Precision Drilling - Earnings Call - Q3 2018
October 25, 2018
Transcript
Speaker 0
Good day, ladies and gentlemen, and welcome to the Precision Drilling Corporation twenty eighteen 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. 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.
Speaker 1
Thank you, Haley, and good afternoon, everyone. Welcome to Precision Drilling's third quarter twenty eighteen earnings conference call and webcast. Participating today on the call with me are Kevin Nevew, President and Chief Executive Officer Carey Ford, Senior Vice President and Chief Financial Officer and Shuja Ghoraya, Chief Technology Officer. Through our news release earlier today, Precision reported its third quarter twenty eighteen 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 Cary 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.
Speaker 2
Thank you, Ashley. Good afternoon. Well, 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 that Precision shareholders our plans to use excess cash to reduce debt will not be diminished or delayed due to this transaction. The transaction creates immediate cost synergies. We 'll continue to deliver long term margin enhancement and expanded scale.
The resulting increase in US 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 Exodus 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're proceeding with the necessary regulatory approvals and expect to file our shareholder circular document in the coming days.
Today, will not be answering any questions regarding the transaction in our Q and A session later in the call. You can refer to our website for more details on transaction. We'll continue to provide updates as new information develops. I'll now turn the call over to Carey.
Speaker 3
Thank you, Kevin. In addition to reviewing the third quarter results, I will demonstrate our progress on two of our three 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 $110,000,000 at the end of the third quarter. This is $45,000,000 higher than the cash balance 2008 and Precision has already reduced long term debt by over $75,000,000 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 $75,000,000 to $125,000,000 debt reduction guidance for 2018. Our 2018 financial performance continued to deliver annual improvement with third quarter revenue and adjusted EBITDA increasing 2211% respectively over the third quarter twenty seventeen. 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 twenty seventeen. 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 US, drilling activity for Precision increased 25% from Q3 twenty seventeen while margins were up approximately $800 per day, positively impacted by day rates that were up approximately $2,300 per day. The increase in day rates was offset by operating costs that increased approximately $1,500 US dollars per day. The increase in operating costs 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 $3,000,000 to $5,000,000 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 twenty seventeen and average day rates internationally were approximately US50000 per day in line with the prior year.
In our C and P division, adjusted EBITDA this quarter was 4,600,000.0 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 2017 due to an increase in our share based compensation accrual of $5500000.0.4000000 dollars of which was allocated to G and A to corporate G and A. Additionally, we incurred approximately $1,000,000 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 $29,000,000 and our 2018 capital plan remains $135,000,000 for the year. The 2018 capital plan is comprised of $52,000,000 for sustaining infrastructure, 71,000,000 for upgrade and expansion and $12,000,000 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 thirty three for the full year 2019. As of September 3038, our long term debt position net of cash is approximately $1,600,000,000 and our total liquidity position was approximately $800,000,000 For 2018, we would expect depreciation to be approximately $350,000,000 We would expect cash taxes to remain low and our effective tax rate to be in the 20% to 25% range. We'll continue to aggressively manage all fixed costs, including G and 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.
Speaker 4
Thank you, Carrie, and good afternoon, everyone. I am Shuja Gurayam. I joined Precision Drilling three months ago as Chief Technology Officer. Before Precision, I have around twenty four years of drilling experience working for one of the major oil field 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 driller's 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 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 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 partnership.
We are able to bring the best of industries, processes and algorithms by working closely with our third party developers, our customers, R and D team, universities, and few of the top oil field service companies. With our directional guidance system, we have drilled about 2,500,000 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 field harden this technology, and we are very confident that with this well tested stable software platform and our in house directional learning competencies, we have a robust directional guidance system.
Now I will hand the call over to Kevin.
Speaker 2
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 tenth 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.
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 breakup 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 United States, including one Canadian Super Triple we redeployed to Pennsylvania. We're seeing improved industry utilization, which is encouraging. 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 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 breakup. Customer indications also point to strong post breakup utilization to the 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 in 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 twenty nineteen 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 upgraded 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 United States, as our customers prepare for twenty nineteen 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 rates trending into the upper 20s and the terms now stretching from one to two years. We commented in 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 contract vintage.
For Precision's well to well rigs in the spot market, the pricing is similarly trending upwards for twelve hundred and fifteen hundred AC Super Triple rigs. All the rigs repriced during the quarter moved up in price ranging from a few $100 per day to several thousand dollars per day. With our current US activity at 80 this week, including seven rigs that have not worked since 2015, this is the highest utilization we reported since the twenty fourteen downturn. And our US 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 the Eagle Ford, Mid Con, Rockies, Bakken, Haynesville and 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 inter basin rig movement as the current demand in the Permian and Marcellus is the strongest, and that's 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 to open common sense of 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. It will deploy mid next year as planned. And Kuwait remains a very solid market for precision drilling internationally.
In Saudi Arabia, we continue to have three 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 four 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. We're meeting the challenge of staffing up service rigs for what is 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 that customers are beginning 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, the 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 of 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.
Speaker 0
Thank you. You. Our first question comes from James West of Evercore. Your line is now open.
Speaker 5
Hey, good afternoon guys.
Speaker 2
Hey, James.
Speaker 5
Hey, 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 I know you just signed some term contracts and you've done a lot of renewals, but at some point here, 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?
Speaker 2
James, I think even during the third quarter, we saw that we had a couple of our spot rigs put in the sidelines and activity was one or two rigs less during the third quarter. I think that's where you'll see customers manage their spending. But I think the sort of the industry drive and customer by customer preference for the most efficient rig is not going to slow down anytime soon. 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, you know, 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 predictable results. 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.
Speaker 5
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?
Speaker 2
You know, 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 So that's a very productive element right now in that Canadian basin. We're quite pleased with that. But it speaks to the deep basin where the, you know, 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, you know, that same drive for a highly efficient rig that they can hold on to and have guaranteed use throughout the year is very important. I think that's driving the contracting action.
Speaker 6
Great,
Speaker 2
thank you.
Speaker 0
You. Our next question comes from Taylor Lercher of Tudor Pickering and Holt. Starting
Speaker 7
on The U. S. Side, just wanted to clarify a bit the rig reactivations for some of the rig upgrades you've been doing. And you called out 3,000,000 to $5,000,000 of sort of reactivation costs. So as we look ahead, 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 I just wanted to clarify why those rig reactivation costs might not show up, certainly not in Q4 but maybe out in Q1 or 2019?
Speaker 3
Hi Taylor, it's Kerry. So just to remind the listeners, we have guided to rig reactivations costing 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, you know, it was a group of rigs that hadn't worked in several years.
The rigs that we would be reactivating in 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 3,000,000 to $5,000,000 bucket which kind of equates to about $400 to $700 per day. We don't expect to be present in the Q4 numbers.
Speaker 7
Okay, got it. That's helpful. And then on the Canadian side, a follow-up to a prior question around the contracts you signed. In The U. S, it sounds like you're getting 25 or north of $25,000 a day for the higher rigs for the Super Triple ACs in Canada.
Could you remind us where the leading edge pricing is for that asset class today?
Speaker 2
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 very small population of 1500s in Canada. For the 1200s, it's going to be low 20s.
Speaker 7
Okay, got it. That's it for me. Thanks guys.
Speaker 3
Thank you.
Speaker 0
Thank you. Our next question comes from J. B. Lowe of Citigroup. Your line is open.
Speaker 2
Hey, 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 of late September, but really it's been a Q4 activation less than Q3.
Speaker 3
Yes, and I'll just add to that. On our call, Q2 call last quarter, we mentioned that we had 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 lower spec rigs that were working on well to well contracts. Both of those happened. So we had our rig count troughed to about 74 rigs during the quarter.
It's gotten back up to 80 rigs. And the next four 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.
Speaker 2
And what would you say your average kind of day rate on your contracted U. S. Fleet is right now?
Speaker 8
I'm just trying to think
Speaker 2
of day rates can move as contracts keep rolling. So you know, 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 getting back to '16, some of '17, and some in early eighteen, and now more of course in mid to late eighteen. On the contracted rigs, the average price is lagging the spot market still.
Got you. All right, thanks. Good, thank you.
Speaker 0
Thank you. Our next question comes from Kurt Hallead of RBC. Your line is open.
Speaker 2
Hi, afternoon.
Speaker 9
Hey, sorry, had it on mute. Good afternoon. How's everybody?
Speaker 2
Good, good.
Speaker 9
All right, excellent. Hey, so 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, you know, can you talk to the commercial elements of these applications?
Speaker 2
Yeah, we do have some Kurt, I'll try to give you some clarity there. You know, we haven't gotten into our full 2019 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 rig. 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've said in the past that of the 21 units we had prior to this quarter that about a third we had customers paying the full ticket and some were paying a reduced amount and some were 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 rates likely in the 75% to 80% range by the end of the year.
Speaker 9
Okay, great.
Speaker 2
And then if you know, if 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 laid out the plan for next year. I also expect we'll start getting app revenue in 2019. And, you know, initially one or two apps per rig, but that could mature into three or four 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 expect revenue to start coming in, in 2019.
Speaker 9
Thanks 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?
Speaker 2
Yeah, we've been on the apps, there's really two 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 in 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.
Speaker 9
Right. That's great. And then Nate, 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?
Speaker 3
Yes. Nothing has changed on that front, Kurt. We have our upgrade plan 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 $3,000,000 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 $2,000,000 $3,000,000 We would get a bump of call it $4,000 a day in day rate and recoup that back within eighteen months. 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.
So we'll be looking for higher day rates and longer contracts to make sure that we get the majority of that contract recouped, the majority of the investment recouped.
Speaker 10
Thanks Kerry. That's great.
Speaker 3
Thank Thanks Drew.
Speaker 0
Thank you. Our next question comes from Ian Gillies of GMP. Your line is open.
Speaker 2
Good afternoon, everyone. Hey, Ian. With respect to the 80 rigs that
Speaker 11
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?
Speaker 2
Ian, short answer is some of those rigs will get upgraded even in our current program, some may be upgraded next year, still under that $3,000,000 mark. Not every one of those rigs has a pad walking system, not every single rig has three mud pumps. So, you know, if the demand stays strong in the Permian for three mud pump pad walking rigs, there could be a handful of additional 1,000,000 or $2,000,000 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 Kerry 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, you know, I think we could envision a rig count in 2019 that gets into the high eighties with our current fleet through upgrades and some redeployments.
Speaker 11
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 much as you would have hoped?
Speaker 2
There's still a lot of sort of broad market uncertainty in Canada. And, you know, while Super Triple rigs are excellent rigs, there's still a little bit of kind of at the edge heavy teledouble competition going on in Canada. So, you know, pricing power is still generally evasive in Canada. But I would tell you, 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.
Speaker 11
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 you think you may like to do?
Speaker 3
Yes, I think we covered that in our prepared comments and in the press release. We paid down $77,000,000 so far this year. We plan to get above or into the higher end of our debt repayment range. So think of something over $100,000,000 by the end of the year.
Speaker 11
Okay, thank you.
Speaker 2
Yeah, 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.
Speaker 11
Okay, thanks very much guys. I'll turn the call back over.
Speaker 2
Thanks Ian.
Speaker 0
Thank you. Our next question comes from Connor Lynagh of Morgan Stanley. Your line is open.
Speaker 6
Yes, thanks. Good afternoon.
Speaker 2
Hey, Connor.
Speaker 6
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 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?
Speaker 2
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 earlier.
Today we have 22 of those rigs working. We expect a fairly even increase through early December to get all 27 AC rigs working. There'll likely be a bit of a break between Christmas and New Year's like there is typically. Then we think that on January 1, all 27 rigs are working right through breakup, whenever breakup happens. We see strong customer interest.
Some of those rigs will run through breakup. You know, you could expect that maybe a third or so of them will run straight through breakup. 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 in the back half of next year because the target for those rigs is a commodity you can't easily see. It's the Canadian, you know, 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 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 shallow replace, Canadian Viking, Saskatchewan, Southern Saskatchewan, and Sean O'Mearfield and Cardium. Is that helpful?
Speaker 6
Yes, that's helpful. Yes, I appreciate it. 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 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 300,000,000 to $500,000,000 range is pretty conservative at this point based on where The U. S. Market is and where you'll be in international markets. Obviously Canada is a risk, it sounds like your highest calorie rigs are going to be working pretty much regardless. So just any thoughts on that?
Speaker 3
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 good 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 four year three or four year period of 300 to $500,000,000 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.
Speaker 6
That's fair. I mean, I guess, let me know if you can't answer this, does the addition of additional rigs to the acquisition change how you think about that target at all or not yet?
Speaker 3
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.
Speaker 2
And we didn't give any guidance about increasing those targets, but I can assure you we would not decrease the targets.
Speaker 6
Fair enough. Thanks a lot.
Speaker 2
Great. Thank you.
Speaker 0
Thank you. Our next question comes from Sean Meakim of JPMorgan. Your line is now open.
Speaker 12
Thanks. Hey guys.
Speaker 2
Hi Sean.
Speaker 12
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?
Speaker 2
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 SCOOPSTACK is stable. And I think we've had a little less attention than 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.
Speaker 12
Okay, got it. Thank you. 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 some of the 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'd be great just to get a little more details on those moving pieces.
Speaker 2
Sean, things have gotten actually a little bit cloudier over the last few weeks. Think there's some turmoil right now. Certainly the news every day 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, our other core market, 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 twenty nineteen, probably twenty twenty 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 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, you know, 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 what those develop if we can early in the New Year. Nothing will happen this year. I don't expect any announcements prior to the end of the year.
Speaker 12
Got it. That's very helpful feedback. Thanks, Kevin.
Speaker 2
Thank you.
Speaker 0
Thank you. Our next question comes from John Morrison of CIBC Capital Markets. Your line is now open.
Speaker 3
Afternoon all. Hey, John. Hey, John.
Speaker 8
Kevin, just a point of clarification. You messaged that PRECISION's ED 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 twenty nineteen ex the obvious Christmas noise, even if you saw some form of a decent downdraft in the Permian in half one, say 5% or 10%, you still think you should be fairly immune to those headwinds.
Is that fair?
Speaker 2
I don't have the numbers in front of me right now, John. 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. You know, 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 will say for sure though is that we're at these day rates right now, we're actively pursuing contracting every one of our high spec rigs. We're, you know, day rates that are north of 25,000 of rigs that will lock 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, you know, a 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 a pipeline up in June, chances are you probably want to have three or four or five pads drilled and completion starting in q two. So as wells are completed and flowing at the beginning of q three, the pipeline comes on. So, you know, lot of discussion around inventory of drilled and completed wells, while it's a big issue and industry issue for pressure pumping, for drilling, it's part of the normal planning sequence. And, you know, the most efficient rigs right now aren't really impacted by more or less ducts coming up or going down.
So I've answered three or four questions there. Short answer is, we feel pretty good about the contract rigs. 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 we're in for a Q1, Q2 a bit like last year where rig counts move up if commodity prices stay strong.
And I don't think, you know, a single digit or a low double digit differential to the Permian will slow that down.
Speaker 8
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 one day rates based on your current bookings, customer conversations and spec of fleet that you're running in Canada?
Speaker 2
Yeah, again, short answer there, I'll go yes. I think the drillers in general are behaving in Canada very disciplined. And you know, 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 you know, very short periods, we see rates dip down. But on a sustainable basis, the industry has 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 complete commodity collapse, I think rates are not at risk next year. But we've both seen a commodity collapse in the past several years, so it's not a guarantee.
Speaker 8
For sure. If you don't mind me violating the new two question rule and just poking on two 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 two rigs that were extended through twenty eighteen year end?
Or is that for all three of the rigs in terms of the long term contracts being likely?
Speaker 2
Oh, the third rig still has I think a two or three year horizon on its contract. So it's not even close. They won't talk they usually don't talk about these renewables. So that rig is out for three years. The other two rigs that they extended through the end of the year, before the December, those will be extended out for more years.
I don't know if it's going be two or three years.
Speaker 8
Okay. And just last one for me. I hear you are 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 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 evaluating it on a simple couple pennies below or above that premium when you think about the value for the shareholder?
Speaker 2
You know what, trying to reiterate my comments earlier, think the combined company creates excellent value for shareholders that own the combined company. Okay. Appreciate the color. I'll turn it back. Thank you.
Speaker 0
Thank you. Our next question comes from John Daniel of Simmons and Company. Your line is now open.
Speaker 13
Hey guys. 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, which where you could see some sort of demonstrable improvement next year in segment?
Just your general thoughts on the various businesses within that segment?
Speaker 2
John, that's a good question. We've spent all of about forty five seconds out of 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 of lined up properly.
In fact, in the third quarter, as Carey commented, our EBITDA year over year was about flat Carey?
Speaker 3
It was up $400,000
Speaker 2
Up $400,000 on reduced revenue. 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, thinner organization, a very much more focused organization, and improving pricing with customers who recognize that this business has to maintain the rigs.
Speaker 13
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?
Speaker 2
We're seeing signs. We're seeing signs right across the board that they're getting it. And the price increases are not extreme. They're measured, they're careful, they're negotiated. We're seeing it with all customers, all regions right now.
And the industry as a whole, you know, 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 of the rigs and a little more.
Speaker 13
Totally. Okay. Thanks, Kevin.
Speaker 2
It's good to see some semblance of logic flowing into the space right now.
Speaker 10
It's needed. Thank you. Thank you.
Speaker 0
Thank you. Our next question comes from Brad Handler of Jefferies. Your line is now open.
Speaker 10
Thanks. Hello everybody.
Speaker 2
My
Speaker 10
question is probably directed 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 it's a fully automated 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 scale and progress along the scale.
Speaker 4
Hi Brad. So there are two pieces of directional guidance system. One is the Kaina algorithm which says you need to go from point A to B. What does it take and what sort of curvature or dog lexularity it takes? Once you don't get there, software continuously computes and tells you what's the best way to land it.
Right? Pretty much landing a plane sort of thing. Right?
Speaker 14
Mhmm.
Speaker 4
And I think that's really the software piece which we are very comfortable with. Now there is the, you know, the other piece of it, the software is that really there is lots of different things DDs have been working on over eighty years, I suppose, and hiding in their telly books. So really sometimes the algorithms are not the simplest of algorithms. 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 2,500,000 feet or drilled 2,500,000 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 point 001%. So I'm very comfortable that as we deploy more, as we get more, you know, mileage on it, this is what we cover. Then the next piece of it is, hey. Look.
The guidance system tells the driller, you know, 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, you know, 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 two reasons. One, you have lots of mileage. More mileage is better. Two, you know, we have an internal directional drilling company. Right?
So that does bring that internal competence whereby you can actually, you know, directionally drill these things. So I think that's another critical part of it.
Speaker 2
That should help you develop it
Speaker 10
faster essentially, right? That's just gonna help you develop a more robust and perhaps develop it faster as having that internal capability?
Speaker 4
Yes, and I think eventually you need to make sure that you learn very quickly from early mistakes. It's 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.
Speaker 2
And Brad, I'd kind of add on to the comments here. I think this will become the domain of the drilling contractor. I think it'll be the drilling contractor that will have the steering advisory software, the automation software they'll connect the two, 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 RICs, which is why we're pursuing it.
Speaker 10
Yes, I that makes a ton of sense. Yes, and I just appreciated the timeline and sort of the update. Okay, very good. Thank you. I'll turn it back.
Speaker 2
Thank you.
Speaker 0
Thank you. Our next question comes from Jeff Fetterly of Peters and Company. Your line is now open.
Speaker 14
Thanks. Just two 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?
Speaker 2
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 entered in that same range for Q1. So again, year over year comparisons in Canada looking like somewhere between 500 and maybe 1,000, probably not to exceed 1,000 on average. In The US, 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 as a reasonable expectation going forward.
Speaker 14
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?
Speaker 2
Well, think I said earlier, the, you know, we still have a component of rigs in the Permian that are 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, you know, 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, you 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 get into new budgets.
Speaker 14
So the way you see it right now from a US standpoint or from a Permian standpoint, 80 rigs or 41 rigs is about the base level?
Speaker 2
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 which day of the week you look at the strip. But you know, again, talking to our customers, think 80 rigs modestly moving up a little bit. I wouldn't be surprised to see a couple of rigs come off late in December as people throttle out spending by the end of the year. But then expect to see those rigs come back, you know, come January 1 and be moving kind of without any interruption from wherever we finish off the peak.
You know, just to see us sitting in the low 80s in January is not a stretch.
Speaker 3
And Jeff, just to round out some of the guidance we gave earlier on cost, I think we feel pretty confident saying that margins in The US will increase somewhere between $750 and $1,000 a day. Some of that's gonna be cost reduction. Some of that, likely day rate increases. But we've just had as you you followed the story, we've just had a lot of rigs go back go back to work. We're recontracting rigs.
We're trying to get the best rates possible. We don't have quite as good of guidance on, on where the day rates are going. They're going up, but can't really give you guidance on the magnitude of that.
Speaker 14
And just to make sure I heard correctly earlier, you talked about in terms of migration or rig moves within The U. Some potential for rigs to move into the Marcellus and into the Permian, correct?
Speaker 2
Yeah, 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 two move from maybe Mid Con or Colorado to the Northeast.
Speaker 14
Okay, great. Thank you. Appreciate the clarity.
Speaker 2
Great, thank you.
Speaker 0
Thank you. 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.
Speaker 1
Thank you all for joining today's call and look forward to speaking with you when we report 2018 in February. Thank you.
Speaker 0
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.