare parts on the rig.

I don't expect we'll have much of that.

Okay.

And what's the impact on your CapEx and maybe also on OpEx of these tariffs both in The US and and Canada.

Well, Carr, could you repeat that question?

So the impact on the cap your capital budget as well as on your operating cost of these tariffs and counter tariffs?

Oh, tariffs. Okay. Sorry. I'm just missing that one word there. The big impact for drilling contractors is on drill pipe. That's the kind of the highest dollar consumable item. So there's going to be a little bit of impact on new drill pipe that we've purchased, I mean, if you've been following our story for the past couple of years, we've gotten well ahead of [indiscernible] bulk purchases. But I think there will be a little bit of increased cost on drill pipe, Drill pipe prices regardless of tariffs, move around quite a bit. And I think even with tariffs, drill pipe wouldn't be as expensive as it was a couple of years ago. So I think it's a cost we're gonna be able to manage. [indiscernible] aside from drill pipe, we have some tariff exposure on consumable parts, but we have alternate supply sources [indiscernible] alternate domestic supply sources. We don't We don't anticipate a big problem on either equipment deliveries or cost, and I think we're a bit fortunate as drilling contractors in that we're running machines that are already in place and the cost is really just repair and maintaining them and then paying the people to run them.

So not nearly as big of an impact for our business as it would be for some other companies. Gary, maybe it's worth mentioning some of the work you've done with the IEDC on trying to communicate to policymakers around tariffs. Yeah, I'll just mention a few weeks ago, the IADC hosted a group of drilling contractor representatives to have meetings with US congresspeople about the impact of these tariffs are on drilling contractors and our customers. And really just the benefit of the oil and gas industry for The United States. And I think it was it was positive to see the support from Congress people for the industry and their openness to hearing maybe the impact some of these tariffs would have on the industry in general.

And would you explain to us what those impacts could be beyond the drill pipe cost that you mentioned?

Yeah. I mean, I think it's just probably the same same squaring that everybody else is trying to do where the administration's trying to get oil prices lower But if you have tariffs on products that are used by the oil and gas industry, it could make operating costs a bit higher for our customers. So [indiscernible] making sure that everybody understood implications that tariffs may have on the industry at large.

And Kevin, one of your, you know, cost E and P customers in Canada talked about cost deflation in Canada. Up to about 10% Are you seeing any pressure on price for services in Canada?

Thank you for the question. I was wait waiting for that one. So I would tell you that we always have that pressure on pricing in our faces. It only eases back when industries are a real growth mode. We haven't seen that real growth mode for a long time. So there's always cost pressures or price pressures back from our customers. Even in Canada where we're almost fully utilized, and there might not be many other rigs in the market. Our customers continually try to push back on price. And certainly, those negotiations are ongoing. No question when you're in a period of kind of broader uncertainty they ramp up that work to try to cut their costs. Tell you is that I think we're focused on managing our margins very effectively or likely trying to raise our margins. Working with our customers to find ways to be more efficient, being paid for that efficiency.

So we're certainly not projecting a 10% reduction in margins or pricing in this market.

And is the pressure more on this super singles versus super triples? Or would you or is it the same in both asset classes?

Yeah. So first of all, I'd guide you that don't expect margins in other product line to be reduced. In fact, expect to see margins rise. We probably have less third party competition or peer group competition on singles that we do on super triples. That we have really strong market positions in both in great performance in both So it's not not one of the high risks right now that we're weighing as we think about our business for the balance of this year.

Great. Good to hear.

And then Waqar, just to add that, if you heard my guidance for Q2 margins, they're effectively the same as last year, potentially higher than last year. With more super singles in the mix. Correct. Correct.

Yeah. Yeah.

And then just one final question, Carrie. Shortfall revenues, should we be expecting some in Q2 or for the second half of twenty twenty five?

We may have some. We typically don't guide for that.

Yeah.

That's all for me. Thank you so much.

Thanks, Prakhar. Our next question comes from John Gibson with BMO Capital Markets. Your line is open.

Morning or afternoon, depending on the time zone you're in here. But I just had one generally sort of a broader question. What are your conversations like with producers in this environment? Going in both Canada and The US? Is there a specific commodity price, be it or oil or gas, we could see a significant change in capital spending plans for the year? I'm just wondering what your expectations are, obviously, in a lower commodity environment here.

Yeah, so often the information you get from our customers is designed to create pricing tension with us.

So we don't get the cleanest information about what their thresholds are generally. We get that great information, but it does feel like it does feel like in The US and the oily basins low 60s, high 50s is probably stable. Get below kind of high 50s and the uncertainty level increases. In Canada, because we have an exchange rate advantage, and WCS discounts narrowed with the Trans Mountain pipeline. That number might be a little lower. It might be more like low 50s or 50ish before customers get too nervous about activity. Now that's a sense from us. No customers give us a hard line or a hard threshold They're continually trying to press us for lower rates and so I'd say it's not necessarily hard line numbers that we can stand on.

Okay, that's fair. But appreciate the response. I'll turn it back. Thanks.

Thank you.

Next question comes from John Daniel with Daniel Energy Partners. Your line is open.

Hey, Thanks for having me.

Kevin, I know this question is is not the well sourced business. It's not wasn't material to you guys in The US. But I'm just curious if the decision to move out, was that a customer consolidation because of that lack of scale bad behavior from your local well service peers? Just what kind of drove that? And then what is there a read through to maybe some of the similar sub 10 rig businesses in Canada that might see the same thing if you will. Just your thoughts.

John, first thing I'll say is you've been around the well service business darn near as long as I have been. I understand the dynamics really well. Your question demonstrates that The number one reason is that our Canadian customers that we're pressing into North Dakota sold their assets. [indiscernible] then we were faced with I'd say that more price sensitive customers who are happy with the service quality and safety offered by local mom and pops And we have a hard time competing that kind of an environment. So it was price sensitivity. [indiscernible] [indiscernible] safety quality and crew capability was at a higher value, we might still be there.

Fair enough.

That's all I had. Thanks for including me guys. Thanks, John. [indiscernible] One moment for our next question. Our next question comes from Aaron Rosenthal with JPMorgan. Your line is open.

Hey, thanks for taking my question. Just wanted to touch on a quick clarifying point. On the international front, rig drop that was called out in the release, and then that you had mentioned that there moving pieces on the international front. The prepared remarks. Just wanted to confirm that there was only one international rig drop, and this suspension that was referenced in the release was, the rig in kingdom. Is that correct?

That's correct.

Okay. Thank you. And then, yeah, I think you also mentioned that, you know, no expectations for impact for the other two rigs in the region. Any kind of broader comments you could provide on activity levels or anything you're hearing or, you know, broader macro landscape in that region that you're able to provide?

Yeah. Well, certainly in Saudi Arabia, it's single customer market. And they don't broadly communicate their drilling strategy across their fleet of rigs. But we do hear that our rig that's been suspended will be among a large group of rigs that are being suspended. How large that group is, we don't know.

So we understand there'll be a number of suspensions occurring. That already have occurred maybe haven't made it to the market yet.

Thank you very much. And then on the Haynesville piece, and sorry if I missed this, the work that you alluded to coming up in 2Q or in the summer, I guess relative to the nine to 10 rigs that you have rated, I guess, idle in the region, are you able to quantify the level of rig demand you know, in that time frame?

Yeah. I I'll I'll stop short of doing that because I'd say the bid intensity right now is quite high. So lots of bids. But it's still hard for us to determine how many of those bids will turn into rigs rotating to the right. Think activity is up.

Customers are converting more of those contracts now, which is clear. I think both us and some of our in basin peers are seeing increasing activity But it's still hard to handicap how many of those bids will actually turn into rigs and how soon that will happen.

So I think for us, we're talking about one, two, three, four rigs in the next couple of months. Not 10 rigs in next couple of months.

Perfect. Thank you very much.

Great. Thank you.

And I'm not showing any further questions at this time. I'd like to turn the call back over to Lavon for any closing remarks.

Thank you, everyone, for taking the time to listen to our first quarter earnings call and wishing you a good day. If you have any follow-up questions, please feel free to send an email to myself or give me a call. Thank you.

Ladies and gentlemen, this does conclude today's presentation. You may now disconnect, and have a wonderful day.