Good day ladies and gentlemen and welcome to the Precision Drilling Corporation 2018 Third Quarter Results Conference Call and Webcast. At this time, all participants are in a listen-only mode. Following management’s prepared remarks, we will have a question-and-answer session and instructions will be given at that time. [Operator Instructions] As a reminder, today’s conference will be recorded for replay purposes. It is now pleasure to turn the conference over to your host Ms. Ashley Connolly, Manager of Investor Relations. Please go ahead.

Thank you, Hailey, and good afternoon everyone. Welcome to Precision Drilling’s third quarter 2018 earnings conference call and webcast. Participating today on the call with me are Kevin Neveu, President and Chief Executive Officer; and Carey Ford, Senior Vice President and Chief Financial Officer; and Shuja Goraya, Chief Technology Officer. Through our news release earlier today, Precision reported its third quarter 2018 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 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. Kevin will begin today’s call with a brief intro followed by a discussion of our third quarter operating results from Carey and an update on our technology initiatives from Shuja. Kevin will then provide an operational update and outlook. With that, I’ll turn it over to you, Kevin.

Thank you, Ashley. Good afternoon. While like all of you joining our call today, we are closely monitoring the macro environment, the commodity price uncertainty and the high volatility in equity markets. And during these periods of extreme volatility, the management of Precision focuses on those business elements within our control. We make sure we execute every business process efficiently and exactly as we expect. We are confident that delivering on our stated priorities is the best way to create value for our shareholders, and our shareholders have repeatedly told us they agree. So regarding the proposed combination with Trinidad Drilling are these few comments. We believe that the combination of Precision in Trinidad, which has been approved by both boards, creates exceptional value for both sets of shareholders and better valued than any other combination. I also assure the Precision shareholders will remain strictly disciplined regarding purchase consideration. We are firm that our offer of 29.1% of Precision shares to the Trinidad shareholders is the fair and correct value and we will focus all of our efforts resources on communication the value of this combination to the market. I can assure that Precision shareholders that our plans to use excess cash through this debt will not be diminished or delayed due to do this transaction. The transaction creates immediate cost synergies and we’ll continue to deliver long-term margin enhancement and expanded scale. The resulting increase in U.S. international presence enhances our scale and our market exposure in those key target regions. These synergies, cost efficiencies and operational leverage, combined with the planned sale of excess assets, including 50 Canadian rigs and several overlapping facilities will generate both immediate and long-term cash flows, substantially exceeding with some of the parts. This will provide Precision the flexibility to accelerate our debt repayment objectives while leveraging the best growth opportunities in the market. We also believe this is a highly compelling combination. We are proceeding with the necessary regulatory approvals and expect to file our shareholder circular document in the coming days. Today, we will not be answering any questions regarding the transaction in our Q&A session later in the call. You can refer to our website for more details and transaction, and we will continue to provide updates as new information develops. I’ll now turn the call over to Carey.

Thank you, Kevin. In addition to reviewing the third quarter, I will demonstrate our progress on two of our three strategic priorities for 2018, reducing debt with free cash and enhancing financial performance. Additionally, I will provide an update on our 2018 capital plan. We continue to build cash through our operations with cash in the balance sheet increasing to $110 million at the end of the third quarter. This is $45 million higher than the cash balance beginning of 2018 and Precision has already reduced long-term debt by over $75 million year-to-date. We expect to pay down more debt before the end of the year with pay downs in the upper range of our targeted $75 million to $125 million debt reduction guidance for 2018. Our 2018 financial performance continue to deliver annual improvement with third quarter revenue and adjusted EBITDA increasing 22% and 11%, respectively over the third quarter 2017. The increase in adjusted EBITDA from last year is primarily the result of higher activity in our U.S. and Canadian contract drilling businesses and higher average day rates in our U.S. contract drilling business. In Canada, drilling activity for Precision increased 7% from Q3 2017 despite the year-over-year activity increase. Utilization was negatively impacted by unusually wet weather during the quarter, which limited days and disproportionately impacted the deep proportion of our feet, resulting in an unfavorable rig mix for day rates and margins. Margins were approximately $950 per day lower than the prior year, almost entirely due to the per day impact of the shortfall payments of approximately $1,100 earned in the prior year quarter versus no shortfall payments in the current quarter. Additionally, timing of equipment certification caused cost to increase to a higher level than expected. Day rates asset shortfall payments were up $688 over…

Thank you, Carey, and good afternoon, everyone. I am Shuja Goraya. I joined Precision Drilling three months ago as Chief Technology Officer. Before Precision, I have around 24 years of drilling experience working for one of the major oilfield services company. On the technology front, we are continuing to make strong progress on all of our strategic initiatives. Since our last call, we have deployed four more Process Automation Control systems, bringing the total up to 25. And we are on plan to finish this year with 31 systems deployed in the field. I must say it’s pretty impressive to see the performance of drilling automation routines we have implemented so far. All of them over duration of the well are now beating the drillers’ time. In last three months since I have been here, I believe our overall system driller, working hand-in-hand with automation control, is performing better and maturing sooner than what I initially thought possible. We are continuously working on adding more and more automation skills to our control system to keep on improving drilling performance. We now also have a well sized in-house data analytics team who is working with all new data streams to manage and optimize operational KPIs for all of the rigs working in our fleet. Our apps ecosystem is growing well with strong customer and developer interest. We now have 15 different apps at various stages of development and trials. I think this app development space is really, probably one of the best examples I have seen in the industry of harnessing the power of partnership. We are able to bring the best of industries, processes and algorithms by working closely with our third-party developers, our customers, R&D team, universities and a few other top oilfield service companies. With our Directional Guidance System, we have drilled about 2.5 million feet since its initial deployment. And year-to-date, we have drilled over 100 wells. That’s more than twice as many wells as last year. All of these wells are being drilled in diverse drilling environments, helping to feel heart in this technology, and we are very confident that with this well tested, stable software platform and our in-house drilling competencies, we have a robust Directional Guidance System. Now I will hand the call over to Kevin.

Thank you, Shuja. So we’re thrilled to have Shuja on Board directing our rig technology efforts in our industry partnerships. Shuja and I recently attended the IADC Advanced Technology Conference held in September. This rig technology conference, now in its 10th year, enjoyed a record number of delegates and technical papers. This tells me that industry expectations for advanced drilling technology is growing, and I’m confident Precision remains at the forefront of this technology shift. Let’s now look at our markets. Beginning in Canada, precision’s rig count is back at 58 rigs this week, in line with last year. Customer indications for rigs targeting diluents and natural gas liquids in the deep basin are strong and the managed through next year barring typical seasonal weather delays in spring break up gaps. The excesses rigs supply in the deep basin has diminished as we estimate that the industry has mobilized approximately 20 rigs from Canada to United States, including one Canadian Super Triple we redeployed to Pennsylvania. We’re seeing improved industry utilization, which is encouraging, and the customers are seeking to secure rig availability with long-term contracts. At Precision, we booked five long-term contracts for Super Triples so far this year compared to zero in all of 2018. Looking at our 27 deep basin AC Super Triple drilling rigs, 22 are active today and we expect activity to step-up for full utilization by early December and through spring breakup. Customer indications also point to strong postbreakup utilization to 2019 for these rigs. For the remainder of our fleet, we expect current activity levels will hold through mid-December, slowing down for the typical Christmas break. Early indications suggest a sharp ram up in early January. And while final 2019 budgets may not be set, we expect Q1 activities should mirror last winter…

Thank you. [Operator Instructions] Our first question comes from James West of Evercore. Your line is now open.

Hey, good afternoon, guys.

Hi, James.

Kevin, maybe I’ll start in the U.S. market where it sounds like you’re getting some pretty good pricing traction. Are your customers and I know you just signed some term contracts and you don’t have a lot of renewals. But at some point here, do you anticipate some flattening of pricing, given the building of DUC inventories and some of the takeaway issues? Are they going to use that kind of against you on price? Or is it just way too tight, they’re terrified to even try to hit the rigs?

James, I think given during the third quarter, we saw that we had a couple of our spot rigs put on the sidelines and our activity was one or two rigs last year in the third quarter. I think that’s where you’ll see customers manage their spending. But I think – so the industry drive and customer preference for the most efficient rig is not going to slow down anytime soon. I don’t see – obviously, day rate aren’t going to keep on going up. There’ll be a plateau at some point. I think that’s real. But we see just very strong demand kind of across the basins and across the customer base right now for no question for pad walking rigs that can deliver consistent and predictable results. But we think the next step-up for us will be adding some of these technology pieces on those rigs to further improve the performance and further improve our returns.

All right, okay. And then one thing that stood out to me in your remarks was the term contracts in the Canadian market, which we haven’t seen in a while. How long are these term contracts?

Those contracts are one to two years in duration. And you’re right; we seldom see term contracts for rigs that don’t have some kind of new capital addition to the rig. So that’s a very productive element right now in that Canadian Basin, and we’re quite pleased with that. But it speaks to the deep basin where the principal hydrocarbon is natural gas liquids and diluents used for heavy oil. So they’re almost isolated from the weak commodity prices that some of the other Canadian players are exposed to. So again, that same drive for heavy efficient rigs that they can hold on to have guaranteed use throughout the year is very important, and I think that’s driving the contracting action.

All right, got you. Thanks, Kevin.

Great, thank you.

Thank you. Our next question comes from Taylor Zurcher of Tudor, Pickering and Holt. Your line is now open.

Thanks, good afternoon. Starting on the U.S. side, I just wanted to clarify a bit of rig reactivations for some of the rig operates you’ve been doing. You called out $3 million to $5 million of sort of reactivation costs. So as we look ahead, I assumed getting past that 80-rig mark in the U.S. You’re probably upgrading rigs that haven’t been active for awhile. So I just wanted to clarify why those rig reactivation costs might not show up, certainly not in Q4 but maybe out in Q1 or Q2 of 2019?

Hi, Taylor, it’s Carey. So just to remind the listeners, we have guided to rig reactivation costs in somewhere between $300,000 and $500,000 per rig. We had seven reactivations during the quarter. All seven of those rigs hadn’t been active since 2015, so that’s a group of rigs that hadn’t worked in several years. The rigs that we will be reactivating in, kind of call it, 80 to – the next five rigs, 80 to 85, would be rigs that have worked recently. We wouldn’t expect to incur those same costs. We also had some costs in the quarter related to restocking rigs and some certification costs that were in the third quarter for rigs that are going to work in the fourth quarter. And all of those together is kind of where we get the $3 million to $5 million bucket, which kind of equates to about $400 to $700 per day. We don’t expect to be present in the Q4 numbers.

Okay, got it. That’s helpful. And then on the Canadian side, follow-up to the prior question around the contract you signed. In the U.S., it sounds like you’re getting $25 – north of $25,000 a day for the highest rigs for the Super Triple ACs in Canada. Could you remind us where the leading edge pricing for that asset class today?

The pricing in Canada is a little softer than the U.S. We’re getting prices in the low- to mid-20s rather than pushing over to mid-20s right now for those Super Triple 1500s and very small population of 1500s in Canada. For the 1200s, it’s going to be low 20s.

Okay, got it. That’s it from me. Thanks guys.

Thank you.

Thank you. Our next question comes from J.B. Lowe [ph] of Citigroup. Your line is open.

Good afternoon, guys. I was wondering of the four to six rigs that you guys had said you’d be reactivating last quarter over the next coming weeks, have they all been now put to work?

You’re right. That’s correct. In our current rig count, those seven rigs we talked about are running and operating now. Some started in early October, a couple late September. But really, it’s been Q4 activation less than Q3.

Got you.

Yes, and I’ll just add to that. On our call, our Q2 call last quarter, we mentioned that we have line of sight of four or so rigs to be reactivated. And then we had some rigs that were at risk of being laid down that were low respect rigs that we’re working on well-to-well contracts. Both of those happened as we had a rig count trial to about 74 rigs during the quarter. It’s gotten back up to 80 rigs. And the next four rigs we’ll be adding would be some of those well-to-well rigs that got laid down in the middle of the third quarter.

And what would you say your average kind of day rate on your contracted U.S. fleet is right now? Just trying to think of how day rates can move as contracts and keep rolling?

So we don’t breakdown the contracted average rate versus the spot active rate in our disclosures. But you could model that essentially our spot rigs and our contracted rigs are in the same leading-edge bracket. And our contracted rigs have various tenors. Some of those rigs dating back to 2016, some in 2017 and some in early 2018, and now more, of course, in mid to late 2018. So on the contracted rigs, the average prices are lagging in the spot market steel.

Got you. All right, thanks.

Good, thank you.

Thank you. Our next question comes from Kurt Hallead of RBC. Your line is open.

Hey Kurt, good afternoon.

Good afternoon. Hey, sorry, I’ve added on mute. Good afternoon. How are you, everybody?

Good, good.

Excellent. So Kevin, I was wondering maybe you can give us an update on the technology rollout. I know there was some reference made to it earlier in the prepared commentary. And can you talk to when you look at that roll out and you look into 2019, can you talk to the commercial elements of these applications?

Yes, we do have some, Kurt. I’ll try to give some clarity there. We haven’t gotten into our full 2019 forecasting yet, but I’ll tell you what I’m expecting. I expect that by the end of this year, we have 31 PAC systems installed in the rigs. So today, we have 25. That means we have about six more to go between now and the end of the year. I think that’s practical. I have said in the past that of the 21 units we have prior to this quarter, that about 1/3 we had customers paying the full ticket and some are paying reduced amount and some are still on the trial mode. I’d expect that during the year of 2019, we transition those customers throughout the year over to all the customers paying for the system by the end of the year. I expect your penetration rates likely in the 75% to 80% range by the end of the year. And then if you we stay on that curve and get ahead of things a little bit, we’d expect to add more PACs during the course of next year. But again, we haven’t done our budgets yet and really haven’t light up a plan for next year. I also expect we’ll start getting up revenue in 2019. And initially, one or two extra rig that could mature into three or four extra rig on a run-rate basis by the end of the year. On a good percentage of the units are being paid for full amounts. So I think we’ll have to give you some help overtime as we get our budget budgets done with modeling. But clearly, we expect revenues to start coming in, in 2019.

Can you give us some – thanks, Kevin. That’s helpful. Can you give us some general senses to how you guys are thinking about the pricing model for these apps?

Yes, we’ve been – on the apps, there’s really two models. There is a price that we develop the applets are our app, but it’s after that it’s the customer with drilling. And recharge kind of lump sum per day amount for a Precision app. And then there’s a hosting charge. So if a customer or a service company wants to running up on the rig, we’ll charge them a hosting amount again on a daily basis. And that’s in order to just facilitate and have the up running on our rig. You’d assume that the hosting amount will be in the range of $150 to and $300 per day, depending on the type of app. And our app rate, our app could be anywhere from $300 to $500 per day, depending on the value of the upgrades.

Right, that’s great. And just one thing on the U.S. side, when you talk about upgrades. Can you kind of just give us an update on how you’re thinking about what kind of returns you need and what kind of contract duration you may need before committing to an upgrade?

Nothing has changed on that front, Kurt. We have our upgrade plan for this year is 12 to 24 rigs. We are still the same within that volume. We have said previously that none of the upgrades would cost more than $3 million per rig, and that will hold true through 2018. We’re still looking for recouping the majority of the capital within the term of the contract, and we’re looking at the cash flow associated with the contract above what the rig would get. So the incremental cash flow is what we used to evaluate the capital investment. So think of an outlay of $2 million or $3 million. We would get a bump of, call it, $4,000 a day in day rate and recoup that back within 18 months. So that’s kind of have been how we always looked at upgrade investments. As we get into 2019, some of our upgrades may become more expensive and so we’ll be looking for higher day rates and longer contracts to make sure that we get the majority of that contract recoup, the majority of the investment recoups.

Thanks, Carey. That’s great. Thank you.

Thank you. Our next question comes from Ian Gillies of GMP. Your line is open.

Afternoon everyone. With respect to the 80 rigs that are active the U.S., is there much left to do in the way of upgrades to those rigs to potentially increase EBITDA and enjoy some of the strong returns on invested capital?

The short answer is some of those rigs will get upgraded even in our current program. Some maybe upgraded next year. Still under that $3 million mark, not every one of those rigs has a pad walking system. Not every single rig has three bud pumps. So if the demand stays strong in the Permian for three-month pump pad walking rigs, there could be a handful of additional $1 million or $2 million upgrades that moved the revenue earnings capacity for some of those rigs up. You also know that we have some DCS rigs running right now in the 80 and a few that aren’t running. And Carey alluded to some more expensive upgrades that may come down the pipe somewhere. If demand stays strong and if our cash flow generation looks encouraging. We might start moving to some of those bigger upgrades where we’re converting a DC rig with AC high-spec pad walking rig. And some of those are running, some of those aren’t running. So I think there could be a mix of rigs. I think we could envision a rig count in 2019 that gets into the high 80s with our current fleet through upgrades and some redeployments.

Okay, that’s helpful. With respect to the Super Triple market in Canada, the day rates you mentioned, I was a bit surprised where they are just given the volume of assets that have left the market. Has it not tightened up quite as you would – quite as much as you would have hoped?

There’s still a lot of sort of broad market uncertainty in Canada. And while Super Triple rigs are excellent rigs, there’s still a little bit of kind of the edge at the double competition going on in Canada. So pricing power is still generally evasive in Canada. But I would tell you though also remember that our fleet in Canada, a lot of today’s pad walking rig is largely 1,200-horsepower fleet. And in fact, the rigs in Canada are not that much different than the U.S. for those rigs.

Okay. And sorry, just to sneak one last one in. Does the Trinidad transaction preclude you for making another debt repayment later this year? Or would you prefer to keep that cash in the balance sheet? Or is that still something that you think you may like to do?

Yes, I think we have covered that in our prepared comments and in the press release. We paid down $77 million so far this year. We plan to get above or into the higher end of our debt repayment range. So think of something over $100 million by the end of the year.

Okay, thank you.

Yes, and I’d reiterate that whatever we do, be it acquisitions or organic build out, our long-term targets are not going to be altered for debt repayments. That’s a very important element in creating shareholder value. Our shareholders have kind of confirmed that as we’ve met with shareholders over the past few months. And we’re pleased with our progress and they think they are, too.

Okay, thanks very much. I’ll turn the call back over.

Thanks, Ian.

Thank you. Our next question comes from Connor Lynagh of Morgan Stanley. Your line is open.

Yes, thanks. Good afternoon.

Hey, Connor.

I’m wondering if you could help us understand sort of what your work program looks like in Canada. So maybe talking about what you’re doing today and when do you decide the peak of about 90 rigs you could potentially get to? Where are those rigs drilling? Which commodity benchmarks we’d be looking at to understand where the risks might lie or where you might be in the money sort of regardless?

Okay. This gets really tricky now. Connor, we’ll speak about Q1 in pretty good detail and I’ll talk about the full year for the deep basin, those 27 AC rigs we have in the fleet. So we’ll start with the 27 AC rigs, and I’ll kind of reiterate my comments earlier. Today, we have 22 of those rigs working. We expect to fairly event increase through early December to get all 27 rigs working. They’ll likely be a bit of a break between Christmas, New Years like it was typically. But then we think that that our January 1st, all 27 rigs are working right through breakup, whatever breakup happens. We see strong customer interest. Some of those rigs will run through breakup. You would expect that maybe a third or so of that will run straight through breakup. And when the ground started to dry out in late June and July, we’d expect to see most of those rigs working again just barring mobilization weather throughout the third and fourth quarter of next year. But we’d expect pretty strong utilization in the back of next year because the target for those rigs is a commodity you can’t easily it. So the Canadian they’re natural gas liquids and the diluents products that are sold directly to heavy oil. And the product right now is getting a near WTI price in Canada, so it’s almost unaffected by all the take away issues. So that’s on the deep basin high spec AC rig fleet. Clearly, those are our strongest day rates and our strongest margins. We feel very good about that business. Now moving back to the Cardium, the Viking, the Canadian Bakken, Canadian heavy oil. That’s a lot more difficult to call and, obviously, AECO gas prices still provide a lot of cash flow for customers in Canada. The Canadian Western Canada select land impacts heavy oil drilling and then light sweet crude just impacted by the discounts also. So there’s a number of different commodities play into it. My expectation is, that budget’s get approved sometime probably in January, but that doesn’t affect Q1. I think for any operator they’re going to fund their Q1 drilling program, drill as much as they can during Q1 and then see how things play out in the back half of the year. They’ll use Q3 and Q4 to throttle their spending throughout the year a little bit like we saw this year between weather and some deferments in Q3. So I would tell you that, that activity in the back half the year right now is unclear, but I think for Q1, we’re expecting to see precision rig going to grow up to 90 the low 90s, 92, 93 rigs. 27 of those are super triples. Probably a dozen or so are heavy oil singles, and then the balance will be the Canadian shall replace Viking, Saskatchewan, Southern Saskatchewan and some of the field in Cardium. Is that helpful?

Yes. That’s helpful. I appreciate it. A complex question, so I appreciate taking a crack at it. I guess just stepping back higher level, second question here is if you look at, you guys are about to hit – you’re expecting to hit the high end of your free cash or debt pay down targets this year. In light of that, do you feel that the bottom end of that $300 million to $500 million range is pretty conservative at this point based on where the U.S. market is and where you’ll be in international markets? And obviously, Canada is a risk, but it sounds like your highest calorie rigs are going to be working pretty much regardless, so just any thoughts on that.

First of all, I would just say we don’t view Canada as a cash flow generation risk. We stated in our comments that, that’s a market that’s not going to require any growth capital. That we foresee maintenance capital will keep the rigs well maintain, and with good pricing and activity. We should generate – continue to generate good cash in that market. I think we gave a pretty broad range of paying down debt over a four-year period of $300 million to $500 million. And the reason why it’s broad range is there is a lot of cyclicality in this business, and we’ll manage through the best we can. But as Kevin said earlier, paying down debt will be our top priority. And if our cash flows from the business are stronger than what we expected, we’ll pay down debt faster.

That’s fair. I guess let me know if you can answer this. But just the addition of additional rigs to the acquisition change how you think about the target at all? Or not yet?

In the presentation that we’ve posted on our website for the transaction, one of the merits of the transaction is the cash flow generating potential of the fleet, and that would include synergies and leveraging scale. So we’ve said that the transaction could enable us to accelerate our progress on our debt reduction targets. So yes.

And we didn’t give any guidance about increasing those targets. But I can assure you, we won’t decrease the targets.

Fair enough. Thanks a lot.

Great. Thank you.

Thank you. Our next question comes from Sean Meakim of JPMorgan. Your line is now open.

Thanks, hey, guys. Could you maybe just give us a sense of in the U.S., are you seeing any material difference in rig demand in the Northeast or the Permian versus other basins? Or is it fairly consistent despite some of the obvious challenges that some producers in those basins are experiencing?

It might be customers mix maybe, but certainly demand for us in the Marcellus, Northeast and Permian appears to be just a little stronger than we’re seeing in other areas right now. But part of that could be that Colorado’s going to be flat until the boat. I think the SCOOP, STACK is stable, and I think we’ve had a little attention to the Bakken lately. I expect to see a little bit more activity for us know next year in Haynesville also. But I think that we’ve just see the little bit – and I think maybe our customer mix more than anything, a little heavier draw in the Marcellus and the Permian.

Okay, got it. In the Middle East, any initial commentary you can give us in terms of what you are seeing in the form of potential tendering opportunities and looking across some of these integrated projects that some of the large CAT diversifies are undertaking? Some cases in similar rigs, other cases, I was looking to source third-party. Just those influences on the rig market in that part of the world for next year. It would be great to get a little more details on those moving pieces.

Sean, things have gotten actually a little cloudier over the last few weeks. I think there’s some turmoil right now. There certainly out the news everyday right now around Saudi Arabia that’s I think just causing some decisions to slow down a little bit. And I think that in Kuwait are the core market there. Just award of bunch of contracts, rigs are being built and being deployed. So I think they are digesting the increase that they put forward to the last round of tenders. I expect to see more tenders emerging in Kuwait in late in 2019, probably 2020 delivers. They didn’t meet all of their demands in the last round, so there could be more coming down the road. We have a live tender right now that we participated in Saudi Arabia. That tender is open until March, so it could be awhile before we could hear anything. There had been ongoing clarifications, but no real indication of accelerating that process. If anything, staying in the current schedule. So nothing imminent right now that has activating rigs near term. But our team is out there discovering every day. We’re certainly talking to the major service companies about IPM opportunities. We booked a few and I’d like to see what those developments we can do in the New Year. I think nothing will happen this year. I don’t expect any announcements at the end of the year.

Got it. That’s very helpful. Thanks, guys.

Thank you. Our next question comes from Jon Morrison of CIBC Capital Markets. Your line is now open.

Good afternoon, all. Kevin, just a point of clarification. You messaged that Precision had 80 active rigs in the U.S. at this stage. Does visibility extend far enough into the future? Do you believe you’re comfortable to say that your activity should largely hold as being fairly flat through year end and, call it, through Q1 2019 x the obvious Christmas noise even if you saw some fall of the decent downdraft in the Permian in Half one, say, 5% or 10%? Still think you should be fairly immune to those headwinds, is that fair?

I don’t have the numbers in front of me right now, Jon. But I think in the U.S. right now, I think roughly 50 of those rigs are under take-or-pay contracts. I think those rigs are rock solid. I think we have a few more contracts that kick in later this year and early next year. Some of those are on existing well-to-well rigs, some of those might be additional rig deployments. But I feel good about the contracted rigs. The well-to-well rigs, those that are in the Permian are always exposed to variability. So I think that risk never really goes away unless we work up more rigs in the contract. What I will say for sure though is that these day rates right now, we’re actively pursuing contracting every one of our high spec rigs where day rates for the north 25,000 or rigs that will walk in for a year or two happily. So I would expect to see our contract book continue to grow, and that gives me more comfort. What I’ll tell you is that one of the dynamics around completions are just a little different than drilling. You can go ahead and drill a complete pad and park that pad and wait till later to complete it. In fact if you’ve got production obligations to meet to fill the pipeline up in June, chances are you probably want to have three or four or five parts drilled and completion starting in Q2. So those wells are completed and flowing at the beginning of Q3 the pipeline comes on. So a lot of discussion around inventory of drilled and completed wells. Well, it’s a big issue and industry issue for pressure pumping. For drilling, it’s part of a normal planning sequence. And the most efficient rigs right now aren’t really impacted by more or less ducks coming up or going down. So I hope I’ve answered your questions there. Short answer is we feel pretty able to contract rigs. I feel generally good about overall activity levels. I expect our rig count creep up a little bit between now and the end of the year. And I think we’re in for Q1, Q2 a bit like last year where rig counts moved up, the commodity prices stayed strong. I don’t think single digit or a low double-digit differential to the Permian will slow that down.

That’s really helpful. Despite some of the hard run in Canada just on the differential issues and the unknowns around what 2019 spending profiles are going to look like at this stage, is it fair to say that you don’t expect any major downdraft in half one day rates based on your current bookings, customer conversations and stock of fleet that you are running in Canada?

Yes. Again, the short answer there I’ll go yes. I think the drillers in general are behaving in Canada very disciplined. And the industry generally doesn’t run at just barely positive cash flow for any sustained periods. If we do that, you can’t cover your maintenance CapEx. You need to have enough cash flow to cover your maintenance CapEx and hopefully replace your assets over time. So for very short periods, we see rates dip down. But on a sustainable basis, the industries behave quite in a very responsible manner and very good discipline across the industry. And short of some complete collapse in Canada, not a differential question, but a complete commodity collapse. I think our rates are not at risk next year, but we posted at class in the past several years. So it is not a guarantee.

For sure. If you don’t mind me the two question and just walking on two other quick things. The first is just be on Saudi. Do you extend your contracts through year end and mentioned that you’re likely to extend into multiyear renewals. Is that just apply to in terms of the latter part, does that just apply to the two rigs that were extended through 2018 year end or is that for all three of the rigs in terms of the long-term contracts being likely?

The third rig still has, I think, two or three-year horizon on its contracts. It’s not even close. The usually don’t talk about this renewals. So that rig is out for three years. The other two rigs that extended through the end of the year before the middle of December, those will be extended out for more years. I don’t know if it’s going to be two or three yet.

Okay. Just last one for me, I hear you don’t want to answer any questions about the Trinidad deal, But I just wanted to clarify one comment you made earlier in the call in terms of how to evaluate the best outcome for Trinidad shareholder. When you speak about the best result, is it fair to say that when you’re evaluating the upside potential and value for Trinidad shareholder, you are thinking of it more from a medium to longer time horizon and value that we can be created to the combined entity? And that while you are not immune to the market gyrations, you are not just valuating it on a simple couple pennies below or above that premium when you think about the value for the shareholder.

I just kind of reiterate the comments earlier. I think the combined company creates excellent value for shareholders at all the combined company.

Okay. I appreciate the color.

Thank you.

[Operator Instructions] Our next question comes from John Daniel of Simmons and Company. Your line is now open.

I got just one question on your sort of your forgotten segment here, Completion and Production Services. But when you look at the just the year-to-date results year-over-year, it’s basically a mirror image. So I’m just curious kind of your thoughts for what we see a repeat of this next year. Is there any initiatives going on right now, which where you would see some sort of remarkable improvement next year in the segment. Just your general thoughts on the various businesses within that segment.

John, that’s a good question. We spent all of about 45 seconds on my third comments today. So a couple of things. The first half of this year, you will remember we brought on a new division leader who is doing a great job running that business for us. But truly for the first quarter and a half, he was reorganizing the business unit. We had some severance costs, some changes in the business and some one-time cost if the business going to wind up properly. In fact, in the third quarter, as Carey commented our EBITDA year-over-year was about flat, Carey?

400,000.

400,000 on reduced revenue. So I think he’s done a great job repositioning our business. Assuming activity level stay flat yea-over-year at expect us to reform better next year between better cost management, material organization, a very – much more focused organization and improving pricing with customers who recognize that this business has to maintain the rigs.

Got it. You talked long about the need for higher pricing there for all the various reasons. We know why work ever need to higher pricing, are your customers getting it?

We’re seeing signs right across the board they’re getting it. And the price increases are not extreme. They are measured, they are carefully negotiated. But we are seeing to all customers in all regions right now. And the industry as a whole, the mom-and-pops meet at the larger players like yourselves the other public players needed. You can’t run this business on $1 of EBITDA, you need to have enough EBITDA to pay the maintenance of the rigs and a little more.

Totally. Okay. Thanks Kevin.

It’s good to see some semblance of logic flowing into the space right now.

If needed. Thank you.

Thank you.

Thank you. Our next question comes from Brad Handler of Jefferies. Your line is now open.

Thanks. Hello everybody. My question is probably direct at Shuja. So I’m curious, if you can give us an update on directional guidance progress. So there is a competitor out there that’s now advertising that they fully automated the system, right. They can actually control the curve yield. And I guess I’m curious if that’s something you’re still working towards or if you can update us? I know you can generally define automation in terms of scale and progress along that scale?

Hi, Brad. So there are two pieces of directional idle system. One is the kind of algorithm, which is you need to go from point A to B. What does it take and what [indiscernible] take. Once you don’t get there, you have software continuously compute and tells you what’s the best way to land it. And I pretty much landing sort of thing, right. And I think that’s the really the software piece, which we are very comfortable with. Now there is the other piece of it, the software is really there is lots of different things has been working on over 80 years that’s supposed hiding in their tele books. Really, sometimes the algorithms is not simplest of algorithms. So what do you really need to get is a software package to do is to run a ton of miles on it, right? That’s why I was saying we have run about 2.5 million feet or driven 2.5 million feet with the software. And I think that’s really what you need to get done diverse environments and make sure that you have run enough scenarios that once you really get to a point whereby you can completely make it independent, it covers that 0.001%. So I am very comfortable that as we deploy more, as we get more mileage on it, this is what we cover. Then the next piece of it is, they look the guidance system tells the driller, turn 90 degrees right and slide 10 feet. And the driller has to execute that. So really the next step of it is executing that piece of command. And I think we are experimenting with something. I don’t think we are 100% there, but we definitely have a few things in the works as well it’s a few months sort of the story. So I think I’ll better on the system for two reasons. One, you have a lots of mileage, more mileage in better. Two, we have an internal directional drilling company, right? So that does bring the internal competent whereby you can actually directionally drill these things. So I think that’s another critical part of it.

That should help you develop it faster essentially, right? That’s just going to help you develop a more robust and perhaps develop it faster inside having that internal capability?

Yes. And I think eventually, you need to make sure that you learn very quickly from early mistakes just like autonomous self-driving cars, right? You just need to learn very quickly. So having that competency makes you do that close the outlook very quickly.

Brad, and if I could add on to the comments here. I think this should become the domain of the drilling contractor. I think it will be the drilling contractor that will have the steering advisory software, the automation software that will connect it to and they’ll do the closed loop drilling. I think it will us. I think it will be any other drilling contractor that has either directional drilling capability, or software capability, or their own algorithm if they are running in marketing right now. it will become part of the next wave of technology and rigs, which is why we’re pursuing it.

Yeah, that make sense. I appreciate the timeline and sort of the update. Okay. very good. Thank you.

Thank you.

Our next question comes from Jeff Fetterly of Peters & Company. Your line is now open.

Thanks, just two clarification questions. On the day rate side, last call you had talked about an average of about an average of $500 to $1,000 per day on a sequential basis is what you expected to see adjusted, obviously. Is that still a fair statement of how you see the market over the next couple of quarters?

Jeff, we said that for Canada, you expect to see rates over $500 to $1,000 a day year-over-year sequentially. And I think my comments for Q1 into that same range for Q1. So again, year-over-year comparisons in Canada looking like somewhere between $500 and maybe $1,000 and probably not to exceed $1,000 on average. In the U.S., I don’t think we didn’t give any give any guidance. I’m still thinking about rates stepping up quarter-over-quarter around $500 a quarter or maybe a little more as a reasonable expectation going forward.

And then from an activity standpoint, in the Permian specifically, have you seen any indication or are you concerned in any of your existing clients or any operators of dropping rigs, either going into year-end over next couple of quarters?

As I said earlier, we still have a component of rigs in the Permian that are in well-to-well contracts, and I think those rigs have exposure. I did comment that I expect the rig count modestly move upwards between now and the end of the year. So nothing we’re hearing today that tells us we should expect rig count to hold back. But I commented that 25 or 35 of those rigs are on well-to-well contracts, and if any given customers should decide to shutdown on December 15, we could see our rig count soften up a little bit at the end of the year. But I think it reenergizes come January 1 when we come to new budgets.

So the way you see it right now from the U.S. standpoint or from a Permian standpoint, 80 rigs or 41 rigs is about the base level?

It feels that way today. And obviously, there’s a lot of moving pieces right now and commodity price are all over the map, depending on which day we could look at this strip. But again, talking to our customers, I think 80 rigs modestly moving up a little bit. I wouldn’t be surprised to see a couple of rigs coming off late in December as people throw a lot of spending by the end of the year. But then expect to see those rigs come back come January 1 and be moving kind of without any interruption from wherever we finish off the peak. Just sitting in the low 80s in January is not a stretch.

And Jeff, just to round out some of the guidance we gave earlier on costs, I think we feel pretty confident saying that margins in the U.S. will increase somewhere between $750 to $1,000 a day. Some of that could be cost reduction, some of that might be day rate increases. But we’ve just had, as you follow the story, we’ve just had a lot of rigs go back to work. We’re recontracting rigs and trying to get the best rates possible. We don’t have as good a guidance on where the day rates are going. They are going up, but can’t really give you guidance on the magnitude of that.

And just to make sure I heard it correctly, you talked about in terms of migration or rig moves within the U.S. are potential for rigs to move into the Marcellus and into the Permian, correct?

Yes, we wouldn’t be surprised to see rigs start to move up around a little bit. We’ve been focused on kind of even spread around all the basins. I think example might be if demands is very strong in the Marcellus. We could see a rig or two move from maybe Mid-Con or Colorado to the Northeast.

Okay, great. Thank you appreciate the clarify.

Thank you.

Ladies and gentlemen, this concludes today’s question-and-answer session. I would like to turn the conference over to your host, Ms. Ashley Connolly for any closing remarks.

Thank you all for joining today’s call and look forward to speaking with you when we report fourth quarter 2018 in February. Thank you.

Ladies and gentlemen, thank you for participating in today’s conference, this concludes today’s program, you may all disconnect. Everyone have a great day.