Precision Drilling Corp (PDS) 2018 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Precision Drilling Corporation 2018 Third Quarter Results Conference Call and Webcast. (Operator Instructions) As a reminder, today's conference will be recorded for replay purposes.

It is now my 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; 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, I have a few comments. We believe that the combination of Precision and Trinidad, which has been approved by both boards, creates exceptional value for both sets of shareholders and better value than any other combination.

I also assure the Precision shareholders that we will remain strictly disciplined regarding purchase consideration. We are firm that our offer of 29.1% of Precision Drilling shares to the Trinidad shareholders is the fair and correct value, and we will focus all of our efforts and resources on communicating the value of this combination to the market. I can also assure the Precision shareholders that our plans to use excess cash to reduce debt will not be diminished or delayed due to do this transaction.

The transaction creates immediate cost synergies and will 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 the sum 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 shareholders' 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 on the transaction, and we'll 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 results, I will demonstrate our progress on 2 of our 3 strategic priorities for 2018: reducing debt with free cash flow; and enhancing financial performance. Additionally, I'll provide an update on our 2018 capital plan.

We continue to build cash through our operations with cash on 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 2008 (sic) [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 paydowns in the upper range of our targeted $75 million to $125 million debt reduction guidance for 2018.

Our 2018 financial performance continued 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 deeper portion of our fleet, 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 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, absent shortfall payments, were up $688 over the prior year quarter.

Turning to the U.S. Drilling activity for Precision increased 25% from Q3 2017, while margins were up approximately USD 800 per day, positively impacted by day rates that were up approximately USD 2,300 per day. The increase in day rates was offset by operating costs that increased approximately USD 1,500 per day. The increase in operating cost was due to reactivation and restocking of rigs, crew configurations and timing of recertification and repair costs.

We have said in the past we had not experienced field cost inflation, but we began to see it in our results during this quarter. That being said, we believe $3 million to $5 million of U.S. dollar costs incurred in Q3 will not be repeated in the fourth quarter. Internationally, drilling activity for Precision equaled activity in Q3 2017 and average day rates internationally were approximately USD 50,000 per day, in line with the prior year.

In our C&P division, adjusted EBITDA this quarter was $4.6 million, up from approximate -- up approximately $400,000 compared to the prior year. Well service activity in the quarter was down year-over-year negatively impacted by weather. However, improved pricing per hour and benefits of cost-saving strategies resulted in higher year-over-year margins.

Our Corporate costs increased over the third quarter 2017 due to an increase in our share-based compensation accrual of $5.5 million, $4 million of which was allocated to G&A -- to Corporate G&A. Additionally, we incurred approximately $1 million in transaction-related costs during the quarter. The share-based compensation cost has demonstrated significant volatility this year due to the underlying volatility in our share price and in the current quarter. This volatility has continued into the fourth quarter.

Capital expenditures for the quarter were $29 million, and our 2018 capital plan remains $135 million for the year. The 2018 capital plan is comprised of $52 million for sustaining infrastructure, $71 million for upgrade and extension and $12 million for intangibles related to our new ERP system.

We made extensive progress on our contract book during the third quarter and into October, signing 20 term contracts since July 1. And as of October 24, we had an average of 67 contracts in hand for the fourth quarter, an average of 61 contracts for the full year 2018 and 33 for the full year 2019.

As of September 30, 2018, our long-term debt position net of cash is approximately $1.6 billion and our total liquidity position was approximately $800 million.

For 2018, we would expect depreciation to be approximately $350 million. We would expect cash taxes to remain low and our effective tax rate to be in the 20% to 25% range. We continue to aggressively manage all fixed costs, including G&A in an effort to enhance financial performance in an increasing activity environment.

I'll now turn the call over to Shuja for a technology update.

Thank you, Carey, and good afternoon, everyone. I am Shuja Goraya. I joined Precision Drilling 3 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 4 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 3 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 stream to manage and optimize operational KPIs for all of the rigs working in our field.

Our Apps ecosystem is growing well and strong -- 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 partnerships. 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 the heart in this technology, and we are very confident that with this well-tested stable software platform and our in-house directional 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 and stewarding our industry partnerships.

Shuja and I recently attended the IADC Advanced Rig 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 that Precision remains at the forefront of this technology shift.

Now looking 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 demand should be firm through next year barring typical seasonal weather delays and spring break-up gaps.

The excess rig supply in the Deep Basin has diminished as we estimate that the industry has mobilized approximately 20 rigs from Canada to the United States, including 1 Canadian Super Triple we redeployed to Pennsylvania. We're seeing improved industry utilization, which is encouraging, and customers are seeking to secure rig availability with long-term contracts.

At Precision, we've booked 5 long-term contracts for Super Triples so far this year compared to 0 in all of 2017. Looking at our 27 Deep Basin AC Super Triple drilling rigs, 22 are active today and we expect activity to step up for a full utilization by early December and through spring break-up. Customer indications also point to strong post break-up 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 ramp up in early January. And while final 2019 budgets may not be set, we expect Q1 activities should mirror last winter for Precision, peaking at the low 90s. We also expect that rig rates will remain constructive into Q1 with year-over-year pricing trending upwards of $500 per day across the fleet. We do not have visibility on full year budgets as yet. We expect this may be delayed into early 2019 as our customers carefully analyze the Canadian macro.

But I want to remind the listeners that while the general outlook for Canada is not crystal clear, Precision is well positioned with a fleet of modern, high-performance rigs. We do not anticipate any upgrade or growth CapEx spending in 2019, and our focus will remain on continuing to maximize our free cash flow as we have this year.

Now turning to the United States. As our customers prepare for 2019 drilling programs, the drive to the most efficient rigs seems to be accelerating even as the market volatility is tempering our customers' risk appetite. We are experiencing a surge in demand for the most efficient rigs, and those are specifically our pad walking Super Triples. We're now booking contracts with rigs trending into the upper 20s and with terms now stretching from 1 to 2 years. We commented on our press release that since the end of Q2, we've signed or renewed a total of 18 term contracts. With every renewal, we've achieved day rate increases with some upwards of $5,000, depending on the prior year contract vintage.

For Precision's well-to-well rigs in the spot market, the pricing is still slowly trending upwards for our 1,200 and 1,500 AC Super Triple rigs. All the rigs repriced during the quarter moved up in price, ranging from a few hundred dollars per day to several thousand dollars per day.

With our current U.S. activity at 80 this week, including 7 rigs that have not worked since 2015, this is the highest utilization we've reported since the 2014 downturn, and our U.S. market share is currently at its all-time highest level.

We believe these market signals speak to the success of our high-performance strategy, coupled with the exceptional performance of our well-trained rig crews operating our Super Series rigs.

In the Permian, we currently have 41 rigs running and expect to see continued strong demand for our Super Triple pad walking rigs.

Across the other regions, including Eagle Ford, Mid-Con, Rockies, Bakken, the Haynesville and the Marcellus, we have 39 rigs operating and have contracts for additional rigs to be deployed in Q1 and Q2. It's possible that we may have some interbasin rig movement as the current demand in the Permian and Marcellus is the strongest, thus, leading to better contracting terms in those areas.

In Colorado, the industry is very focused on the upcoming Proposition 112 ballot, and we, like most, are hoping commonsense will prevail and defeat the proposition.

Now regarding our business in Kuwait. The new-build project is well underway. The rig build is on schedule, it's on budget and we'll deploy mid-next year as planned. And Kuwait remains a very solid market for Precision Drilling internationally.

In Saudi Arabia, we continue to have 3 rigs operating as we previously disclosed. Two of those rigs received contract extensions through the end of the year, and we are well advanced with the negotiations to renew those contracts for several more years. We also continue to look to activate our 4 idle rigs in the region. It remains very important for us to improve our scale in Saudi Arabia in order to achieve the desired country level returns we seek.

Turning to our well service business. Our well service group continues to manage through a very challenging market, which suffers from significant oversupply and still persistent weak customer demand. We've made good progress managing fixed costs. We've optimized our field support and we're meeting the challenge of staffing up services rigs where there's a largely intermittent work career opportunity.

The industry remains stuck in a sub-survival mode with minimal industry reinvestment, which is now leading to a reduction in available equipment. We're seeing signs of customers appearing to recognize how difficult this is as some are now accepting rate increases and crew labor premiums to help us manage through these issues. Now I'm pleased that our team is keeping our customers satisfied with Precision's High Performance services. They're sustaining the quality of our assets and they're improving our cash flows. So I think in a very tough situation, our team is doing a great job in that business.

I'll wrap up my comments by reminding you that the Precision team remains focused on creating shareholder value, with steady progress delivering free cash flow, commercializing our advanced rig technologies and improving our capital structure through further debt reduction.

I'd like to thank the employees at Precision, many of whom are also shareholders and listening to this call, for their dedication, their hard work and the good results they've helped deliver this quarter.

And I'll now turn the call back to the operator for questions. Thank you.

(Operator Instructions) Our first question comes from James West of Evercore.

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've done 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? And are they going to use that kind of against you on pricing or is it just way too tight that they're just terrified to even try, they just need to keep the rigs?

James, I think even during the third quarter, we saw that we had a couple of our spot rigs put on the sidelines and our activity was 1 or 2 rigs less during the third quarter. I think that's where you'll see customers manage their spending. But I think the -- 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 rates 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 and -- but we think the next step-up for us will be adding some of these technology pieces onto 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 1 to 2 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 plays are exposed to. So again, that same drive for heavy efficient rigs that they can hold on to and have guaranteed use throughout the year is very important, and I think that's driving the contracting action.

Our next question comes from Taylor Zurcher of Tudor, Pickering, Holt.

Starting on the U.S. side. I just wanted to clarify a bit the rig reactivations for some of the rig operators you've been doing. And you called out $3 million to $5 million of sort of reactivation costs. So as we look ahead, I assume getting past that 80-rig mark in the U.S., you're probably upgrading rigs that haven't been active for a while. And so just wanted to clarify why those rig reactivation costs might not show up, or certainly not in Q4 but maybe out in Q1 or Q2 of '19?

Taylor, it's Carey. So just to remind the listeners, we have guided to rig reactivations costing somewhere between $300,000 and $500,000 per rig. We had 7 reactivations during the quarter. All 7 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 would be reactivating in, kind of call it, 80 days and the next 5 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 for a 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 the mid-20s right now for those Super Triple 1500s and a very small population of 1500s in Canada. For the 1200s, it's going to be low 20s.

Our next question comes from [J. B. Lau], Citigroup.

I was wondering of the 4 to 6 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?

Right. That's correct. In our current rig count, those 7 rigs we talked about are running and operating now. Some started in early October, a couple late September. But really, it's been a Q4 activation less than Q3.

Yes, and I'll just add to that. On our call, our Q2 call last quarter, we mentioned that we had line of sight of 4 or so rigs to be reactivated. And then we had some rigs that were at risk of being laid down that were lower-spec rigs that were working on well-to-well contracts. Both of those happened as we had a rig count trough to about 74 rigs during the quarter. It's gotten back up to 80 rigs. And the next 4 rigs that 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? I'm just trying to think of how day rates can move as contracts keep rolling?

Well, so we don't break down 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 '16, some to '17 and some in early '18. And now more, of course, in mid- to late '18. So on the contracted rigs, the average price is lagging the spot market still.

Our next question comes from Kurt Hallead of RBC.

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 rollout 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 you some clarity there. We haven't gotten into our full 2018 -- '19 forecasting yet, but I'll tell you what I'm expecting. I'd expect that by the end of this year, we have 31 PAC systems installed on the rigs. So today, we have 25. That means we have about 6 more to go between now and the end of the year. I think that's practical. I've said in the past that of the 21 units we had prior to this quarter, that about 1/3 we had customers paying the full ticket and some were paying a reduced amount and some are still on trial mode.

I'd expect that during the year of 2019, we transition those customers throughout the year over to all customers paying for the system by the end of the year. I expect our penetration rate's likely in the 75% to 80% range by the end of the year. And then, if we're -- if we can 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 laid out the plan for next year.

I also expect we'll start getting App revenue in 2019. And initially, 1 or 2 Apps per rig, but that could mature into 3 or 4 Apps per rig on a run-rate basis by the end of the year on a good percentage of the units that are being paid for full amounts. So I think we'll have to give you some help over time as we get our budgets done with modeling. But clearly, we expect revenues to start coming in, in 2019.

Can you give us -- Kevin, that's helpful. Can you give us some general sense as to how you guys are thinking about the pricing model for these Apps?

Yes, we've been -- on the Apps, there's really 2 models. There's a price if we develop the App and it's our App and it's an App that aids the customer with drilling. And we charge kind of a 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 run an App on the rig, we'll charge them a hosting amount. It's again a daily basis. And that's in order to just facilitate and have the App running on our rig. You'd assume that the hosting amount will be in the range of $150 to $300 per day, depending on the type of App. And our App rate, if it's our App, could be anywhere from $300 to $500 per day, depending on the value the App creates.

All right. That's great. And then 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?

Yes, nothing has changed on that front, Kurt. We have our upgrade planned for this year, which is 12 to 24 rigs. We're still staying within that volume. We've said previously that none of the upgrades would cost more than $3 million per rig, and that'll 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 use 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 been how we've 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 recouped -- majority of the investment recouped.

Our next question comes from Ian Gillies of GMP.

With respect to the 80 rigs that are active in 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 those strong returns on invested capital?

The short answer is some of those rigs will get upgraded even in our current program. Some may be 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 3 mud pumps. So if the demand stays strong in the Permian for 3 mud pump pad walking rigs, there could be a handful of additional $1 million or $2 million upgrades that move the revenue earning capacity for some of those rigs up. You'll also know that we have some DC/SCR rigs running right now in that 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 to an AC high-spec pad walking rig. So -- and some of those are running, some of those aren't running. So I think there could be a mix of rigs.

I think getting our -- 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 at 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 a -- kind of at the edge, heavy telling double competition going on in Canada. So pricing power is still generally evasive in Canada. But I would tell you, though, so also remember that our fleet in Canada, while it's an AC pad walking rig, it's largely a 1,200-horsepower fleet. And in fact, the rates 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 from making another debt repayment later this year? Or would you prefer to keep that cash on the balance sheet? Or is that still something that you think you may like to do?

Yes, I think we 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.

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 I think they are, too.

Our next question comes from Connor Lynagh of Morgan Stanley.

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 cite the peak of about 90 rigs you could potentially get to, where are those rigs drilling? Which commodity benchmarks should we 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, that's those 27 AC rigs we have in the fleet. So let's start with the 27 AC rigs, and I'll kind of reiterate my comments from earlier. Today, we have 22 of those rigs working. We expect a fairly even increase through early December to get all 27 rigs working. There'll likely be a bit of a break between Christmas, New Years like there is typically. But then we think that on January 1, all 27 rigs are working right through break-up, whenever break-up happens.

We see strong customer interest. Some of those rigs will run through break-up. You could expect that maybe 1/3 or so of them will run straight through break-up. And then when the ground starts to dry out in late June and July, we'd expect to see most of those rigs working again, just barring mobilization of weather throughout the third and fourth quarter of next year. But we'd expect pretty strong utilization the back half of next year because the target for those rigs is a commodity you can't easily see. It's the Canadian -- the heavy natural gas liquids and the diluent 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 takeaway 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 our customers in Canada. The Canadian -- Western Canada Select blend impacts heavy oil drilling and then light sweet crude gets impacted by the discounts also. So there's a number of different commodities that play into it. My expectation is that budgets 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. And 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 of the year right now is unclear. But I think for Q1, we're expecting to see Precision's rig count go up to around 90 -- the low 90s, could be 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 shallower plays Viking, Saskatchewan, Southern Saskatchewan and Shaunavon field and Cardium. Is that helpful?

Yes, that's helpful. Yes, I appreciate it's a complex question, so appreciate you 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 -- or you're expecting to hit the high end of your free cash, your 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, 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 off, I would just say we don't view Canada as a cash flow generation risk. We've stated in our comments that that's a market that's not going to require any growth capital that we foresee. So it's just going to be maintenance capital to keep the rigs well maintained and with good pricing and activity, we should generate good -- continue to generate good cash in that market. I think we gave a pretty broad range of paying down debt over a 4-year period of $300 million to $500 million. And the reason why it's a broad range is there is a lot of cyclicality in this business, and we'll manage through it 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 mean, I guess let me know if you can't answer this, but does the addition of additional rigs to the acquisition change how you think about that 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 would not decrease the targets.

Our next question comes from Sean Meakim of JP Morgan.

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 our customer 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 vote. I think the SCOOP/STACK is stable, and I think we've had a little less attention on the Bakken lately. I expect to see a little bit more activity for us, though, next year in the Haynesville also. But I think that we've just seen a little bit -- and I think it might be our customer mix more than anything, a little heavier draw in the Marcellus and the Permian.

Okay, got it. And then in the Middle East, any additional commentary you can give us in terms of what you're seeing in the form of potential tendering opportunities and looking across some of these integrated projects that some of the large cap diversifieds are undertaking? In some cases, using similar rigs. Other cases, obviously, 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 just to get a little more detail on some of those moving pieces.

Sean, things have gotten actually a little bit cloudier over the last few weeks. I think there's some turmoil right now. Certainly, the news everyday right now around Saudi Arabia that's may -- I think just causing some decisions to slow down a little bit. And I think that in Kuwait, our other core market there, they've just awarded a bunch of contracts. Rigs are being built and being deployed. So I think they're digesting the increases they put forward through the last round of tenders. I expect to see more tenders emerging in Kuwait in -- late in 2019, probably 2020 deliveries. 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've participated in, in Saudi Arabia. That tender is open until March, so it could be a while before we hear anything. There have 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 us activating any rigs near term. But our team is out there scouring every day. We're certainly talking to the major service companies about IPM opportunities. We've looked at a few and I'd like to see where those develop, again, early in the new year. Nothing will happen this year. I don't expect any announcements prior to the end of the year.

Our next question comes from Jon Morrison of CIBC Capital Markets.

Kevin, just a point of clarification. You messaged that Precision's at 80 active rigs in the U.S. at this stage. Does visibility extend far enough into the future that 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 '19 ex the obvious Christmas noise even if you saw some form of a decent downdraft in the Permian in half 1, say, 5% or 10%? Do you 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, early next year. Some of those are on existing well-to-well rigs, some of those might be some additional redeployments. 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 lock up more rigs under contract.

What I will say for sure though is that at these day rates right now, we're actively pursuing contracting every one of our high-spec rigs where day rates that are north of $25,000 are rigs that we'll lock in for a year or 2 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 until later to complete it. In fact, if you've got production obligations to meet to fill a pipeline up in June, chances are you probably want to have 3 or 4 or 5 pads drilled and completion starting in Q2, so those wells are completed and flowing at the beginning of Q3 and the pipeline comes on.

So a lot of the discussion around inventory of drilled uncompleted wells, while it's a big issue and industry issue for pressure pumping, for drilling, it's part of the normal planning sequence. And the most efficient rigs right now aren't really impacted by more or less DUCs coming up or going down. So I've answered 3 or 4 questions there. Short answer is we feel pretty good about the contract rigs. And I feel generally good about overall activity levels. I expect our rig count could creep up a little bit between now and the end of the year. And I think we're in for a Q1, Q2 a bit like last year where rig counts move up, the commodity prices stay strong. And I don't think a single digit or a low double-digit differential to the Permian will slow that down.

That's really helpful. Despite some of the heartburn 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 1 day rates based on your current bookings, customer conversations and spec of fleet that you're running in Canada?

Yes, again, 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 you 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 -- might see rates dip down. But on a sustainable basis, the industry's behaved quite in a very responsible manner and a lot of -- 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, I mean, we've -- well we've both seen a commodity collapse in the past several years, so it's not a guarantee.

For sure. If you don't mind me violating the new 2 question rule and just talking on 2 other quick things. The first would just be on Saudi. You extended your contracts through year-end and mentioned that you're likely to extend into multiyear renewals. Does that just apply to -- in terms of the latter part, does that just apply to the 2 rigs that were extended through 2018 year-end? Or is that for all 3 of the rigs in terms of the long-term contracts being likely?

The third rig still has, I think, a 2- or 3-year -- a 3-year horizon on its contract. So it's not even close. They won't talk -- they usually don't talk about these renewals. So that rig is out for 3 years. The other 2 rigs that they 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 2 or 3 yet.

Okay. And just last one from me. I hear you're not wanting 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 a 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 a Trinidad shareholder, you're thinking of it more from a medium- to longer-term time horizon and the value that can be created through the combined entity? And that while you're not immune to the market gyrations, you're not just valuating it on a simple couple pennies below or above that premium when you think about the value for the shareholder.

I'd just kind of reiterate my comments earlier. I think the combined company creates excellent value for shareholders and all the combined company.

(Operator Instructions) Our next question comes from John Daniel of Simmons and Company.

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 will we see a repeat of this next year? Is there any initiatives going on right now, where you could see some sort of demonstrable improvement next year in the segment? Just your general thoughts on the various businesses within that segment.

John, that's a good question. We've spent all of about 45 seconds on it in my prepared comments today. And so a couple of things. In the first half of this year, you'll remember we brought on a new division leader who's 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 onetime costs to get the business kind lined up properly. In fact, in the third quarter, as Carey commented, our EBITDA year-over-year was about flat, Carey?

Up $400,000.

Up $400,000 on reduced revenue.

Right.

So I think he's done a great job repositioning the business. Assuming activity levels stay flat year-over-year, I'd expect us to perform better next year between better cost management, a thinner organization, a very -- a much more focused organization and improving pricing with customers who recognize that this business has to maintain the rigs.

Got it. You've talked long about the need for higher pricing there for all the various reasons. We know why workover needs higher pricing, but are your customers getting it?

We're seeing signs and we're seeing signs right across the boards they are getting it. And the price increases are not extreme. They're measured, they're careful, they're negotiated. But we're seeing it with all customers in all regions right now. And the industry as a whole, the mom-and-pops need it, the larger players like ourselves, the other public players need it. You can't run this business on $1 of EBITDA. You need to have enough EBITDA to pay the maintenance on the rigs and a little more. It's good to see some semblance of logic flowing into the space right now.

Our next question comes from Brad Handler of Jefferies.

My question is probably directed at Shuja. 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, that can actually control the curve build. 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 a scale and progress along the scale.

Brad, so there are 2 pieces of Directional Guidance System. One is the kind of algorithm, which is you need to go from Point A to B. What does it take and what sort of curvature or dog legs analogy it takes. Once you don't get there, you -- the software continuously computes and tells you what's the best way to land it, like pretty much landing a plane sort of thing, right? And I think that's really the software piece, which we are very comfortable with.

Now, there is the other piece of it, the software, is that really there is lots of different things DDs have been working on over 80 years I suppose and hiding in their tally books. So really, sometimes the algorithms are not the simplest of algorithm. So what you really need to get a very good 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 drilled 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 .001%. So I'm 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 hey look, the guidance system tells the driller, turn 90 degrees right and slide 10 feet. And the driller has to execute that. So that is the next step off 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 a story.

So I think I'll bet on a system for 2 reasons: one, you have lots of mileage, more mileage is better; and two, we have an internal directional drilling company, right, so that does bring that 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 is 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 that loop very quickly.

And Brad, I could add on to the comments here. I think this will 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, they'll connect the 2 and they'll do the closed loop drilling. I think it'll be us. I think it'll be any other drilling contractor that has either directional drilling capability, or software capability, or their own algorithm that they're running and marketing right now. And I think it'll become part of the next wave of technology on rigs, which is why we're pursuing it.

Our next question comes from Jeff Fetterly of Peters & Company.

Just 2 clarification questions. On the day rate side, last call you had talked 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 that were $500 to $1,000 a day year-over-year sequentially. And I think my comments for Q1 hinted in that same range for Q1. So again, year-over-year comparisons in Canada are 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 guidance this time. I still think thinking about rates stepping up quarter-over-quarter around $500 a quarter or maybe a little more is 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 or over the next couple of quarters?

Well, as I think I said earlier, the -- we still have a component of rigs in the Permian that are on well-to-well contracts, and I think those rigs have exposure. I did comment that I expect our rig count to 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 pull back. But I comment that 25 or 30 of those rigs are on well-to-well contracts, and if any given customer should decide to shut down on December 15, we could see our rig count soften up a little bit the end of the year. But I think it reenergizes come January 1 when we get into new budgets.

So the way you see it right now from a 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 prices are all over the map, depending on which day of the week you look at the 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 rigs come off late in December as people throw out 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. To see us 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 cost. I think we could -- we feel pretty confident saying that margins in the U.S. will increase somewhere between $750 and $1,000 a day. Some of that's going to 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 we're trying to get the best rates possible. We don't have quite as good of guidance on where the day rates are going. They're going up, but can't really give you guidance on the magnitude of that.

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

Yes, I wouldn't be surprised to see rigs start to move around a little bit. We've been focused on kind of even spread around all the basins. I think an example might be that if demand stays really strong in the Marcellus, we could see a rig or 2 move from maybe Mid-Con or Colorado to the Northeast.

Ladies and gentlemen, this concludes today's question-and-answer session. I would like to turn the call back to 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.