All participants please standby. You conference is ready to begin. Good afternoon, ladies and gentlemen, and welcome to the Precision Drilling Corporation 2016 Second Quarter Conference Call and Webcast. I would now like to turn the meeting over to Mr. Saber Rad, Manager, Investor Relations & Business Development. Mr. Rad, please go ahead, sir.

Thank you, and good afternoon, everyone. Welcome to Precision Drilling Corporation's second quarter 2016 conference call and webcast. Participating today on the call with me are Kevin Neveu, Chief Executive Officer; and Carey Ford, Senior Vice President and Chief Financial Officer. Through a news release earlier today, Precision Drilling Corporation reported its second quarter 2016 results. Please note that these financial figures are in Canadian dollars, unless otherwise indicated. Some of our comments today will refer to non-IFRS financial measures such as EBITDA and operating earnings. Please see our news release for disclosure on these financial measures. Our comments today will also include forward-looking statements regarding Precision's future results and prospects. We caution you that these forward-looking statements are subject to a number of known and unknown risks and uncertainties that could cause actual results to differ materially from our expectations. Please see our news release and other regulatory filings for more information on forward-looking statements and these risk factors. Carey Ford will begin with a brief discussion of the second quarter operating results and a financial overview. Kevin Neveu will then provide a business operations update and outlook. Carey, over to you.

Thank you, Saber. In addition to reviewing the second quarter results, I will provide an update on our 2016 capital plan and our liquidity position. Second quarter adjusted EBITDA was CAD 22 million which is 75% lower than the second quarter of 2015. The decline in adjusted EBITDA from last year is the result of decrease in activity levels across all of our operating segments and lower spot market pricing. Including in our second quarter results, our CAD $1.6 million in restructuring cost and share based compensation accrual that increased SG&A expense by CAD 4.6 million over Q1 2016 levels. In Canada, drilling activity per precision decreased 48% from Q2 2015 while margins were CAD 95 per day lower than the prior year. The margins for the quarter were positively impacted relative to the prior year by approximately CAD 4,000 per day from shortfall payments received during the quarter and negatively affected by the fix cost absorption due to lower activity. In the U.S., drilling activity per precision decreased 58% from Q2 2015 while margins were $785 per day higher than Q2 2015. The increase was primarily result of the impact from revenue earned from idle but contracted rigs which increase the margins relative to the prior year by approximately $1,600 per day, offset by the negative effects of fixed cost absorption due to lower activity. Internationally, drilling activity per precision decreased 44% from Q2 2015. The decrease in activity was primarily the result of fewer days in Mexico and the Middle East. International average day rates for $44,391 a decrease of $309 from the prior year. We now expect both the Kuwait new build rigs to begin working in the fourth quarter, on budget and within early startup. Today, we have 29 rigs drilling and moving in Canada, 29…

Thank you, Carey, and good morning. The second quarter of 2016 will certainly go down one of the most challenging quarters land drilling industry has faced. Not only was it the six consecutive quarter of this prolonged downturn, but our customers reacted swiftly cutting activity, reflecting the low commodity prices realized during the first quarter. Industry activity levels dropped to multi-decade lows, with most of the quarter there was little bit of different site. Just looking at Canada for a brief moment. If you exclude the Deep Basin which still remains a bright spot, Q2 industry activity outside the Deep Basin was less than 20 rigs, amazingly low activity levels. For Precision, our activity during the second quarter was roughly half of the prior year, averaging low 20s in the U.S. and low teens in Canada. In the U.S., the Permian remains our strongest region as the deep based in Canada. It's in these areas where Precision's intense focus on efficiency and high performance and as delivering is our best market share results. Moving in the quarter, our customers are being defensive in a survival style mode. As the quarter progress and commodity prices both oil and gas recovered, we noticed the significant shift in customer sentiment. Late in the quarter, several of our customers began adding rigs back as the adjusted near-term spending back up the levels better reflecting the current commodity prices and this would become evident in the weekly rig activity reports that are published by industry. But more encouraging is that slot customers are looking further out and planning into 2017 and beyond. As a result, we mentioned one rig gear of new contracts booked for this year in four rig gears stretching into 2017. Now, I’ll give some more details on that later. Specifically, in…

Thank you. We will now take questions from the telephone line. [Operator Instructions] The first question is from James West with Evercore/ISI. Please go ahead.

Hey. Good afternoon, guys.

Hi, James.

Kevin, curious about your conversation. You're obviously getting better visibility here. It's improving. Could you break that out between your Canadian customer base and the U.S. customer base? And perhaps, is this the visibility better in the Permian less so in the deep bases in Canada, or is it – I guess some color on the market.

It's interesting. I'll tell you that I think that the customers are looking to longer term thinking like late this year or early next year. The conversation is just similar in the Canadian deep basin in the Permian, but also some of the other oil place in the U.S. right now. So we're seeing kind of the consistency right now of larger, better capitalized, or [indiscernible] customers are looking through near-term volatility. And very few plants being signed up yet, but lots of conversations ongoing. So I would describe it as I think they're expecting to see better commodity prices, but probably not prepared to pull the trigger until that materializes.

Okay. That's helpful. And then, your comment about pricing being stable, and I think you said that on new contract – or the new contract that pricing was actually higher. Is that – did I catch that right?

Yes, you did. I would tell you that I think that our – what people refer to as the spot market are uncontracted rigs. Pricing has been stable through the quarter despite the utilization dropping. But I think we are happy with the premiums we've achieved on the contracts we've signed, both during the quarter and stretching into 2017. We are probably here to clear premium on those restarts. Now, I've been describing this kind of over the past few months as we do believe that as customers begin to reactivate rigs, it'll be customers that likely use those rigs during the previous cycle and probably paid for those rigs and probably know the performance of those rigs. And they are looking for us to re-staff those rigs with the same crews, the same drillers, same rig managers and they'll be willing to pay I'd described it as a little premium for that capability and I think we're achieving that.

Okay. Got it. Great. Thanks, Kevin.

Great.

Thank you. The next question is from Sean Meakim with JPMorgan. Please go ahead.

Hey, guys.

Hey, Sean.

Hi, Sean.

So I was just curious if you can maybe give us a little more detail on the recent rig adds in the U.S., if you could maybe elaborate on types of drilling or customers that you're seeing, either the work you won or just some of the broader tendering that you're seeing? I think I guess what I'm trying to ask is could you characterize the mix of work and some of the incremental activity, similar to what you've seen as we get to some of the base levels in the trough, or have you seen any shift?

I don't want to give too much detail here because there's just so little work out there right now that it's likely that if our competitors are listening, they'll know who we're talking about what I comment on is every rig we've added is a horizontal drilling resource rig. We're not adding any vertical drilling rigs, so we're participating in the most important part of the plays. I think every one of these rigs is a pad walking precision super triple. So, I think we're kind of expecting – it's what we're expecting to see in the rebound. It's been focused on the Permian, on the Canadian Duvernay, but we are seeing traction in other place.

Okay. Fair enough. And then just to touch on the Deep Basin, you highlighted, it's still a bright spot. Obviously, it's been a great anchor position for you. The recent FID delay for one of the LNG explore projects, do you have a sense that that could have an impact to activity or how does that factor into your thoughts looking forward?

Sean, it's not what I would call a good news for sure. Fortunately, our customers right now at the deep basin are focusing on the Duvernay and the Montney. It's a wet portion of the play they're focusing on. I would argue that some of those customers were long-term LNG players for sure. But in the meantime, they're selling these products and especially selling the national gas liquids, the NGLs as diluents for heavy oil. And that portion of the revenue stream from that three phase fluid is driving the economics right now. So, I don't think the delays on the LNG projects are going to have a material impact on near-term activity. Certainly, I think Canada is missing an opportunity long term by not helping the operators get approval faster.

Got it. That's very helpful. Thanks, Kevin.

Thank you. The next question is from Scott Treadwell with TD Securities. Please go ahead.

Thanks. Good morning, guys. Just maybe building on that last question. The contracts that you've added here were those re-contracting an extension of the active rigs or I think you let it slip, were those restart of idle rigs?

Actually Scott, there was both. We didn't give that level of clarity but I can tell you we had both. We had a couple re-contracts. Do we had a couple of re-contracts but knowing customers nor our performance and we're likely involved the original contract of those rigs.

Okay. And I'm assuming then that there was mix than of direct negotiations and tenders and not?

Yeah, a mix but I think most were just direct point-to-point negotiations.

Okay. Perfect.

Most but not all.

Okay. Perfect. Second one for me, the OpEx in Canada obviously part of that, you referenced the lower revenue base and the fixed cost. Can you quantify or give us some set. Was there an impact from seasonal cost that is some of the active rigs went down? You only had – you had that one quarter window to do any sort of R&M that you needed to get done. Did that contribute to the higher OpEx at Q2 or was it almost entirely fixed cost absorption?

It's almost entirely the fixed cost absorption Scott and also if there are minor repairs to do, that's going to have much bigger impact on the daily operating cost as well just because the volume so well.

Okay. Turning to the IBC side, just wondering if you've got any visibility of that, if any of those IBC rigs could be moving to active anytime in the near future and if you do get any kind of notification, is it 30 or 60 days or can they kind of call you Friday to go to work Monday?

The can call us Friday to go work Monday. We said we put the rig back to work that quickly. We're in touch of those customers almost every day. I would say all right now are likely to go back to work at some point but timing is hard for us to anticipate.

Okay. Looking a little bit further out. You guys have referenced the number of times, your ability to ramp-up. At some point, there's got to be some CapEx that comes down the pipe. Would the likely contributors to that be recertifications, drill pipe, and things like that? Or is there something else that once you've added the first, say, 100 rigs, that that's going to drive some, call it, maintenance or reactivation capital?

Yeah. I think that if we get through a large number of rigs, we are at 5,000, 7,500 rigs per fleet. I do think things like drill pipes start to catch up a little bit. There would be probably an increased recertification activity. Some of those rigs will have been down at that point, probably, two or three years. There's probably a little bit of catch-up on the rubber products. And then, Scott, there will be more of a trend to 7,500 psi standpipes and larger mud pumps. For us, it's a bolt-on, but it does need capital, so I don't think we have any obsolescence issues, but there will be some rigs that require high-pressure standpipes. There'll be some rigs that we add walking systems or two. I expect that if you play this forward, I don't know if it's two or three years or four years, but with commodity prices, if they move back into a CAD 60, CAD 65 range, I expect that all of our 200 rigs are working, probably all working on pads and probably all drilling core resource plays where walking was a real value for our customer. So I do think that moving from where we are today to having virtually all of our 200 rigs with walking system as possible. I do think that for that to happen, there has to be pretty good commodity tailwind and good tension on pricing and a good opportunity for us to get returns.

Okay. Last one for me on the outlook. As you referenced in the past that the contracts kind of rolled off at a steady pace, are you seeing any difference in the discussions? Obviously this last addition has been welcome, but as you've got customers who've got rigs expiring Q3, Q4, Q1, a difference in the tempo or at least the – I guess the tone of those discussions with customers about re-contracting what kind of – where the day rate goes. Has it shifted to some sort of worry about security of supply at this point or is it maybe just a little more friendly than it was six months ago.

I don't know if friendly is the right term. I would tell you that if you'd ask me the same question six weeks ago, nobody would've been talking to us about a renewal of contract or anything. They just wanted to get ways to cut costs six weeks ago, maybe seven weeks ago. And the sediment ring in the past month and a half has been phenomenal. So I think I'll stop with what we have done so far, the contracts we've worked up for 2017. Clearly, the tone has changed. The sentiment has changed, but it's fragile. And if commodity price would take another link down back into the 30s or 20s, any bit of this momentum we see right now could disappear very quickly.

Okay. Perfect. That's all I've got, guys. I appreciate the color. Thanks.

Thank you.

Thanks, Scott.

Thank you. The next question is from Jim Wicklund with Credit Suisse. Please go ahead.

Good afternoon, guys.

Hey, Jim.

Hey, Jim.

Kevin, I noticed that on the Canadian seasonality that normally third quarter rig count is up about 80% from the second quarter rig count on a historical basis, so putting some rigs to work in Canada, I guess really consider couldn't – shouldn't come as a shock. But do you think you're going to get as big of an uplift in activity in Canada in Q3 as historically we have seen?

Well, the law of small numbers should get us there, Jim. We started the quarter off with 12 or 13 rigs in Q2, so getting a 78% lift, I think, is pretty easy. But I think it's very helpful. I think that's a wrong answer. We're at 29 rigs today, and we expect this to sort of follow the typical trend through the rest of this quarter. I would tell you what I think access capital in Canada is slightly limited compared to the U.S. today. But remember, our customers here are dealing in selling new products in U.S. dollars but their costs are in Canadian dollars. So even a slight movement to commodity price, we get closer to 50 rather than 45, I think that freeze up more opportunities for Canadian customers. So, while I think we're lagging in Canada to the rebound of the U.S. a little bit, it's pretty sensitive, a small increase in commodity price between now and even early September could see activity in Canada come up nicely for us. I mentioned a little more pressure in the Viking and Canadian Bakken. But another $5 a barrel would be really helpful for our customers and we see activity move up nicely.

Every little bit helps. Do you normally see – when do you normally see on a normal course of the year because this one obviously isn't normal, when do you start to see your customers look to contract rigs for the coming year. And I mentioned that because of the significant seasonality in Canada, and I didn't know if it's normal for a third quarter people start looking into next year because we don't do it in the U.S. until ease with the first quarter.

Yeah. So there's a real seasonal base cyclicality here. I would tell you that closer to the beginning of September, the conversations about 2017 get more and more focused.

Okay. My last...

So I would tell you that if you look back at the vacation whether it's a second week of August or third week of August, they are now focused on 2017. So as we get late August early September, they're building their building their budgets for 2017 and we start getting clear with our customers about needs in winter.

And my last question, Kevin, what are cash costs for rigs in the Permian of these types?

We're not giving clear guidance on that, but I think we've done a great job managing our cost down.

Okay. Thanks, guys.

Thank you.

Thank you. The next question is from Mark Bianchi with Cowen. Please go ahead.

Thank you. Kevin, we hear a lot about 1,500 horsepower AC rigs being kind of the ideal rig that's being demanded with all the other bells and whistles as well such as walking in mud palms and hook loads. But you guys have 1,500 and you also have some 1,200 and 1,800 horsepower rigs. Can you maybe talk to us about how that factors into what an E&P might demand? Maybe if you can say what of those rigs that you contracted were 1,500 versus 1,200 versus 1,800?

Yeah. I don't have the breakdown between 1,500 and 1,200. In fact, what you were referring to on our website you found as 1,800 is really a 1,500 horsepower class rig. So, we're really dealing with two Super Triple to the U.S. as Super Triple 1,500 and Super Triple 1,200. The 1,200 rigs are more commonly being used in the Niobrara and the Marcellus. And the 1,500 horsepower rigs are in the Marcellus, in the Niobrara and every other base in the U.S., Permian especially.

Okay.

So, that's the regional expect. I'd expect over time that we may see as [indiscernible] reach starts stretching a little further, some of those 1,200 they migrate back to Canada and we may backfill 1,500 horsepower rigs in the U.S. We'll see how that trends out.

Okay. Thanks for that. And then I guess on CapEx and either for your or Carey, for 2017, I know you're not sort of guiding but it sounded like maybe maintenance is the starting point there and I think we're about $40 million of maintenance this year. I mean, is that really the type of number you'd be thinking about or there – how should we think about how it – any upgrades or anything else would play into that?

Well, the base maintenance CapEx, we can tell you if you can tell us what the rig count is going to be next year because that's all activity based. But this year, I think kind of in the mid-30s level is probably where we're going to be for maintenance. So if activity is similar, mid-30s would be a good estimate. And as Kevin said, I think the first part of the reactivations of our fleet won't require any sort of upgrade capital. But as we get deeper into the Tier 1 rig fleet reactivations, there may be a little bit, maybe CAD 0.5 million, CAD 1 million, CAD 2 million a rig if we're adding walking systems or [indiscernible] pumps.

Okay. Great, guys. Thanks. I'll turn it back.

Thanks Mark.

Thank you. The next question is from Jon Morrison with CIBC World Markets. Please go ahead.

Good morning, all.

Good morning, Jon.

Can you give a sense of how many incremental rigs you could be running in Canada or to the U.S. based on your current cost structure of not adding on the SG&A or corporate side of things at this point?

Jon, we, I would tell you that the resizing restructure we did in the first quarter was designed to bring us down to sort of a midpoint of about 100 operating rigs. And today, we're operating about 60 rigs. So I can tell you, we can certainly add from today's rig count, 40 rigs with no impact on G&A and fixed costs. But we also think that we can probably go beyond that by another 50 rigs. We'd be running a little bit faster and hard, a little bit lean, so I would tell you, I think we can probably get to about 150 operating rigs without a meaningful change in G&A. After that, there's no question we have to add utilization or activity based cost throughout the system. But I think that we were very thoughtful in the restructure we did back in the first quarter, and really sized for that mid-winter activity level, recognizing which we have a bit of extra cost during the spring breakup. But believing that they would probably get back to that kind of activity level in this commodity environment, in this CAD 45 to CAD 50 commodity environment. But – and believing we have optionality to go beyond that. So, short answer is you can probably add up to about 90 rigs into this rig count, with minimal impact on G&A.

Okay. You talked about having a large pool of pre-screened candidates in the system and ready to go back to work. But ultimately, as time goes on, people end up doing different things. And I guess the question is how do you know that that's an accurate number and you can ultimately meet the demand on the field employment side?

I'll let Gene Stahl answer that question.

Yes. So we have a very formal process through HR and our Personnel Department, and we're reaching out to our inactive employees all the time on a regular basis, either through the rig managers or directly. So we have a real good sense of where guys are at, what they're doing, and their expectations on when to come back to work.

And we keep that list live, and if somebody falls off the list, we dig down a little deeper and just call the next group of people below that. So we'll tell you that we're probably always within 30 days of doing work. People are what they're doing.

Kevin, I realize you don't want to make too many comments on pricing, as you referenced. But do you expect to put out any rigs at little to no margin just to get equipment warm in the coming period? And I guess what I'm getting at there is I'm thinking about some of your heavy doubles or super singles as having different supply-demand dynamics than your triples over the next call it two to four quarters?

Yes. Jon, strategically, no; tactically, occasionally. If there's good customer or a place we want to be or something we're trying to accomplish, we will put a small number of rigs at a lower price. But, generally, our strategy is to contain our margins.

Okay. Is it fair to assume that there could be an inflection point in Mexico coming where if you don't see any uptick in activity levels or, ultimately, interest in the market from a foreign capital perspective that you'd have to look at redeploying those rigs to other markets as demand rises in other countries?

Probably not. I think the cost to move those rigs will make them probably competitive in other areas, plus we have excess rigs right now in Middle East. So we can deploy there. I mean, if we used up all four rigs and inventory in the Middle East, so we can get a more from Mexico to Middle East, absolutely. But I also don't think Mexico is dead forever. I think the Schlumberger, Halliburton and IPA model will work in Mexico. It does give PMX a high quality strong, intelligent drilling program through Schlumberger and through Halliburton. So we think we’d be part of. So I think the answer is I expect that business will rebound at some point, probably commodity price sensitive. I think the Schlumberger model and Halliburton models effective in Mexico. It's been down there for a decade and a half working quite well actually. And if we use the rigs in the Middle East, we would certainly look to redeploy rigs in the Middle East if demand was there.

Through every downturn and just going back to your comment on CapEx and cash out layer for the coming period. For every downturn pretty much every service company says that all their equipment being laid down as an excellent shape, ready to go back to work and there's going to be almost no capital needed to, once that we get that back in the field, then inevitably, a large capital upgrading or cost cycle follows. What gives you comfort or confidence that it's not going to be the case for Precision this time around outside of small upgrades like adding a walking system that you mentioned earlier?

Yes. Jon, 145 new build rigs delivered the past four or five years. The rig fleet is extremely current, extremely new. That's one big piece. We retired large block of our tier 2 rigs back in December. Every spare part of those rigs from 3x4 transfer pump to expendable parts, we’ve robbed of those rigs, we’ve pulled those in. I think we're in pretty good shape with the rig fleet. For sure, if the rig has been down two or three years, there's a little more cost to get us back up again. No question there. But I think what we'll see is that when we work through the first 50 or 60 rigs, then we’re probably into walking systems and high pressure mud systems and things like that. Carey anything to add?

Yes. A couple of other things I would add there is, just taking a look at our daily operating cost. We're reducing overhead where we can, but we're still spending the required repair maintenance to keep our rigs in good shape and the same thing with our maintenance capital expenditures, it's down over 2014 and 2015, but relative to the activity level, we're still investing the appropriate amount in our rigs. I think the one area that people get caught out is on drill pipe where they will – you can save money in the short term by cannibalizing your fleet on the rigs that are operating. And then when business rebounds, you're short on drill pipe you’re paying a premium. We're being very careful to keep our rig fleet - our drill pipe fleet current and not cannibalizing the fleet. So, I think that's one area where a lot of drillers get caught out. It's just so easy to do and you can save cash cost for short-term. And I can see a point in time where that might be necessary for anybody, if the downturn were to last half a decade. But we've been refreshing that fleet continuously over the course of this downturn.

Carey, I realized that the market is largely focused on growth at this point in bringing rigs back to work, but do you have any major concerns about extending additional credit many of your customers that are ultimately asking for incremental rigs. And even as we go through this upturn, balance sheets are fairly stretched. How comfortable are you with the receivable that you have on the balance sheet?

I would say we're very comfortable. We have a rigorous credit review process that is upfront on a quarterly basis. And so, we're always looking at customer credit quality and feel very good about our customer base and credit quality as it sits right now.

Last one just for me. On the service rig side, it looks like you guys give up some market share on the quarter. Are you unwilling to work at some of the negative rates that are mentioned in the market at this point and you're more than happy to give up market share and unwilling to go into negative territories to defend market share at this juncture?

The short answer might be yes to that. But also kind of expanding on that it might be a bit of a – they’re all in small numbers. A couple of rigs here or there all of a sudden meets five market share points. But John, that is a highly fragmented market. It includes mom-and-pops, it includes small private companies, medium sized private companies. And a bunch of companies like us that have all service rigs as kind of a secondary or tertiary product line. But it's just highly fractured it's structurally in trouble right now. And I think we've done all the right things, I think we've took a pretty big write- down in the fourth quarter on those assets. We think we are appropriately value the market now. But I look at Grand Prairie and I think I lost count, I think we counted 14 or 15 operation bases in Grand Prairie against about 25 operating rigs. So the industry has a structural issue that we need to work our way through. We're taking other steps, others have to take their steps. But it's hard, it's a hard market right now and I'm not running a business here to be cash flow negative.

I appreciate the color. I'll turn it back.

Thank you. The next question is from Ian Gillies with FirstEnergy. Please, go ahead.

Good morning, everyone.

Hi, Ian.

Just out of curiosity, is there any rig specifications you're seeing the customers want that has been surprising or perhaps different than what you've seen over the past few quarters as they look to go back to work in certain key place?

No. The answer is no absolutely not. We are getting a few customers they didn't have access to our super triples maybe a year ago. That are getting a little bit of capital and now they're getting access to super triples. And the performance has been really good. And Ian you can call a few of the Alberta customers you can see in our list, in our public list today that didn't use us a year ago and ask them how their performance is. You'll get – you'll hear that we're drilling [indiscernible]. And the same thing holds true in the Permian Basin.

Okay. And with respect to – you mentioned sales tax and the operating cost, and I don't know if I missed earlier, it took me a little while to get into the call, are you able to elaborate a bit more on what happened with the sales tax in the U.S. and how that affects your operating cost in perhaps go forward impact?

Yes. There was a bit of a one-time impact that was I think less than CAD 1,000 impact on daily operating cost, but it's a reverse in accruals on sales tax on a quarterly basis. We'll review this every quarter and make adjustments if necessary.

Okay. Thanks, Carey. That's really helpful. And last one for me, I mean, it sounds like Precision thinks they're okay with respect to staffing rigs as they go back and they're comfortable with where the equipment is right now. So from your perspective, what are the potential bottlenecks' activity or recoveries because it's never as seamless as we would all like to think it's going to be?

Ian, I would back on the last five cycles at the industry as a whole, and I was surprised -- reminded me the drillers aren't actually the backlog or aren't the critical path onto recovery. I mean, it's a heavy lift. I mean, the drillers where there's position of great systems are even the slow moving [indiscernible] trying to fire up couple of rigs. The drillers somehow find the staffing and I think it's because we've – in Canada, the CAODC has good rates. In the U.S., the drillers have been quite good of paying people appropriately. But I think the jobs on rigs should be attractive jobs. And I think the industry has done a pretty good job of staffing up. I don't think their critical path is staffing rigs. It’s a heavy lift, a lot of work, it is tough and training is required. So don't mishear me that it's easy, but I think your critical path is people that have either robbed rigs or taken things off rigs, engines, generators. And then the rebounding market, I can tell you, the supply chain went down their inventories where there's fuel pipe or chemical engines or mud pumps. And in a rebounding market, the larger companies, larger drilling contractors get priority and the balance of industries struggles to try to find those sources – that source. So drill pipe gets tight, the Caterpillar engines gets tight, mud pumps get tight in a rebounding world. I'm pretty comfortable where it’s Precision is today.

Okay. Thanks very much. I'll turn it back over.

Okay. Thank you.

Thank you. [Operator Instructions] The next question is from John Watson with Simmons. Please go ahead.

Hi, guys.

Hey, John.

Apologies, if I missed this, Kevin. Did you specify if the new term contracts with mid- to high-single EBITDA margins were destined for Canada or the U.S.?

I didn't say that. I don't know if it's in our disclosure, but it's a blend of both.

Okay. Okay. That's helpful.

And because these markets are so sensitive right now, so little activity in all regions, I really don't want to be more specific than that.

Right. That's fair. And then just one more for me. Looking at consolidated EBITDA within contract drilling, it appears as if international margin fell significantly. Is that the case, and if so, why?

Yes. We don't disclose that. I can't give you specific numbers, but I can say that a big part of the international margin performance on a month-to-month basis and sometimes on quarter-to-quarter basis is when the rig moves occur. And so that will have a bit of – in this quarter, I think we had an extra rig move or two that would – that we didn't have last quarter. So it did impact a bit.

Great, it’s a little bit of lumpiness, but the average is out over the course of two or three quarters.

Right.

Okay. That's helpful. Thank you.

Thank you, John.

Thank you.

Thank you, Jon.

Thanks.

Thank you. There are no further questions registered at this time. I would like to turn the meeting over to Mr. Neveu.

Well, thank you for joining our second quarter conference call, and I look forward to talking to you again in October on our third quarter results. Thank you.