Good afternoon, ladies and gentlemen, and welcome to the Precision Drilling Corporation 2017 First Quarter Results Conference Call and Webcast. I would now like to turn the meeting over to Mr. Saber Rad, Manager, Investor Relations and Business Development. Mr. Rad, please go ahead, sir.

Thank you, Shannon, and good afternoon, everyone. Welcome to Precision Drilling Corporation's first quarter 2017 earnings 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 first quarter 2017 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 additional 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 first 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 first quarter results, I will provide an update on our 2017 capital plan and our liquidity position. First quarter, adjusted EBITDA was $84 million, which is 15% lower than the first quarter of 2016. The decline in adjusted EBITDA from last year is primarily the result of lower day rates in our North American drilling business offset by higher North American activity levels and higher day rates internationally. In Canada, drilling activity for Precision increased 71% from Q1 2016, while margins were $3,023 per day lower than the prior year. Margins for the quarter were negatively impacted by decrease in average day rates driven by rig mix with a higher percentage of shallower rigs working and legacy contracts growing off and renewing at lower rates. The negative revenue impacts were slightly offset by daily operating costs that were approximately $1,000 per day lower than the prior year. In the U.S., drilling activity for Precision increased 45% from Q1 2016, while margins were U.S$9,884 per day lower. The decrease was primarily the result of lower idle but contracted payments and higher rig mobilization cost. Idle but contracted revenue was approximately U.S$800 per day in the quarter compared to approximately U.S$8,400 per day in Q1 2016. The impact from rig mobilization cost was approximately U.S$1,400 per day in the quarter compared to approximately U.S$100 per day in Q1 2016. Absent rig mobilization cost, daily operating costs were approximately U.S$13,000 per day. We have two rigs receiving idle but contracted payments today both of which were roll-off in the current quarter. Internationally, drilling activity for Precision decreased 6% from Q1 2016. The decrease in activity was primarily the result of no activity in Mexico partially offset by the addition of two new rigs in Kuwait…

Thank you, Carey, and good afternoon. As we have mentioned in our press release, the rebound in North American customer demand carried through the first quarter, it is continuing well into the second quarter. Today, we have 59 rigs running in the U.S. and 30 rigs in Canada as we experience a seasonal spring break-up period. Combined with American activity it's almost 3x higher than last year's record lows, there is no question that customer sentiment is substantially more constructive than at any point in the last 30 months. Yet, I believe the sentiment remains fragile and it's sensitive to the seemingly daily volatility and commodity prices. From an activity and demand perspective, we believe our customers are carefully managing their spending by hedging productions to lock-in cash flows where commodity price permits. And this gives us some confidence that the current customer demand and activity we see today will be sustained through 2017 then into 2018. Now looking at the demand in our particular markets, I will start with a broad trend in unconventional liquids and oil basins throughout North America where demand for our pad walking super triples remains strong and with any customers opting for high pressure, high volume mud systems which enable long-reach drilling capabilities. And as we commented in the past, these upgrades to our rigs are typically bolt-on or coupon sale upgrades. And Carey did recap some of our upgrade capital spending earlier. As we continued to see tight market for these rigs and we report leading-edge day rates to low 20s as we -- the market remain strong. And as mentioned in our press release, our customers are generally willing to cover the repositioning cost, these upgrade economics and all of the above provided, we build these costs and toward day rates. During…

Thank you. [Operator Instructions] Our first question comes from Sean Meakim with JPMorgan. You may begin.

Hi, thanks.

Hi, Sean.

Hi, Kevin. I was hoping just to touch based maybe start with Canada, you come out of spring breakup having the second half, how would you characterize your expectations around conversations with customers around pricing and contracting as you have given what you experienced during winter drilling season?

I've held a number of conversations with customers myself over the past few weeks and our sales team has been highly engaged with customers about rebound pricing. I think our customers have the appreciation of the service sector. Frankly, last year we went through a very unhealthy period. And they understand the need for price increases kind of a cost is based not just drilling but all sectors of well services. I described the discussions as constructive. We recognized the cost purchase is our customers phase. I think they recognized we need to be slightly higher on day rates to have a healthy business. So I think it's going well. I'd also comment that right now as I speak and our sales guys are up meeting with customers and so our competition. So it's hard to be a very specific, but I will tell you that I think that the healthier regions like the Deep Basin and heavy oil particularly, are the areas where our customers may have a little more room to work with us and in the shallower areas there are always budget challenged and still maybe tighter, but I'm expecting that across the space, that we'll have some room to work with customers to increase pricing and lead to a healthier segment.

Got it. That seems fair. And then, just thinking about that customer discussion, there has been some back and forth as we think about how much of their budgets were expanded during that stronger and expected winter drilling season, do we expect from your perspective budget to move higher in the second half. I was thinking about the interplay between kind of what's baked in with already and what's been spent versus what's left for the second half?

I think we try to give some sense of what we expect the rig counts in the second half. We see ourselves rising back to 60 plus rigs as the ground dries out. There is always a fair amount of volatility in some of our activity based on localized rain showers and things like that. But 60 to Q3 and probably higher in Q4, but Q4 activity will depend, I think on decisions our customers will make later in Q2. So there is some timing issues, we're expecting an OPEC meeting in May and I think a lot of people believe that OPEC will extend the price cuts, we'll have to wait and see for sure what happens, but fixed in price cuts if prices show a little more firmness if we get day rates trending closer to 55, not 50, you could see increased spending in the fourth quarter for Canada, but I think the activity levels that we discussed are covered by customer hedges. So I feel comfortable what we discussed, I think there is room for upside providing some of these chips fall in the right place for us. I hope that's helpful.

Yes. That's very helpful. And just one last thing I wanted to highlight and obviously a lot of details come out at the Analyst Day, but if I could, you noted that the beta-style field trials underway for the automation of directional drilling, that closed loop automation. Is there any kind of phase you can give us of what you guys have been seeing out in the field with this new technology?

I think, Sean, it's suffice to say that we're comfortable rolling this out to the investors now because we've seen the results in the field. I've used the term highly encouraging, some of the technologies like I'd mentioned the directional drilling advisory software, we've got several years of very good experience behind us. So the beta term there might be a little bit late, but on the automation technology and some of the data transmission technology, we're still at beta phase, but we're really encouraged of what we see and we believe there is meaningful value for our customers, meaningful competitive advantage to be gained here and we're anxious to tell you more about it.

Got it. Great. Thank you, Kevin.

Thank you.

Thank you. Our next question comes from Brad Handler with Jefferies. You may begin.

Thanks. Good afternoon guys.

Hi, Brad.

Hi, Brad.

I guess I will start with Canada as well and there is a bit of meandering in my questions, so I'm almost apologizing a little bit beforehand, but if maybe you can help us and just need to think about a few things. So in the second quarter how predominant would you expect the Super Triples to be of your total rig count, it's pretty hard percentage of it, right?

Well, the guidance I gave you so far is about half of the activity in the second half of the year.

Well, I think if we're thinking about right now we're running 19 Super Triples as Kevin said and we gave some guidance from the last quarter we thought that we would average right around below 30s kind of trough just below 30. So if we -- if we're going to keep similar activity probably be half to two-thirds of our activity will be Super Triples in the second quarter.

Yes. Sorry, no I'm starting very near term, so thank much for that. And I guess is that suggest by the way that since you get 24 fixed price contracts, you've got some ideal, but contracted revenue streams we know because of the nature of the contract then it only gets trued up later in the contract or something.

Correct. Most of the Canadian contracts are designed to where our customers can choose to not operate the rigs during the second quarter.

Right. Okay. And now you talk about 19 legacy contracts of the 24 and 14 renewing, can we assume that market pricing is still below -- current market pricing is still below that legacy contract level or we still truing down as you…

No question, market pricing is below the legacy price levels, but that gap is narrowing and I would say that our numerical guidance for the U.S. kind of low 20s would be similar for Canada for the similar Super Triple rig.

Okay, I appreciate it. Thanks. And then maybe just in terms of -- and this becomes a little bit more of a general question, but in terms of the pricing outside perhaps of the specific contract, but just in terms of period of time or the process of pushing pricing higher again I understand there is some sort of seasonal dynamics here and there is drilling programs that get set, so when might that process start or how long does it take or when do you kind of get a sense and when do you conclude negotiations as to sort of what the next round up pricing, next levels of pricing will be across the rig types.

So Brad, just traditionally the winter drilling season usually gets priced in early part of the fourth quarter in prior year. So typically for this winter, we would have placed an early October. And then, that pricing is usually fairly sticky throughout the year unless something changes and this year something changed, activity was higher than expected. So, I will tell you that we began pricing up into this activity late December last year, early January through Q1 but that was really on a handful of rigs as we move into Q3 and Q4 on all the uncontracted rigs we will be working hard to move pricing up whether at shallow or deep rig price where we're dealing with uncontracted rigs, moving pricing up. And regarding our sales to -- I guess back to what I call sustainable levels, so that's you were from few hundreds to maybe a few thousand dollars per day across the fleet.

Okay. And it is potentially more fluid and more real-time and maybe even I realized.

Well, I know today we have our sales team out in customer offices. I'm sure some customers are listening to our comments in this call right now, so I will speak really cautious. But that's said, I'll go back and say our customers recognized that the industry in 2016 was unhealthy and likely getting put into distress in many cases. For us, we made it through okay but clearly higher what you needed across the space to ensure health and I think those conversations are moving forward in a very constructive manner.

Okay.

So just to finish up the answer, this year we expect to see spot market rates increase throughout the year.

Yes, if Q4 budgets improved and then we see stronger budgets into 2018.

That will come on the back of improved commodity outlook. I think you would see further price traction in the fourth quarter into the first quarter of next year, predicated on stronger commodity prices, prices are getting closer to 55 rather than kind of circling up on 50 like we see in the last few weeks.

Right, okay. That's very helpful. I'll turn it back and get back in queue perhaps. Thanks.

Thanks Brad.

Thank you. Our next question comes from Connor Lynagh with Morgan Stanley. You may begin.

Yes, thanks. Maybe a high level one from me here, can you talk about some of the technologies and I assume it will be somewhat of an Analyst Day preview, but some of the technologies that you're deploying in addition to the automation features and how you view yourself as differentiating in both the U.S. and the Canadian markets?

Connor, it's a fairly complicated question, I'll try to move through it pieces here, think about this like a lots of technology that were proving kind of independent lead and bringing it together to create a unique package. So the blocks that we're proving separately would be directional drilling advisory software, rig automation software, high speed data communication from downhole to surface. So those are the three core blocks, underpinning those three core blocks is a standard rig software package and all the rigs. And so I can tell you that all of our AC rigs used one standard platform for our software and for the hardware as a matter of fact, it's all provided one vendor in fact our partner in that package is National Oilwell Varco and they control the software, they designed the software, but it's one package for all the rigs. Each of these technology blocks essentially operates like an app we can operate onto that system. So we're using the base system is -- these [MPM] [ph] system, they're automation software, their brand is [NOVOs] [ph] and that allows us to then plug in things like our automation software, the high speed data connection from the drill pipe and bring all of this together. Ultimately our end game here is to automate and make consistent repeatable all of the manual processes on the rig that's one piece, is to utilize advisory software to improve the overall directional drilling performance and then eventually move to full close loop drilling process control. And we think all of these building blocks can put together uniquely on the Precision platform across the entire fleet and they're really just plug in technologies, so nothing described here obsoletes or reduces any of the value in the current Super Triple fleet, it all plugs in or plugs on to the existing rigs. So I hope that gives you a bit of a sense of the preview, we'll have to go into more detail on May 15th.

Great, I understood, understood. Maybe just a quick one, so you mentioned that you used National Oilwell for lot of this, how do you think about the risk in return profile of building yourself or paying somebody else a margin to use their technology.

Well, there is couple of things, here first of all, we believe the Precision is excellent at configuring drilling rigs, operating drilling rigs, staffing drilling rigs and keeping customers happy as a high performance, high value operator of drilling rigs. We don't think our core competency is writing software. We'd rather relate se software applications to software experts, who really have the discipline, the process, and the capability to do it on a large scale, not just the Precision fleet, but that amount of the entire fleet. I know you mentioned National Oilwell Varco, and I did, but we also have partnerships with Pason, with Schlumberger and others that we're combining in this technology envelope, and I should have mentioned that, but again we're putting the expertise worldwide. So for example data gathering, Pason is excellence at data gathering. They're involved in that piece. Directional drilling technology and downhole equipment is Schlumberger's expertise, and we have our alliance with Schlumberger to provide the downhole tools. And then with that is the cable software that based on providers and then finally again the NOV platform. So again, I think it's keeping the expertise where it best lies in the industry and letting Precision focus on -- combine these technologies on any platform and then executing very well in the field.

Yes, make sense. Thanks a lot.

Thank you.

Thank you. Our next question comes from Chase Mulvehill with Wolfe Research. You may begin.

Hi, how are you all doing?

Hi, Chase.

Hi, Carey and Kevin. So I guess I'll follow-up on Canada a little bit, you talked about having 60, potentially -- 60 rigs active in the third quarter, could you help us either from a day rate perspective or gross margin perspective about expectations on those 60 rigs?

It's always a little tricky to give a day rate margin expectations that for out, but if were giving guide of the market here to 60 rigs kind of end of the summer I assume that 30 of those will be Super Triple rigs, which will be higher day rate little bit higher cost and 30 of those would be the shallower rigs, likely Super Single, which would be little bit lower day rate and slightly lower cost.

Okay. All right. And from an OpEx perspective, if we think about it in the third quarter, should we think about the kind of flat year-over-year or should we think about more as what your OpEx per day in the first quarter of 2017?

I think the OpEx will be a little bit lower than where we were in Q3 of last year just because we had higher activity, so we'll have a bit better fixed cost coverage.

Okay, great. And then, quick on the U.S. OpEx per day, how should we will be thinking about that in the second quarter of this year?

I think Kevin gave some guidance on what we expect to expense based on the number of rigs that we reactivate, so there is some recertification cost and time based maintenance that we'll be required for rigs that if we go from let's say 60 to 70 rigs. I think that numbers that Kevin quoted of $3000 to $5000 per day; our per rig to reactivate will have an impact on the cost per day. The other variable is turnkey activity you noticed that we had $9 million in turnkey revenue in Q1 which is below we've had in a long-time. If we have more turnkey activity that will drive operating cost up a bit. So I think we mentioned that absent move cost and with very little turnkey activity, our operating cost about $13,000 per day that will be a good baseline I would add to that some extra cost that we end up activating more rigs throughout the quarter and we will see where the turnkey cost shake out.

Okay. All right. And last one I'll jump back in, we think about the balance sheet and just kind of think about net debt and potentially de-levering the balance sheet, is there anything that we're not thinking about creatively that you can do whether its asset sales, is there a JV or anything that we might not be thinking about that you could do to kind of de-lever the balance sheet or accelerate de-levering the balance sheet?

Chase, it's probably several things we're thinking about where we're going and talk about publicly right now. I would tell you that it is -- it's one of our top three primary focuses for 2017 and we'll tell you that discipline around de-levering over the next several years will remain a top priority for us whether the market is going up or down going forward.

All right. Great to hear. I think that's a little bit of overhang on the stock, so it'd be nice to get some clarity there.

Appreciate it. I'll just comment the discipline using cash from operations and generating cash flow business is obviously de-leveraging occurring over the next few years.

Yes. All right. Thanks Kevin. Thanks Carey.

Great. Thank you, Chase.

Thank you. Our next question comes from Jim Wicklund with Credit Suisse. You may begin.

Good afternoon guys.

Hi, Jim.

That gives us a really good idea of cost. We don't have really a good idea of day rates and day rates were little bit of surprise this quarter. Can you tell us where sequentially where second quarter or the June quarter day rates for U.S. and Canada are expected to be?

So I think by surprise, you probably referring to the Canadian rates being pull down a little bit. Is that what you're hinting at, Jim?

Yes.

Yes. So the Canadian rates being pull down primarily by shallow rig activity during the first quarter we talked about having 30 more rigs drilling shallow in the first quarter and second quarter were down just two shallow rigs, is that sort of solves the Q2 day rate gap that you are concerned about?

Yes. Just adding to Kevin's comment in Q1 2016, we had 45% of our activity days for Super Triple rigs. In Q1 2017 that number went down to 34%. So we just had -- it's actually from a cash flow standpoint and utilization standpoint, it's a good story that reactivating more rigs, but the rigs that we're reactivating would be lower day rate rigs which drag down the average rate.

So we should expect to see day rates move up about dollars in Canada in Q2.

They typically do, typically Q2 is one of our higher day rate quarters because of the rig mix where we have deeper rigs working -- higher percentage of deeper rigs working.

Okay. And in U.S., I mean, if the rig count doesn't go up anymore this year would be up 50% year-over-year, I'm not sure what most people's expectations are for E&P cash flow growth, but you're somewhere in there and everybody I think realizes that the rig count probably isn't going to go same rate its done in the last 11 months. How much visibility do you have with your customers on additional rigs coming into the markets from here?

Jim, as we did comment that we have -- I think three more rigs to activate that are contracted right now. We have ongoing conversations or negotiations with couple of handful of customers out there for one or two rig opportunities. I don't expect all of those to become rig activations and I think there is thinking -- I think there is two things going on, I think our customers hedge cash flows and the activity we're seeing now could probably bump up a little further whether we are at 62 or 65. I don't think it's a big needle mover in activity. But, I think the next leg up is going to be kind of waiting on -- on bit of an improvement in commodity prices, I think there is lot of people waiting to see in the commodity markets, waiting to see what OPEC does in May. I think the expectation is that OPEC will extend production savings that will see fundamentals continue to improve throughout the year, commodity prices firm up a little bit, but until that materializes we could be running to the end of the rig count ramp-up at least during the second quarter I think.

Okay. Unless if I could, I know people has continued to be an issue, you've hired back 2000 people and lot of those are ex-Precision employees which is excellent. Have you lost any revenue due to not being able to find people and can you kind of discuss where you go from here in terms of people?

Yes, Jim. We kind of off the top, we haven't lost any revenue due to inability to staff rigs, not a single rig and we brought back about 2000 people by the peak of the winter season in Canada. About 85% by design are recalled and 15% by design are new hirers, so we can keep a new steam of people flowing in. So we're pretty pleased with our performance so far. We don't expect to see any missed opportunities due to the staffing challenges. It's a heavy lift, I can tell you the organization -- CEO down actually from the Board, down to the CEO, down to our drillers are focused on recruiting, training, developing people and it's easily the biggest single workload we have in our company.

Got it, gentlemen. Thank you very much.

Thanks Jim.

Thank you.

Thank you. Our next question comes from Ben Owens with RBC Capital. You may begin.

Hi, guys, good afternoon.

Hi, Ben.

So I appreciate you guys giving the information on the legacy contract and how many rolling in 2017, I was curious if any of the ones that aren't re-pricing in 2017, did they make any extend in the 2019, part of they all expire in 2018?

On the North American contracts, actually most we'll expire in '18, maybe one goes into – no will actually go into'19 on the international contracts we haven't given a full split on those, but several of those contracts is going into 2020s.

Okay, great. And then on the U.S. can you curious about, do you think given the mix of legacy contracts and new contracts on the market rate, do you think that day rates could be sequentially up in the second quarter from first quarter?

Probably on the second quarter but we are expecting to see margins – our EBITDA margins at the rig level company wide trend up in the second half of the year and I'm just not sure that's going to be Q3 or Q4, but I'm confident in the second half of the year, confident as I could be in a volatile commodity world that we'll see commodity or that will see our rig rates and margins turning up in the back half of the year.

Okay, great, that's it from me. I'll turn it back, thanks.

Great, thanks, Ben.

Thank you. Our next question comes from Ian Gillies with GMP Securities. You may begin.

Good afternoon everyone.

Hi, Ian.

I just wanted to touch on the new rig build that you mentioned earlier in the conference call. Are you able to provide any color around where the hurdle rates and pay back terms may be relative to the new builds – the new builds you are doing in 2013, 2014 and whether they've changed or stayed the same?

Okay so first guy that's asked this question and I thank you for asking the question, this rig was assembled and put together really for the purposes of the Investor Day and we do not have an customer lined up as yet and would expect to put it out into market at a return rate in line with our previously guided return rates so high teens, low 20s. So I will tell you that this rig is a very good looking brand new ST-1300, I expect it will be contracted sometime during 2017 maybe sooner than later we'll see, but we assembled and put it together as a tactical step kind of away from a long-term strategies to never build new rates on stack, but we really wanted to have a rig in the yard that we can not just show the technology on an aspirational mode, but on a full production mode. Carey?

Yes and we have enough indication from customers that we can contract this rig this year that it make sense to build it and we're following our investor day, the following day we're having a customer day where we're going to invite for several customers through our facility to do the rig.

Okay, thanks, that's helpful and perhaps just a follow-on question is to ask explicitly, this is in the start of a new rig build program for Precision.

No, it's not, I appreciate the question, it's not sort of the new build program, we don't see a rise not there has new builds on it probably not this year.

Okay, thanks very much. That's all from me, guys I appreciate that, that's very helpful.

Thanks, Ian.

Thank you. Our next question comes from John Daniel with Simmons and Company. You may begin.

Hi guys.

Hi, John.

Kevin, you mentioned low 20s for their rates on some of your best rigs U.S. rates, is that low 20s, the actual day rate is that a revenue per day concept and if the lot of what else is built in lower 20s calculation?

We will determine day rates the way we have always historically.

Yes, and John just so I think you know this for just of a clear, the directional drilling revenue that we would have associated with integrated directional drilling contract is excluded from the day rate, that would show up in the directional drilling revenue that would report.

[indiscernible] Okay, can you update us on your thoughts as it relates to M&A opportunities you mentioned rig cash flow to be used towards debt reduction is that been limit consolidation efforts by you?

I guess these – the complicated answer – simple answer is I don't know that we're going to find any M&A targets that we'll meet our bid and so we would be – if we get find a rig was exactly a PD spec that we can buy that global value we've been first of buying it probably, but in fact is I don't think there are any PD spec rigs for sale, PD rigs, spec rigs up the market and by PD spec, I mean every key piece of equivalent has to match our spec, the software has to match our spec and the rig layout should match our spec and that's a pretty complicated list.

Well, it's actually thank you more on a long lines, I apologize on within this E&P segment as you guys have been pretty clear about one by the drilling rigs.

Yes, John on this E&P segment of it, there where we see kind of the most value we created is consolidation within the well service industry and we – we're really hesitant to use our capital to effect consolidation, but if there situations where we can find creative ways to do a cashless transaction similar to the one we did with essential we would be interested and looking at that, but again it's pretty small dollars compared to our drilling business.

Okay. Last one from one, not trying to be too [indiscernible] here, but following up on Wicklund's question, you guys haven't missed any opportunity due to staffing challenging and that seems to be sort of the common reframe from your peer group. Should we assume that the labor's tightness situation is somewhat overhyped?

No, you can't, I'd say two things, John. First of all, I think in this whole oil services space, the land drillers are among the best every staffing generally, where – of any oil service space, because you're giving – you're typically giving several months of work to the worker, a lot of the other services are kind of, call it services that the work might be short service, whether it's – specific – well, pressure pumping, well servicing. But in drilling, we can almost always guarantee months of work, that attracts people quicker. But I will tell you that it's hard work is heavy lifting is in some case they can cause more, but I think the drill has done a very good job meeting that challenge, but it's still one of the toughest things we do, Carey?

Yes, adding on to what Kevin said, we've seen more challenges in the well service business attracting new crews than we haven't in the drilling business, so we think that – for the oil services industry in general the labor situation is probably not overhyped, but land drillers have, I think, comparatively done better than some of the other service providers in attracting people.

All right, thanks guys for your time. See you soon.

Thanks, John.

Thank you. Our next question comes from Jon Morrison with CIBC Capital Markets. You may begin.

Good afternoon all.

Hi, Jon.

Kevin, if I interpret your comments correctly on Canada, you're basically saying that you believe you will be get upwards of 60 rigs by mid-ish Q3 and it's fair to assume that where do you get there earlier later largely just be a function of weather?

I would say that we have line of sight to that level of activity right now. And Jon unless something disrupts commodity prices, I think that's a pretty good mark for mid Q3.

Okay.

You don't – it does well as I do that weather in early July can be pretty spotty in Western Canada and you combine that with some commodity price volatility and there are lots of excuses for customers to the late reactivations, but we'll see how plays out.

It's fair to assume that line of site that you've referenced is based on fairly firm customer conversations and not a guesstimation for the market is going well.

Yes, I agree those comments and as firm as they can be with the volatility we've seen in prices.

Okay. Can you give me more color on the U.S. mobe cost incurred in the quarter, I guess, two parts: One, were the mobe cost supported by customer contracts at this point and secondly a lot of things getting included in mobe cost by various different companies, so rig transportation, reactivation, R&M, perhaps equipment tweaks for different climates. How much of that was physically moving the rigs versus other things getting ready to work?

I'll give part of the answer and let Carey jump in if he wants to add anything to it. But – so we – I wouldn't see mobe, we actually repositioned six rigs [indiscernible] two rigs are international. And in our accounting, the repositioning cost is just the cost of loading the rigs up moving somewhere else and spotting on typically a straight on location. We also talked about – I commented any rigs that we activated during the first quarter that had that we're longer than four years in prior certification probably requires in recertification, so we had some of those during the first quarter and that's going to the math the subtracts here, the top drive, all the load-bearing components. And I'll comment that the recertification period is based on calendar four years or calendar five years or calendar two years depending on the component. It's not based on hours of use or days of use. So if it ran out a year ago when the rig was idle, we wouldn't be certified because we lose calendar days until it gets and put back to work. So we held up recertification until we have a firm date for the rig that we have a firm – we did a research as closed to that sort of days we can sort of we can get the full benefit of the maximum time out of the certification. So long story short, in the first quarter, we had some higher than probably modeled recertification costs and we had the mobe costs. I'd say it was probably two-thirds or more mobe, one-third recertification. Carey, is that fair?

Yes, it's fair.

And the majority of the mobe costs were seeking to recapture those through day rate. The recertification costs are just normal operating maintenance expense. We wouldn't typically have a handful of mobe – recertifications in one quarter, because typically they haven't kind of evenly spread over the course of the year.

Yes, I think this is actually in Q1 we activated higher percentage increase in rigs than we ever have in the history of our company.

I appreciate the color you guys gave around where your U.S. fleet is working today, is it fair to assume that the bulk of your incremental conversation at this point is still focused on the Permian and Oklahoma, are you starting to see more potential reactivation shift back to Niobrara and Eagle Ford at this point?

I'd say that at least half or more will be Permian Basin, but the balance will be kind of evenly spread as we're seeing with Oklahoma and Niobrara and Eagle Ford.

Can you give us some color on what underpin the decision to bump the CapEx at this point and is that all fairly year mark that it will get spent the '17 or there is still decent variability toward the number shakes out at the end of the year?

There is always variability on maintenance and that just depends on activity level. The upgrade CapEx is depending on customer demand so if we think about demand from our customers in the current drilling programs, there are customers are looking to pursue in a kind of $50 to $55 of oil world than 35 rigs upgrading throughout the year, it sounds about right if we have a drop in commodity prices that number will go down and it's – we're fortunate to have an increase in commodity prices throughout the year that number could go up.

In the international segment, can you share how many rig tenders you're actually involved in today, specifically in the Middle East?

The total number of rigs probably in the range of 40 or 50 rigs that we're involved in tendering for, we don't target probably between 5 and 10 of those to be successful, so we'd structure our tenders to kind of favor getting to our sweet spot, which will be 5 to 10 rigs and we're tendering in five different countries right now, is that helpful?

Yes. How of those 40 to 50 rigs that you're potentially pinning into, how many of those would be satisfied with some form of a move from a different country or ultimately a new building, how many new builds are you comfortable contemplating at this point of time everything back to your comments around cash flow and living within your means?

Yes, really complicated question, if we don't seek one of your prices improved, probably there is no new builds and they're probably just reactivations, that's the first comment so if we're bidding on some of these bids and they end up – end up turning into success and commodity price is little bit soft, it's probably just relocating anyone of the six rigs we have in Mexico and in the Middle East. If commodity prices improved and firm up, I suggest a firm up into a high 50s than there could be some builds anywhere from 2 to 4 new builds, but then probably the business we have in other markets is what we want one or two. I would not expect us in a constrained commodity price world or a constrained activity world, to be drawing down our cash position was impacting our ability to pay down debt, it's not our new builds.

Okay, last one from me. Would a temporary exit of Mexico be on the table at this point, given where PEMEX's development plans are in the long-term market?

Probably not because, once you're down there, they're stored safely. They're secure. There's no cost to keep in the meaningful cost, those rigs up probably don't have a whole unless something really turned up quickly in the Middle East that we're adding a mobe cost we call out a million dollar mobe cost in the Middle East on top of whatever upgrades rigs will need, but if the Middle East – I kind of think that whatever takes to get the Middle East going probably means that the IPM work in Mexico probably picks up. So much of this is predicated on commodity price, there is really hard to see, we're certainly not going to spend money moving rigs it advanced of a need.

Fair enough, I appreciate the color. I'll turn it back.

Thanks, Jon.

Thanks, Jon.

Thank you. Our next question comes from Jeff Fetterly with Peters & Company. You may begin.

Good afternoon guys.

Hi, Jeff.

Hi, Jeff.

Just a clarification questions, on the rig upgrade side, you said there is 42 available rigs in the U.S. for deployment, did I hear that correctly?

That's right.

Okay and should we take the 35 rigs being upgraded this year, it's attractive from the 42 number or is there…?

No, I think we're almost 10 rigs into the upgrade programs so that could probably reasonable ruling for 24 more upgrades, but probably could see a case where a rig that's running right now that has 2 mud pumps gets a third mud pump at a higher day rate. So one assumption might be either of the 42 rigs that we could upgrade 24 now or maybe some of the money in the upgrade budget goes to upgrading rigs are currently running that aren't total leading edge spec.

And although the majority of the upgrades will be for the U.S. market there, there could be some upgrades for the Canadian market too.

Do you have a ballpark estimate of what your inventory of rigs that would be available for upgrade will look like at the end of the year assuming you stay with the 35 number that you have talked about?

Again, it's a mix of rigs that are idle right now and Kevin gave an overview of the idle rigs that could be upgraded. But then, there are some rigs in the field that might have some features but maybe missing of walking system or third-mud pump that that we might look to upgrade in the field.

Out of our U.S. fleet of 104 rigs, think about 94 of those or 92 of those being either upgraded or upgrade candidates and about 10 or 12 are probably not upgrade candidates. The rigs will be specified for turnkey work and for storage well driving are typically bigger deeper rigs that we had a good business over the years that likely are not candidates for upgrades any point in time.

Okay, great. That's a helpful number. Just to clarify the early question on mobilization, so Carey, you said in your prepared remarks that rig mobilization was $1400 U.S. per day?

That's correct.

So the comment about 2/3rds being rig moved, 1/3rd being recertification, is that $1400 applicable to those two pieces or just the mobilization cost of the rig?

So, it's just in the mobilization cost of the rig, I think Kevin's comments about the time-based certifications were more of kind of impact of the overall higher cost for the quarter.

Okay. And then, from an overall standpoint, just trying to understand when your incremental margins -- you expect your incremental margins to turn positive. If you look at Q1 in terms of the drilling segment EBITDA margins ignoring Q2 for a second, but when you blend the rigs coming off of contracts the new builds coming in, the lower cost structure with sort of the better incremental off of that. Do you expect that your Q3 margins could be better than your Q1 margins, or do you think it will take longer than that?

Well, definitely we really got to the second half of the year, it really depends on how Q3 in Canada seasonally ramps up. So it's a little hard to say. I think clearly that means the Q3 is kind of tipping point at worst.

Okay.

And Jeff, I think you said something about new builds coming in, we haven't had announced any new builds coming into the market.

Okay. Thank you. Appreciate the color on those.

Thanks Jeff.

Thank you. Our next question comes from Dan Healing with Canadian Press. You may begin.

Hi, guys. Thanks for taking my question. Just looking at the part of the press release where talks about bringing in 2000 employees, some of those are new guys. In view of that, how do you regard the Canadian government's decision to go ahead with legalization of recreational marijuana?

We have been thinking about this for a long-term. We deal with it in the U.S. in several different districts. I think we deal with it quite well. Dan, we are not happy to see those kind of regulations loosened up for all the reasons we have to deal with on the rig. We want people to be fully capable of operating at maximum efficiency. So, not pleased with it. Nonetheless, it's a reality, we need to manage it and deal with it. We are managing and dealing within the U.S. Comment that we are zero-tolerance; we have a number of techniques to check the capability of our people not just alcohol or dugs, but whether they are tired or distracted or sleepy although these things can lead into risky behavior in the rigs. So I think we are focused on safety, we are mainly focused on safety and this -- Canadian government change will not something we are thrilled about. I think we will manage our way through it, it's just fine.

Okay. And just one follow-up if I can, they are leaving a lot of the room making up to the Provinces as a company whose rigs are employed in several jurisdictions. How do you feel about that?

I think we are comfortable with provinces managing the testing and the regulations, we are zero-tolerance, our regulations kind of overwrites the Provinces. If we believe an employee is impaired by distraction, by drugs, by alcohol or by lack of sleep, he is not permitted to work and we have ways of testing for all of those problems.

Okay. Thanks very much.

Great. Thank you, Dan.

Thank you. Our next question comes from Michael Sabella with Citigroup. You may begin.

Hi, good afternoon.

Hi, Michael.

I was wondering, if we can talk for a minute about what you guys are seeing on the international seven day rate, bearing in mind that everything you had working in 1Q is contracted but that you can be involved with several tenders, where would we expect those tenders, I mean relative to the current segment day rates and how are customers approaching the rate discussion?

The information we have back right now is actually very vague. So, one tender we said it earlier this quarter hasn't been reported back to the company ourselves included. So, we don't know what the results of the first tender are. We have several more that are kind of in process. Just there is so little moving to the award phase right now. It's really hard to get a sense for tender day rates. There isn't really a spot market in the places we are active, so we don't really see spot market rates in the places we are active. I know there are many other international locations. But, I think the answer is that we are going to be very disciplined, if we need to add capital to the rigs, we are in a state of return. And if that causes us to lose a tender, we will take that. We will wear that risk. So, I don't have a good answer and I think I have no clarity other than -- we will be tendering this projects, some will require upgrade capital, some may require no capital, some will require maybe a new built. Our expectations of return haven't wavered and if we lose because we are too expensive, so be it.

Thanks. And then, I was wondering if you could just talk for one more quick minute on what you see as the long-term cost structure in the U.S. and I don't know Carey's comments around kind of 13,000 per day excluding just maybe the mobilization cost and some other things. When do we think, we can ultimately get down to that level. Are we looking, thinking long-term, there is some normal cost per day for the business below 13? And then, one more follow-up quickly, in the U.S. if you could, just a question around any additional long lead time items in storage that that could help change the return profile for any more new builds going forward?

Okay, Michael. I will start with the operating cost. We mentioned $13,000 a day has been kind of a baseline, I wouldn't encourage anybody to model that into -- into their models for the next few quarters because there are always things that come up. But, that's where if things are really clicking, running 60 rigs where our costs would likely be. From call it going from 60 to 100 rigs, there maybe a slight increase in improved fixed cost absorption, but it isn't a step change. So, we could see operating cost go a little bit lower, but I would never expect them to get significantly lower.

Great. Thanks. And then, just a follow-up on the long lead-time items and storage and the one new built you had. Are there anymore rig that you can deploy some capital that's already been spent previously to change the return to profile or is it just like a special one time?

Well, it doesn't change return profile, it does change around the cash we need to spend. So, we do have an inventory of long lead-time components that we had at the end of last up cycle, some things like top drives, engines, BOPs things like that. It will reduce the amount of cash we need to spend up to complete rigs. But, we would still seek to get returns on the entire rigs notwithstanding any minor, less expensive cash always. Is that helpful?

Yep. Great. Thanks a lot guys.

Thanks Mike.

Thank you. Our next question is a follow-up from Brad Handler with Jefferies. You may begin.

Thanks for letting me back on guys. I guess maybe I noted the additional contracts you secured in the quarter, I guess I'm -- this is sort of half confirmation kind of a question, but it seem that they were pretty much all tied to recovering some form of upgrade or another. And so, is that exactly where that that your mentality is around contracts at this point in North America?

I would say that what we are looking for is, I think all of us have pretty sense where the spot market rates are for the rigs as they set. If we're having to invest in the rig or invest to move the rig or just upgrade the rig, we want to recover that cost inside the original contract, we are really thrilled to have a full ice back rig at the end of the six month or one year contract.

Right. Right. Another way just to --

And the prior quarters comments about the trajectory of day rates, nothing we've said today changes that view.

Yes, okay. Make sense. Thanks. I will turn it back.

Thanks Brad.

Thank you. I'm showing no further questions at this time. I would like to turn the call back over to Kevin Neveu for closing remarks.

All right. Well, again, thank you for joining our call today. We look forward to hosting some of you at our May 15 Investor Day in Houston. We remind you to join us in July for our Q2 earnings release and conference call. Thank you.

Ladies and gentlemen, this concludes today's conference. Thank you for your participation. Have a wonderful day.