Precision Drilling Corp (PDS) 2017 Q3 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to the Precision Drilling Corporation 2017 Third Quarter Results Conference Call and Webcast. (Operator Instructions) And as a reminder, this conference call is being recorded.

I would now like to introduce your host for today's conference, Ms. Ashley Connolly, Manager of Investor Relations. Ma'am, you may begin.

Thank you, Sandra, and good afternoon, everyone. Welcome to Precision Drilling's Third Quarter 2017 Earnings Conference Call and Webcast. Participating on the call with me today are Kevin Neveu, President and Chief Executive Officer; and Carey Ford, Senior Vice President and Chief Financial Officer.

Through our news release earlier today, Precision reported its third quarter 2017 results. Please note that these financial figures are in Canadian dollars, unless otherwise indicated. Some of our comments today will refer to non-IFRS financial measures, such as EBITDA and operating earnings. Please see our news release for additional disclosure on these financial measures.

Our comments today will include forward-looking statements regarding Precision's future results and prospects. We caution you that these forward-looking statements are subject to a number of known and unknown risks and uncertainties that could cause actual results to differ materially from our expectations. Please see our news release and other regulatory filings for more information on forward-looking statements and these risk factors. Carey will begin today's call with a brief discussion of our third quarter operating results and provide a financial overview. Kevin will then provide an operational update and outlook.

Before I turn it over to Carey, I want to make note of our 3 strategic priorities for 2017: deliver high-performance, high-value service offerings in an improving demand environment, while demonstrating fixed cost leverage; maintain strict financial discipline and pursuing growth opportunities with a focus on free cash flow and debt reduction; and, lastly, commercialized rig automation and efficiency-driven technologies across our Super Series fleet. We will touch on our progress year-to-date for each of these initiatives throughout today's call.

With that, I'll turn it over to you, Carey.

Thank you, Ashley. In addition to reviewing the third quarter results, I will provide an update on our 20,000 -- 2017 capital plan and our liquidity position.

Third quarter adjusted EBITDA was $73 million, which is 77% higher than the third quarter of 2016. The increase in adjusted EBITDA from last year is primarily the result of higher activity levels across all our businesses, lower North American operating cost and higher day rates internationally.

As you may have noticed, we introduced some changes to the treatment of certain items that were historically netted against operating expenses. These are now treated as revenue, impacting revenue and operating expense, particularly in our Canadian drilling segment, but having no impact on EBITDA or profitability.

The audience today is likely particularly interested in the impact on current and historical day rates and operating costs. We have provided a detailed schedule of the recast figures in our press release.

In Canada, drilling activity for Precision increased 57% from Q3 2016, while margins were $615 per day lower than prior year. The margins for the quarter were negatively impacted by legacy contracts rolling off and renewing at lower rates, offset by lower daily operating costs that were $451 per day lower than prior year.

In the U.S., drilling activity for Precision increased 108% from Q3 2016, while margins were USD 2,452 per day lower. Absent the IBC payments and lump sum move cost realized in Q3 2016, margins this quarter were essentially flat year-over-year with daily operating cost reaching a multiyear low averaging $12,591.

Internationally, drilling activity for Precision increased 15% from Q3 2016. The increase in activity was primarily the result of the addition of 2 new rigs in Kuwait deployed in Q4 2016, partially offset by a reduction in activity in our Mexico operations. International average day rates were $50,528, an increase of USD 6,649 from the prior year. The increase was largely the result of rig mix. Today, we have 8 rigs active internationally.

In our C&P division, adjusted EBITDA this quarter was $4,251,000, up approximately $3.5 million from the prior year. The increase is a result of significantly higher activity and a lower operating cost structure across all segments.

Capital expenditures for the quarter were $23 million, and we now plan on capital expenditures of $104 million for the full year 2017. The 2017 capital plan is comprised of $13 million for expansion, $52 million for maintenance and infrastructure and $39 million for upgrades. We have been able to reduce our capital plan to align with activity and have realized lower dollar cost per upgrade. We now plan to complete approximately 30 upgrades in 2017 at approximately $1.3 million per rig. The lower dollar amount per rig is a result of our Super Triple rig design, allowing for bolt-on upgrades for capacity increases, process automation control technology and walking systems as well as lower production cost and a slight benefit from foreign exchange throughout the year. The maintenance and infrastructure capital portion includes the ongoing upgrade of our ERP system, which is on schedule and on budget.

We have continued to build our contract book, and as of September 30, 2017, we had an average of 48 contracts in hand for the fourth quarter and an average of 26 contracts for full year 2018. Year-to-date, we have added 22 term contracts.

As of September 30, 2017, our long-term debt is $1.78 billion and our net debt is $1.64 billion.

We had $132 million in cash on our balance sheet at the end of the quarter, and as of September 30, our total liquidity position was $859 million.

As mentioned earlier, 2 of our strategic priorities for the year are to demonstrate fixed cost leverage in an increasing activity environment and focusing on free cash flow and debt reduction. We have delivered significant activity increases year-to-date in all our business lines, and salary and headcount has remained essentially flat. In the first 9 months of the year, we generated funds from operations of $156 million, and we continue to view reducing debt levels as a priority, and intend to use free cash flow and cash on the balance sheet to delever over the next several years.

I will now turn the call over to Kevin for a further discussion of the business and outlook.

Thank you, Carey, and good afternoon. The third quarter for Precision is shaping up to be a turning point, as we reported both year-over-year and sequential increases in revenue, EBITDA and cash for the first time since 2015. And despite lower-than-expected commodity prices for WTI and AECO gas in Canada, demand has remained strong for our Super Triple long reach pad rigs. Day rates remained firm. While we've experienced a slight pullback in utilization later in the third quarter, we expect strengthening demand from customers as we progress towards 2018.

Now with our capital spending largely complete for the year and improving day rates and margins in North American markets, coupled with firm international cash flow, we're anticipating a solid runway of free cash flow for the foreseeable future.

As Ashley reminded investors earlier, our stated priorities for this year include: a focus on free cash flow and debt reduction; leveraging our fixed costs; and commercially -- commercializing our drilling automation technologies. And this quarter, we're reporting strong progress in all 3 priorities.

So beginning with our $39 million reduction in capital spending, this is a very important step as we focus on debt reduction. Now besides Carey's comments related to the bolt-on nature of our upgrades, we further leveraged our in-house manufacturing facilities in Calgary and utilized batch production techniques to prefabricate these upgrades and the components, we have significantly reduced the cost for each rig upgrade. Additionally, we have created inventory in parts for about 2 to 3 more rig upgrades that we can execute later in the year with essentially no additional cash requirements.

And finally, our partnership arrangements for technology development have lowered our expected technology spending as we continue the beta testing and improve these technologies.

So the strong execution demonstrated by our manufacturing and operations team should not surprise anyone as Precision's culture of high-performance execution is evident with all employees. Our people are managing every expense, every cost and every activity. They've executing our business with excellence and, as a result, delivering on our expectation of fixed cost leverage. The results are clearly evident in funds from operations, up $53 million year-over-year and $100 million sequentially, providing the cash flow tailwinds as we seek to reduce debt over the coming quarters.

So moving on to our third strategic focus regarding commercializing technology. This is very important because it provides an opportunity for revenue growth, even with larger declining markets. So today, we have 20 rigs of NOVOS drilling automation systems installed. We drilled 70 wells utilizing this technology. We experienced a slight interruption in the third quarter related to software updates and testing delayed by the Harvey flood events in Houston. So our hearts go out to all those affected by Harvey throughout the Houston Gulf Coast area, and I remain amazed by the resilience of the people of Houston and Gulf Coast, and particularly the Precision team in Texas with 6 rigs operating in the hurricane zone and almost 1,000 employees living in the region, Precision did not miss a beat.

And other than the software delays I mentioned, we report no other corporate or operational impacts due to the hurricane. Now I wish I could say the same for our people, our hearts go out to 72 Precision employees, their families and hundreds of thousands of Gulf Coast residents who suffered significant damage, loss and dislocation as a result of Harvey.

Now moving back to our field implementation. The results we're delivering with this NOVOS automation system continue on track. We're improving system uptime. We're delivering consistency, repeatability and, of course, we're demonstrating the key metric of improved drilling efficiency. We're running this technology on 20 rigs with 14 different customers in 5 basins. And as I said earlier, we drilled 70 wells. Notably, we have 10 rigs operating in the Permian Basin with this technology.

We believe we remain on track to finish this beta program later this year. And as we've seen it before, we expect the technology will generate a 5% to 8% reduction in drilling time for our customers and create an incremental revenue stream for Precision, while enhancing market share and the competitive advantage of our Super Series rigs.

So through 2017, Precision has been focused on improving cash flow, and day rate increases have been a top focus for our sales team. This strategy is critically important as rates last year were simply too low to sustain a healthy industry. And we fundamentally believe that the efficiency gains we've delivered to our customers must generate positive returns for us. During the third quarter, we continued to press rates upward for every rig class in every region. Also, we expect upgrade investments that we make to be fully funded by incremental day rate increases, and that those investments are covered and backed by contracts with sufficient terms to pay up those investments. We are simply not interested in deploying capital, unless we achieve our expected returns and enough contract backing.

Now with our customers, there remains a high degree of price sensitivity and we expect that at times, we'll see customer push back and market share impacts. We're less troubled than some by temporary market share losses, as we remain keenly focused on improving total cash flow, while demonstrating rig performance and efficiency to our customers.

So looking across our U.S. fleet. We continue to book pad walking, long reach ST-1500 at day rates in the low 20s with new contracts signed as recently as just a few days ago. Our single-well configured ST-1500s are generating rates in the high teens as our ST-1200s. These rates apply to both our term contract renewals and our well-to-well rigs. As such, we expect fleet average rates and margins to continue to increase as rigs reprice. During the third quarter, customers indicated less desire to lock in long-term contract obligations. But as we approach 2018, that sentiment is improving. And as we mentioned in the press release, we've finalized 3 long-term contracts since the end of the third quarter.

In Canada, and particularly Alberta, natural gas pricing, and that's driven by the AECO quote, has been deeply distressed by seasonal midstream shutdowns and maintenance, and this has proven a drag in the customer cash flows and resulted in slowing customer demand. That said, our activity achieved over 90% of our expectations. And more importantly, we're sustaining our rates for our Deep Basin Super Triple rigs, while pressing meaningful rate increases on our shallower rigs.

Now you may recall, the last winter of Precision and the industry underestimated the Canadian winter activity, and we were stuck with unacceptably lower rates and, particularly, for the shallower rigs. Though we understand that the customers in Canada are very price sensitive, but we firmly believe the industry needs somewhat better rates to ensure the long-term health and responsive operational capability our industry provides, and Precision is doing its part to support this recovery.

Outlook for -- on 2018 is firmly up, as our customers are well into the 2018 budgeting process. And with global oil supply and demand fundamentals tightening and continued OPEC focus on supply management, the strengthening oil price is coming at a very important time. And as I mentioned earlier, we have good signs of improving rig demand with confirmed rig activations over the coming days and weeks, and further rig deployments confirmed into the first quarter of 2018. We would expect Precision's U.S. activity to return to peak 2017 levels later this year and strengthen further during the first quarter of 2018.

Now as of yet, production -- producer budgets have not yet been set, but we do know their intense focus on efficiency will remain, and Precision's utilization will grow via market share with our pad walking Super Triple leading the way. Specifically, we expect customer demand in rig high-grading will remain a priority for our customers in the Permian, the Mid-Continent, the Marcellus, the Niobrara. And we believe that Precision is well positioned in all of these regions.

In Canada, we expect the Deep Basin activity will stay firm into 2018, but we're also expecting a resurgence in heavy oil activity, which will be a beneficiary of the depressed AECO prices. Our market position in oil sands is strong. And with the rate improvements I mentioned earlier, we expect a good winter result in oil sands areas.

Now in all of these markets, it's clear that our customers are intensely sensitive to commodity prices. And those with stronger hedge books will function with their stability, but there's no question that our industry remains willing to respond quickly to either stronger or more challenged macro environment. At Precision, we're poised to meet the demand. We'll accordingly adjust our business. We have aggressively managed our cost through this now 3-year downturn. We're positioned with new and highly relevant Super Series rig fleet, generating strong cash flows. We're demonstrating improved utilization and with minimal capital needs going forward. We expect a good runway to improve our capital structure as we continue to increase competitive offerings with new automation technologies.

So close out by recognizing all the Precision employees who continue to execute our business with confidence and control, and especially those in the Houston and Gulf Coast region who endured Harvey. Thank you.

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

(Operator Instructions) Our first question comes from the line of Sean Meakim with JPMorgan.

So maybe to start off on the technology front and some of the inroads that you're making there. Can you maybe give us a little bit sense of how you see the timing for commercialization in '18? And you talked about, in terms of in the marketplace for your rigs, being willing to walk away from market share. Do you feel like the economics are not appropriate? But in terms of the technology uplift here, are you able to see line of sight to how that can help you win share over the next several quarters?

Sean, the short answer is yes. I think we have line of sight to how we can win share. The performance of the rigs right now running the automation software is looking very, very good. And the data that we've demonstrated back at our investor day back in May, we were repeating on multiple rigs. We've been increasing uptime for the systems. So we're pretty encouraged. We have hard-to-find metrics that we have to achieve what we call commercialization. And our board solely is accountable to those. I think we're on track to complete this project, either by the end of this year or very early into Q1 next year, just depends on the delays we mentioned on the software. But it's coming along well. So I think the efficiency gains are measurable. They're real. Our customers are seeing it. We have some customers right now that are paying -- actually paying us whole rate. We've got other customers right now that are working on kind of performance-based metrics. But I can tell you, there was no pushback from our client base right now based on the performance. So we're very encouraged by that. Is that helpful?

It is helpful. And for those customers, are they all using the same suite in terms of the Process Automation Control? Are there -- or people taking and shooting certain components? How does that look among the 20 rigs?

Sean, on the Process Automation Control, we're running one version on all the rigs, all the same. We're trying to keep that -- the number of variables and systems controllable, so we can compare rig 1 to rig 20. So same operation dates. We did -- there's a couple of things that are actually really key here. We're running multiple tests. We've got, I think we said, 14 or 15 different customers that are running the software, 20 rigs spread among 5 different basins. But it's exactly the same hardware, same software, and that's really critical, so we can capture repeatable results. And having multiple tests running concurrently, but using the same platform is really important to our test and helps us get that guarantee of consistency and time savings going forward.

That's very helpful. And one more question, if I could. Just -- you mentioned one of your key focuses this year and in the next year is going to be on free cash flow. Curious as your latest thoughts about line of sight for the large tenders in the Middle East. It seemed like the one in Kuwait is the one that's at least most promising. Timing is always very difficult for any of these. How are you thinking about balancing, obviously, need for free cash? But if you're able to secure some of those types of contracts, particularly because of new build component, a stream of good -- long-term contracts with a good stream of cash flows attached to this might be pretty attractive. So just curious how you're thinking about those types of capital allocation decisions.

Well, Sean, I'll be clear. So we have active bids in lots of places. I don't want to discuss a specific bid. But our preference today and our preference going forward is our first use of free cash is to pay down debt.

And our next question comes from the line of Ben Owens with RBC Capital.

Kevin, so you mentioned you expect your rig count in the U.S. return to peak 2017 levels later this year, which, I think, was around 63 rigs or so. Is that based on contracts you have in hand? Or is that more of a general comment on how you view the state of the market?

So we have rig deployments scheduled between now and the end of the year that, we think, gets us back to that number.

Okay. And then sticking with the U.S. It looks like your daily cash margin has benefited quite a bit from a reduction in operating cost. Do you think the third quarter level is sustainable going forward?

Ben, this is Carey. I think this quarter really shows what the business can do. But remember, we did not have any turnkey revenue this quarter, and we did not have any regional rig moves and that will add some variability to the operating cost. But there weren't any onetime items that drove that cost lower.

And our next question comes from the line of Chase Mulvehill with Wolfe Research.

So I guess, first one, thinking about U.S. land drilling, really nice quarter on the operating cost there. As we go into 3 -- or go into 4Q, how should we be thinking about kind of OpEx per day? Should it be kind of flat? Or should we kind of take that higher as we get into 4Q?

Yes. So as I just mentioned, I think that the business performed really well this quarter and really showed that's a true operating cost with the business firing on all cylinders. But we didn't have any turnkey revenue, which is typically an -- adds to operating cost. And we don't have any regional rig moves. So it was a very good quarter for operating cost, but there is typically more variability in the cost number quarter-to-quarter.

Okay. So the rig, I think you said, that you see line of sight for 5 rigs. Are those within the same basin? Are you going to have rig moves out of basin?

So I said -- I didn't say the number. Actually, I said I saw line of sight to get back to our peak levels. Your math is close, but not quite right on. But I don't expect at this point that we have any rig moves coming up. But that could change. Customers change plans, and we may end up activating different rigs sooner. But nothing on the horizon right now, Chase.

Okay. All right. Also on 4Q, could you talk to kind of how you see rig mix playing out in Canada between the shallow and deep rigs? And then maybe -- I don't know if you want to talk at a high level about pricing in Canada through the winter drilling season.

Yes. I think activity on the Deep Basin were pretty close to last winter. We said, I think, on my comments, if you're going over it, I said flat or in line with 2017. We think that the heavy oil regions could be a little busier than last winter. And that, combined with our rate increases on the shallower rigs, should be helpful. Now we're right in the middle of pricing rigs for the winter, and our competition is listening to this call. And I don't want to give specific guidance on what we're doing with our rigs, but we are pushing them up on the shallower rigs. And that hits everything outside the Deep Basin in Canada. And we did that and we pressed hard earlier this year. We lost a little bit of market share in Canada because of that. But I feel good about our positioning for the winter. And I think we said in the press release we expect activity levels to be in line with 2017.

It's hard for us to understand kind of high-spec rigs in Canada and what utilization looks like. So if we kind of look at Tier 1, super-spec type rigs that we call them in the U.S., what kind of utilization do you think that has during the winter season?

I think last winter, we had about 35 rigs and we kept that category in Canada running during winter.

And (inaudible) you think it is -- I mean (inaudible).

So our market share of that base would be a little bit over 30%, probably 35%, less than 100 rigs.

Yes. Chase, the utilization on that fleet segment in Q4 and Q1 will be pretty close to 100%.

Okay. So why are you not able to push pricing more? Why are you not able to get to closer to kind of new build economics? I mean, in the U.S., everybody will upgrade a rig if you get there, so that kind of caps pricing. But I'm just kind of curious why you don't see more pricing momentum in Canada.

So that -- Chase, that's a really good question, a great question for people who aren't in the market daily like we are. The short answer is that the -- there's a rig spec in Canada called the heavy Tele-Double, which can kind of nibble at the bottom or the shallower applications on the Super Triples. And our customers are quite good at gaming that rig against Super Triples. So it doesn't cap the pricing, but it does cause a bit of a drag on pricing. And the other problem with Canada is it's so seasonal right now. It's so sensitive to this AECO gas price that it's really hard to understand what might happen in the back half of the year. It appears as though budgets may be flat to slightly up, but just -- it's really, really hard to tell. I can tell you the last year, the problem on pricing wasn't so much on the Super Triples. It was really on the shallower rigs that were underpriced in the winter last year.

Okay. That's helpful. Appreciate the color. I'm going to squeeze one in if you'll allow me one more. On the debt side, I mean, you had some nice debt reduction in the quarter. It's a big focus of the company. And so could you talk about maybe targeted leverage ratios or maybe targeted net debt and your path to kind of getting to those levels?

Yes. I think we're looking at this over a 3- to 4-year time horizon. As a reminder, our next maturity is November 2020, so we've got about 3 years until we have our first principal payment. And we really don't have a metric that we're gearing towards. But we have communicated that we would like to reduce our debt by $300 million to $500 million over the next 3 to 4 years. And we think we can do that entirely out of cash flow from operation.

And our next question comes from the line of Jim Wicklund with Crédit Suisse.

Usually, when somebody cuts their CapEx, which you guys are doing, your CapEx going forward, it's because there is not as much growth has been expected. Now I appreciate that you're more efficient, reduced input costs. I'm just curious. Do you see fewer opportunities for CapEx -- growth CapEx in '18? Or have you just gotten so efficient that you can shave $39 million off and still have the same trajectory?

Jim, there's several moving pieces there. But they -- I think one of the key numbers you can kind of relate back to is we estimated at the beginning of the year, I think, 3 weeks of 39 upgrades.

Yes, 35.

35 upgrades. We actually booked in 30 upgrades, so the 5-year upgrades that we might have talked about earlier this year. I would say there's strong willingness on the customer front to accept the day rates that we were looking for. There's lots of willingness in the third quarter to sign up for the term we wanted. But you'll remember that at Precision, we're a little different. We have to use the incremental value of the day rate to fund the upgrade. So we can't use whole margin on the rig, just the incremental margin above the opportunity cost of the rig. We have to get a contract that will pay that incremental value back on the upgrade inside the contract life. And the issue during the third quarter was a reluctance of customers and a $42 oil price world to walk in for a year or longer at these premium day rates. The rate wasn't the problem. It was the term of the contract in Q3. That's why we reduced the numbers slightly.

Okay. Okay. And how much -- remind me, how much you're spending for rig upgrade?

Right now, it's about $1.3 million.

Okay. $1.3 million times 5. Okay.

That $1.3 million number is lower than we guided to earlier this year because of the cost savings.

Good.

And Jim, just to add to what Kevin said. So we typically segment our capital expenditures in 3 buckets. We have managed infrastructure, we have upgrades and expansion. Expansion has remained the same. That has already been spent. Maintenance is activity driven. And we produce our maintenance capital this year as Q3 activity was softer than we expected in both Canada and the U.S. as the industry was in both markets. And Q4 looks to be a little bit softer than what we would have expected 3 months ago the last time we gave a CapEx update. Since we only update it once a quarter, we're only able to reflect the forecasted activity once a quarter in our CapEx numbers.

Got you. Okay. And since you signed some contracts since the end of the quarter, Kevin, what is the approximate term or average term of those contracts? Are we doing 1-year, 2-year, 3-year?

We don't -- so I can tell you, nothing at 3 years. We usually don't publish contract by contract terms as...

No. Just average. I know you can't tell me contract by contract, but just generally on average.

Think about in terms of between 6 months, 1.5 years with an average of about 1 year.

Okay. That's helpful. And the last one, if I could sneak in since Chase got one, I get one. You're -- how much of your directional drilling business is in the U.S. versus Canada? And how long does your deal with Schlumberger go before it expires? Or is it open-ended?

There is -- it's open-ended. There's no expiry. We continually are working with Schlumberger. I can tell you that the third quarter was a soft quarter for us with U.S. and Canada. We push rates on directional. That didn't work very well for us. But typically, if you negate the seasonality, it's about 50-50 between Canada and the U.S. Of course, that means that Q1 is very strong in Canada. Q2 is very light. But for the balance of the year, it's about equally split.

(Operator Instructions) Our next question comes from the line of Jon Morrison with CIBC Capital Markets.

Kevin, can you give more color on the order of magnitude that you're seeing in the day rate momentum that you mentioned in the release and your preamble? And how different is it across geographies and rig classes right now?

So I think I gave the rate ranges for the U.S. rigs. I was a little more vague on the Canadian rigs because we're right in the battle right now. I'm sure my sales guys are in front of customers this afternoon and tomorrow. And both our customers and competitors are listening on the call. But think about it this way, Jon. The rates we were pushing through on a quarterly basis, we've been trying to step up rates $1,000 and $2,000 a day. Each time we go to renewal or a step in the market, we have an opportunity to do such. The type of -- the magnitude of the type of changes has run across.

Is it fair to assume that the comments you made were fairly specific to Q3 or post Q3, not generally speaking over the last 6 to 12 months or anything like that?

Absolutely. Q3, post Q3, into Q4 and into Q1. So those rate increases didn't have a huge impact in Canada in Q3, but we expect it to start to help in Q4 and Q1.

And can we -- just on the operating cost side. Are you expecting any turnkey in Q4 at this point based on everything that you know?

So we don't ever provide guidance on how much turnkey we will have. I know that'll be easier to model, but we just -- we don't know that going into the quarter. I would say that the turnkey component of our activity in the U.S. has been lower this year than it has in the -- in previous years. So we wouldn't expect a big jump. It might be 1, maybe 2 jobs.

Okay. Can you give any more color on the 6 rigs that you signed the contracts for in the quarter and post quarter? Were those straight renewals? Or were they new contracts?

I don't have that data in front of me. But I know that some of those were new clients, new contracts for new deployments. Some may have been renewals. I can't recall. But I think if you assume that half are new and half are renewals, that's probably...

Yes. I think that's good, Kevin.

Okay. In terms of the 2017 CapEx cuts, I know that you've gone through some of the details here. But would it be fair to assume that you deliberately tried to cut your CapEx and went more aggressively at the budget or it was literally a function of going throughout the year and realizing that you probably weren't going to spend what you had originally targeted 3 months ago?

We saw the -- running on the wall back in Q2, but there's too much variability on how the back end of the year was going to look. So we frankly didn't pull any reductions back on our Q2 conference call in July. But with the commodity prices staying lower and the Canadian activity being dragged down by AECO, that maintenance capital number went down. And we're front up into the -- it is middle of October now. We have a pretty good sense of capital for the year.

Okay. I realize you guys don't have a 2018 CapEx plan yet, but is it fair to assume that it's a low probability that the 2018 spend is going to be at a meaningful premium to what you're outlaying in the new 2017 program?

Yes. It's tough to know what the market is going to be like, Jon. I mean, so much of it is determined by both our activity and the demand for upgrades by customers. But in the world that we're in right now on a $45 to $60 oil world, we're probably going to be no higher than where we are today.

Is there any expected ERP rollover into 2018?

There'll be a bit.

It'll be, but It won't -- it will be inside our infrastructure maintenance capital number and it won't be -- won't move the needle relative to top line number.

Kevin, turning back to your 3 priorities and wanting to make sure that you're an industry leader in terms of automation and installing NOVOS, would it be fair to assume that you're not willing to make those investments on any rig that isn't operating with a customer that has some form of a base contract and the customer has clearly indicated a willingness to pay for that technology at this point? Like, are you willing to install it on a rig and hope to get paid for it or only do so if it's with a customer that's willing to pay for it today?

Okay. So the answer is not quite simply yes or no, but it's really a good question, Jon. So the first part of the answer is I'd like to have the hardware and software, the steel box on every rig with the red and green light off or on. So customers have the option to pay for it or not pay for it. And I'd also like to have hard evidence, so it's very compelling. So they're highly incented to want to turn the system on. That said, we will want to play capital on the rigs, unless we have clear line of sight to revenue. Now this is a really minor capital investment, like in the case of [steel] box inside a few months. So you don't -- we don't need a 2-year commitment to make that decision and we might need it to welcome it and to make the decision.

Okay. It's fair to assume probably that the uptake on it, of everything that you've done today would have to be very strong with customers to keep going forward at the same pace in 2018.

I think our expectation is the pace probably accelerates.

Okay. Just -- sorry, one last one for me.

Yes. Yes. The initial 20 rigs, it's a bit of a push by us in talking to customers and getting them on the rigs and trying it out. And the reason why we're -- we have it installed on 20 rigs is we want to test it with enough good data to verify it.

And bring out all the [field harding] bugs and things like that.

Very difficult to do that when you have it running on 1 or 2 rigs.

Okay. And just to go back to the comment around international bids because any time that you're in the upper 50s on Brent, all the chatter on international contracts and Middle East seems to come back. Would you be comfortable being free cash flow neutral in 2018 if there was contracts in the market that provided similar economic rates of return to 2014 levels and contract durations that were 4 or 5 years in duration? I'm just trying to understand how you prioritize the free cash flow focus versus aspirations to, perhaps, get bigger in certain countries.

Jon, we haven't actually put forward our 2018 budget to our board for approval. But I suspect if I put forward a cash flow-neutral budget, it will be a different CEO talking to you next year.

Okay. So it is -- fair to assume that out of the 3 priorities, that's the #1 through and through.

It's #1.

Okay. Last one just for me, Kevin. On the well servicing market, improvement, obviously, in economics in the quarter, which was positive to see in pricing. Do you believe that you need to see industry consolidation in Canada for that market to get meaningfully more healthy in the next 2 to 3 years?

Yes. Jon, I've actually, I think, said that in a couple of calls back that the market right now is just structurally in a really tough spot. Consolidation would be -- would really help. And I think we've even said that we'd like to be a part of a consolidation, but it's not something that we're going to put capital towards ourselves.

And our next question comes from the line of Ian Gillies with GMP.

Kevin, I wanted to go back to Canadian day rates and if we think about the evolution into, I guess, Q1 '18, is it fair to assume that we should expect more than just additional boiler revenue right now based on what you know today?

Ian, so I think I did give some sort of comments. We did push rigs through on the shallower rigs everything outside the Deep Basin, and we're expecting to have a stronger average day rate in 2018 for those shallower rigs than we saw in 2017. So yes, pricing power beyond the boilers. Now that said, I also comment the market is really price-sensitive. And the exercise isn't finished yet. We're still working with customers daily as well as with our competitors. And things are lining up for us nicely right now, but the deals aren't done yet.

Okay. That's helpful. In the U.S., can you provide any commentary around what you're seeing from a drilling efficiencies perspective and whether they're starting to plateau or whether you're still starting to see, I guess, additional efficiencies? If you exclude some of the additional technologies you're putting on the rig right now that are obviously saving people's -- saving people time.

Yes. Ian, so we're a pretty important part of the efficiency chain on the drilling completion circuit. But frankly, over the last year or so, most of those efficiency gains haven't been coming from rigs other than more pad rigs being used. So I can kind of back this up a little bit and tell you that we're hitting really fast drilling performance days in the Eagle Ford back in 2010. We're hitting really -- with the best rigs and really fast drilling performance in the Permian in 2014. But there is just more rigs drilling at that level now, so that's still -- that's been part of the trend. And if you look at it today, we'd say that probably, a little over half of the rigs in the Permian are premium-efficiency rigs. And the balance of the rigs in the Permian probably have room for improvement. And we think that some of our rigs will displace some of those. So -- but the rig itself -- our best rigs right now, without automation, have been drilling at their maximum speed now for several years. But we are displacing lower-performing rigs in the marketplace as our other high-spec or super-spec rigs displacing lower-performing rigs. So that run rate in the Permian is probably half the Permian activity. And across the U.S., it's probably 300 to 400 more rigs of displacement that are possible.

Okay. That's helpful. And then last one for me. With respect to deleveraging and paying off $300 million to $500 million of debt over the next, call it, 3 to 4 years, should we just expect that cash position to continue to build on the balance sheet until the next maturity in 2020? Or is there something more immediate that you may look try to do if you get a sizable enough cash position?

Yes. I think the 2020 bonds are callable next month at 101, so that will be an obvious target. But there might be opportunities for us to buy back debt in the open market over that time frame.

And I'm showing no further questions at this time, so I'd like to return the call to Mr. Kevin Neveu for any closing remarks.

All right. Thank you for joining us on our Q3 call, and we look forward to sharing our end-of-year results in February with you. Thank you very much.

Ladies and gentlemen, thank you for participating in today's call. This does conclude the program, and you may all disconnect. Everyone, have a great day.