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Operator: Good day and thank you for standing by. Welcome to the Precision Drilling Corporation 2025 First Quarter Results Conference Call and Webcast. I would now like to hand the conference over to Lavonne Zdunich, Vice President of Investor Relations. Please go ahead.

Lavonne Zdunich: Thank you, operator and welcome, everyone, to our first quarter conference call. Today, I’m joined by Kevin Neveu, Precision’s President and CEO; and Carey Ford, our CFO. Yesterday, we reported our first quarter results. To begin the call, Carey 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, Carey.

Carey Ford: Thank you, Lavonne. Precision’s Q1 financial results met our expectations for adjusted EBITDA, earnings and cash flow. Adjusted EBITDA of $137 million was driven by strong drilling activity in Canada and steady cash flow generation from our drilling operations in the U.S. and Middle East as well as our Completion and Production Services business. Our Q1 adjusted EBITDA included a share-based compensation charge of $3 million and restructuring charges of $3 million. Without these charges, adjusted EBITDA would have been $143 million. Revenue for the quarter was $496 million, a decrease of 6% from Q1 2024. Net earnings were $35 million or $2.52 per share, representing Precision’s 11th consecutive quarter of positive earnings.

Funds and cash provided by operations were $110 million and $63 million, respectively. And in the U.S., Precision’s drilling activity averaged 30 rigs in Q1, a decrease of 4 rigs from the previous quarter. Daily operating margins in Q1, excluding the impacts of turnkey and IBC were US$8,360, a decrease of US$787 from Q4. For Q2, we expect normalized margins to be between US$7,000 and US$8,000. Daily operating costs in the U.S. were 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 U.S. 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 U.S. 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 will be closely monitoring costs associated with rig reactivations and mobilizations later this year, as these costs may introduce some variability in reported daily costs in future periods.

Our goal will be to continue to drive down normalized operating costs throughout 2025. Moving to Canada. Precision’s drilling activity averaged 74 rigs, an increase of 1 rig from Q1 2024. Our daily operating margins for the quarter were $14,779, a decrease of $858 from Q1 2024. For Q2, our daily operating margins are expected to be between $13,500 and $14,500. Internationally, Precision’s drilling activity in the quarter averaged 8 rigs. International average day rates were US$49,419, a decrease of 6% from the prior year due to fewer rig move. In our C&P segment, adjusted EBITDA this quarter was $18 million, 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 million, including $20 million for upgrade and expansion and $40 million for maintenance and infrastructure. Our full year 2025 capital plan has been reduced from $225 million to $200 million and is comprised of $158 million for sustaining and infrastructure and $42 million 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, semiannual interest payments and typical year-end payments.

In fact, the $46 million decrease in cash from year-end was applied almost entirely to debt reduction of $17 million and share repurchases of $31 million in the quarter. As of March 31, our long-term debt position net of cash was approximately $778 million and our total liquidity position was approximately $570 million, excluding letters of credit. Our net debt to trailing 12-month EBITDA ratio is approximately 1.5x 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 a $230 million balance on our 2026 note as current debt. We plan to reduce this balance by at least $80 million in the last 3 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 million between 2022 and 2027 and achieving a normalized leverage level below 1x. Since 2022, we have reduced debt by $452 million. Conveniently, the $248 million remaining on our target debt reduction nearly matches the remaining balance on our 2026 notes. Our debt reduction target for 2025 is $100 million 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 million, cash interest expense of approximately $65 million.

Cash taxes, we expect to remain low and our effective tax rate to be approximately 25% to 30%. We expect SG&A of approximately $95 million before share-based compensation expense. And we expect share-based compensation charges for the year to range between $15 million and $35 million 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. With that, I will turn the call over to Kevin.

Kevin Neveu: Thank you, Carey. 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 to 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 Carey 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 a spring breakup period with our most active fleet in over a decade. Today, we have 47 rigs operating and 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 first week of May and should 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 2 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 and with further rig additions if Phase 2 achieves FID. The balance of our Canadian activity will be almost all heavy oil related and that is Clearwater, Mannville, Marten Hills, SAGD and conventional heavy oil.

During the first quarter, we upgraded and reactivated an additional Super Single, increasing our fleet of 46 rigs available with all of these committed for work through the summer and the fall. We have 2 remaining Super Singles cold stacked that are ready to reactivate and we believe there are several good opportunities which 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 with 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.

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 prioritized spending on drilling programs and perhaps held back a little on abandonments and delayed some prospective 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 and we will have no problem responding with available rigs and crews. Now we mentioned in our press release that we’re exiting — that 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 and North Dakota. And for several years, this business performed well. With 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 and we decided to exit the market. We are moving 6 of the rigs back to Canada and we’ll sell the balance of the assets in the market. In our U.S. drilling 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 in the Carey’s 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 our 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.S. activity back to a level of appropriate scale. In 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 the 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-1500 rig to the Marcellus later this quarter. Now we continue to experience very active bidding activity in the Haynesville and expect rig activations later this quarter and into the summer. With 10 Precision Super Triple rigs stacked near Haughton, 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 basins, 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 that 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 5 rigs. Precision Rig 906 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 will either be extended further or recontracted after that. The remaining 4 rigs in Kuwait are contracted well into 2028. We have 1 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 3 rigs but we have received a suspension notice for 1 rig which will take effect in May and reduce our activity for 2 rigs likely for the balance of this year.

Now we have no indications from our customer that either of the 2 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 Carey mentioned, we reduced our capital spending from $225 million down to $200 million. Let me break this down to $8 million reduction in upgrade capital and a $17 million 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 prebuy drill pipe and other rig components for the coming year. We did that in 2023. We did that again in 2024. And in 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 million is in line with our initial activity estimates for the year. Regarding the $8 million reduction in 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 and restructure our U.S. operations team. These are very difficult steps for the Precision organization. And 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 for the 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 lever we control. This gives me confidence that we’ll continue to deliver on our 3 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.

Operator: [Operator Instructions] Our first question comes from Aaron MacNeil with TD Cowen.

Aaron MacNeil: Kevin, you spoke to the restructuring of the U.S. sales and operations team that operations are subscale. 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 I guess I’m just curious to hear what your prevailing view is on the performance model versus the day rate model. And if you think the reluctance to move to a performance model is a headwind.

Kevin Neveu: Aaron, great question and I didn’t give a lot of guidance to our contract structure in the U.S. right now. I would tell you that I still like the a la carte style of base rate for the rig plus add-on prices. It gives us lots of room to kind of enhance our margins. But I comment that we do have right now, I think about 1/3 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, could be related to drilling performance or even fuel consumption. So I feel good about how we’re being rewarded for any enhancements we 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 and deliver better performance.

Aaron MacNeil: Okay. And I know I was oversimplifying there. I’m not sure if the next one is for Kevin or Carey 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?

Carey Ford: Yes, Aaron, I mean, I think part of the success we’ve had is just a commitment 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. So I think for this year, we’re sticking with our guidance of $100 million of debt reduction and allocating maybe a little bit less than that to share repurchases and we want to get to the 1x level. I mean we’ve got a really good capital structure in place with a lot of liquidity and termed-out debt that’s at good coupons. But we’ve made a commitment to get to below 1x and we’re going to stick with it.

Kevin Neveu: Aaron, I’ll add to that. I don’t think one is 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 maximizing liquidity so that we can fund the business when it rebounds after these periods of uncertainty. So I feel good about our direction right now. You might notice that during the first quarter, we actually applied a little more cash to 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.

Operator: Our next question comes from Keith MacKey with RBC Capital Markets.

Keith MacKey: Just a point of clarification to start out. So the $25 million 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?

Kevin Neveu: Yes. Keith, I would just say that we are fully confident that we’re going to meet our capital allocation guidance, whether the capital expenditures were $225 million or $200 million. 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 costs or capital expenditures, that’s what we’re doing.

Keith MacKey: Yes, understood. And just on the changes you’ve made in the U.S., Carey, the day — normalized day margin for Q2 is a little bit lower than what we had in our model. I’m not saying our model is one that’s correct. But nevertheless, you’ve made some changes in the U.S. and yet we see margins below where we would have had them before these changes. So can 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 in Q2 and beyond?

Carey Ford: Yes. So the margins on balance will reduce our fixed cost, our overall fixed cost and then our fixed cost 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 to be a little bit of noise in those margins as we increase the number of rigs running with rig mobilizations and rig reactivations that kind of come up when you don’t have a steadier rig count. And so I think as we are 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 kind of an appropriate scale level, you should see those margins continue to go up.

Kevin Neveu: Keith, I’ll add to that. The — 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.

Keith MacKey: 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. It sounds like there could be a couple there. But there’s also a lot of uncertainty on the oil front. So just 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, spare hot rigs from oil basins that you could just move over? Or is it really just not realistic to work it that way?

Kevin Neveu: No, 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 we’ll be recovering in the contract but we still have to pay for that rig move upfront. In the Haynesville, if you noticed my comments, I think we have 9 idle rigs in the Haynesville are not active right now. It is less expensive to activate those rigs than mobilize rigs from — that are idle in — or that may even be hot in the Permian back to the Haynesville — we’ll always make the decision that has a minimum cash impact and utilize the closest, best available rig.

Operator: Our next question comes from Waqar Syed with ATB Capital Markets.

Waqar Syed: Kevin, Carey, is there a rule of thumb that we can use for rig mobilization or rig reactivation costs for rig pickup in the Haynesville and Appalachia?

Carey Ford: It depends on which rig are picking up and when it’s happening but it’s typically between $500,000 and $1 million to either reactivate or remobilize a rig, something in that range. Reactivation — to give you a little more clarity, those rigs in the Haynesville are down now for approaching 2 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 will be more than that but the rig doesn’t require that start-up cost.

Waqar Syed: It doesn’t — it feels that if a rig is down for 2 years, $0.5 million or $1 million reactivation cost may be at the lower end. Are you comfortable with those numbers?

Carey Ford: Yes, we are. It really is just rubber products. I mean, what the industry often does when it’s been down for a long time is not specifically with the industry, will sometimes take drill pipe off a rig and borrow some spare parts off the rig. So reactivation costs can be higher if you’re backfilling borrow drill pipe or backfilling spare parts on the rig. I don’t expect we’ll have much of that.

Waqar Syed: Okay. And what’s the impact on your CapEx and maybe also on OpEx of these tariffs, both in the U.S. and Canada?

Carey Ford: Waqar, could you repeat that question?

Waqar Syed: So the impact on your capital budget as well as on your operating costs of these tariffs and counter tariffs?

Carey Ford: Tariffs. Okay. Sorry, I was just missing that one word there. The big part for — 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 purchased. I mean, if you’ve been following our story for the past couple of years, we’ve gotten well ahead of drill pipe needs in 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 that we’re going to be able to manage. Absent — aside from drill pipe, we have some tariff exposure on consumable parts but we have alternate supply sources in alternate domestic supply sources.

So we don’t anticipate a big problem on either equipment deliveries or cost. And I think we’re a bit fortunate as drilling contractors and 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 it’s not nearly as big of an impact for our business as it would be for some other companies.

Kevin Neveu: Carey, maybe it’s worth mentioning some of the work you’ve done with the IADC on trying to communicate to policymakers around tariffs.

Carey Ford: Yes. I’ll just mention a few weeks ago, the IADC hosted a group of drilling contractor representatives to have meetings with U.S. Congress people 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 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.

Waqar Syed: And would you explain to us, what those impacts could be beyond the drill pipe costs that you mentioned?

Carey Ford: Yes. I mean I think it’s just probably the same squaring that everybody else is trying to do, where the administration is 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 just making sure that everybody understood the implications that tariffs may have on the industry at large.

Waqar Syed: And Kevin, one of your E&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?

Kevin Neveu: Thank you for the question. I was waiting for that one. So I would tell you that we always have that pressure on pricing in our face. It only eases back when the industry is in a real growth mode and 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. What I’d tell you is that I think we’re focused on managing our margins very effectively here, likely trying to raise our margins, working with our customers to find ways to be more efficient but being paid for that efficiency. So we’re certainly not projecting a 10% reduction in margins or pricing in this market.

Waqar Syed: And is the pressure more on the Super Singles versus Super Triples or would you — is it the same in those asset classes?

Kevin Neveu: Yes. So first of all, I’d guide you that I don’t expect margins in either product line to be reduced. In fact, we expect to see margins rise. We probably have less third-party competition or peer group competition on Super Singles than we do on Super Triples. But we have really strong market positions in both and great performance in both. So it’s not one of the high risks right now that we’re weighing as we think about our business for the balance of this year.

Carey Ford: 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.

Kevin Neveu: With more Super Singles in the mix.

Carey Ford: Correct.

Waqar Syed: And then just one final question, Carey. Shortfall revenues; should we be expecting some in Q2 or for the second half of 2025?

Carey Ford: We may have some. We typically don’t guide for that.

Operator: Our next question comes from John Gibson with BMO Capital Markets.

John Gibson: Depending on the time zone you’re in. But I just had one generally sort of a broader question. What are your conversations like with producers in this environment in both Canada and the U.S.? Is there a specific commodity price, be it oil or gas, where 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?

Carey Ford: Yes. 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 don’t get that great information. But it does feel like in the U.S. 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 the WCS discounts narrowed with the Trans Mountain pipeline, that number might be a little lower. It might be more like low 50s or 50-ish before our 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 hardline numbers that we can stand on.

Operator: Our next question comes from John Daniel with Daniel Energy Partners.

John Daniel: Kevin, I know this question is not — the well service business is not — wasn’t material to you guys in the U.S. But I’m just curious, if the decision to move out, was that a customer consolidation because of that, lack of scale, just 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.

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

Operator: Our next question comes from Aaron Rosenthal with JPMorgan.

Aaron Rosenthal: Just wanted to touch on a quick clarifying point. On the international front, the rig drop that was called out in the release and then you had mentioned that there was some moving pieces on the international front in the prepared remarks. Just wanted to confirm that there was only one international rig drop and the suspension that was referenced in the release was the rig in Kingdom. Is that correct?

Carey Ford: That’s correct.

Aaron Rosenthal: Okay. And then I think you also mentioned that no expectations for impact for the other 2 rigs in the region. Any kind of broader comments you could provide on activity levels or anything you’re hearing from broader macro landscape in that region that you’re able to provide?

Carey Ford: Yes. Well, certainly, in Saudi Arabia, it’s a 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. And how large that group is, we don’t know. But we understand there’ll be a number of suspensions occurring or that already have occurred that maybe haven’t made it to the market yet.

Aaron Rosenthal: And then on the Haynesville basin, sorry if I missed this, the work that you alluded to coming up in 2Q or in the summer, I guess, relative to the 9 to 10 rigs that you have, I guess, idle in the region. Are you able to quantify the level of rig demand in that time frame?

Carey Ford: Yes. 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. Bidding activity is up. Our 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 1, 2, 3, 4 rigs in the next couple of months, not 10 rigs in the next couple of months.

Operator: And I’m not showing any further questions at this time. I’d like to turn the call back over to Lavonne for any closing remarks.

Lavonne Zdunich: 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.

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