Precision Drilling Corp (PDS) 2017 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Precision Drilling Corporation 2017 Fourth Quarter Results Conference Call and Webcast. (Operator Instructions)

I would now like to turn the conference over to Ashley Connolly, Manager, Investor Relations. Please go ahead.

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

Through our news release earlier today, Precision reported its fourth quarter and year-end 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 fourth quarter and year-end operating results and provide a financial overview. Kevin will then provide an operational update and outlook and then will turn the call over for questions. Carey?

Thank you, Ashley. In addition to reviewing the fourth quarter and year-end results, I will provide an update on our 2018 capital plan and management of our capital structure.

Fourth quarter adjusted EBITDA was $91 million, which is 40% higher than the fourth quarter of 2016. The increase in adjusted EBITDA from last year is primarily the result of higher activity levels across our North American businesses. With the company's stated focus on fixed cost leverage, I'm particularly pleased with the EBITDA margin performance, up 500 basis points from last year to 26%. For the full year 2017, our EBITDA was $305 million, a 34% increase from 2016.

In Canada, drilling activity for Precision increased 6% from Q4 2016 while margins were approximately $100 per day lower than the prior year. The margins for the quarter were negatively impacted by legacy contracts rolling off and renewing at lower rates, offset by improved spot market pricing. In the U.S., drilling activity for Precision increased 50% from Q4 2016 while margins were approximately USD 360 per day lower, primarily due to lower IBC revenue in the quarter. We continue to see average rates moving up, and absent turnkey and IBC revenue, average day rates increased approximately USD 200 per day from Q3 2017.

Internationally, drilling activity for Precision decreased 1% from Q4 2016. International average day rates were approximately USD 50,300, a decrease of approximately USD 2,500 from the prior year. The decrease was a result of mobilization and demobilization payments received in 2016. During the quarter, we took a $15 million impairment charge relating to our Mexico operations due to a lack of activity in the region.

In our C&P division, adjusted EBITDA this quarter was $2.7 million, up approximately $2.3 million from the prior year. The increase is a result of significantly higher activity and a lower operating cost structure across most business lines.

Capital expenditures for the quarter were $25 million and $98 million for the full year. For 2018, our capital plan of $94 million is consistent with previous guidance. The 2018 capital plan is comprised of $45 million for sustaining infrastructure, $34 million for upgrading existing rigs and $15 million for intangibles. Our capital plan is expected to align with industry activity and reflects the lower dollar cost per upgrade of our Super Series fleet. We plan to complete 10 to 20 upgrades in 2018. The intangible capital portion of our plan includes the ongoing upgrade of our ERP system, which is on budget and on schedule to complete in Q2.

We have continued to build our contract book. And as of February 14, we had an average of 15 contracts in hand for the first quarter and an average of 40 contracts for the full year 2018.

I will now make a few comments on the balance sheet. We've successfully completed several transactions in the fourth quarter which further strengthened our financial position. First, we issued USD 400 million in senior notes due 2026 and used the process to repay and redeem our 2020 notes and a portion of our 2021 notes. Second, we used USD 49 million of cash from our balance sheet to reduce overall debt levels. And third, we extended the maturity of our USD 500 million senior secured revolving credit facility to November 2021. The result of these transactions is that we have retained our strong liquidity position and have no maturities due for almost 4 years.

I will point out that the USD 249 million notes due December 2021 are callable today, representing a portion of our debt capital structure we can pay down with free cash flow in the future, a stated priority on our last conference call. As of December 31, 2017, our long-term debt position, net of cash, is $1.67 billion. We had $65 million in cash on our balance sheet, and our total liquidity position was $727 million.

I will mention our focus on free cash flow generation this year resulted in funds from operation of $184 million, with capital expenditures, net of disposals, of $83 million. I continue to be encouraged by the cash flow generation performance of our business.

For 2018, we would expect depreciation to be approximately $360 million and SG&A to be in the range of $100 million to $110 million. We would expect cash taxes to remain low and our effective tax rate to be in the 20% to 25% range.

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

Thank you, Carey, and good afternoon. As we've stated in our press release...

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Okay. I'll begin from the beginning again, and I'll say thank you, Carey, and good afternoon. And as we stated in our press release earlier today, we're very pleased with our fourth quarter results.

In addition to our improved financial results, the highlights for Precision included achieving our 2017 strategic priorities. Carey mentioned our progress on cash flow, reducing debt and improving our financial position, and he also mentioned our strong results, managing G&A and our fixed cost leverage. And I'll add that on our key operations performance metrics, we exceeded 6 of our 7 performance targets relating to key customer performance measures, and that further strengthens our competitive positioning.

And finally, I'm pretty pleased with our progress on our beta testing of our new technologies, including NOVOS Process Automation Controls and the abbl Directional Guidance System. By the end of 2017, we achieved our commercialization benchmarks and have begun the market rollout of these technologies. I'll provide a little more color on our technology initiatives in a few moments.

But first, I'll make a few comments regarding what we're seeing in the markets. Starting in lower 48. The improved commodity prices are providing a nice tailwind, but it's the efficiency and performance of our Super Triple rigs that's propelling us forward. We ended 2017 with our highest market share since entering the United States in 2006. Today, we have 65 rigs running, and we expect to be in the low 70s by the end of the first quarter, with customer indications for further rig activations during the second quarter.

Leading-edge rates for our pad walking, extended reach ST-1500s are now in the mid-20s, and rates for our similarly equipped ST-1200s are in the low 20s. Now I'll remind you that Precision's Super Triple rigs, both our ST-1200 and our ST-1500, were designed to be inexpensively upgradable, with clip-on walking systems costing approximately $1 million, third pump installations less than $700,000 and high-pressure upgrades that cost less than $500,000. As a result, the incremental capital we have used to upgrade our rigs to leading-edge spec has been substantially lower than others in the industry report. For 2018, we continue to plan 10 to 20 upgrades of similar scope and expect to spend about $34 million in total. Now should customer demand exceed our estimates, we will consider additional upgrades, and that is only if the day rates, the incremental margins and contract duration meet our hurdles and also provided that we can satisfy our debt reduction targets.

Now you may recall that during the third quarter, we reported only 3 additional long-term contract bookings. Now since the end of the third quarter, we've added 21 long-term contracts, primarily all in the United States. Pricing momentum pickup seen in the fourth quarter is continuing as customer demand for the most efficient rigs remain strong and supply remains very tight. Of those 21 long-term contracts we signed, 9 of those are for rigs in the Permian, 4 in the SCOOP/STACK, and the balance are spread between the Utica, Marcellus, the Eagle Ford, the Bakken and DJ Basin. Now some of these will be rig additions that we've already mentioned, and some will be renewals of existing contracts.

I want to point out that the Precision ST-1200 is a unique high-performance, high-spec rig. This rig is well suited to the DJ Basin, the Marcellus and the Canadian Montney. Recently, at DJ, our ST-1200s are drilling 13,000-foot measured depth wells with 5,000-foot horizontal sections. These wells are being drilled in less than 3 days. These rigs are walking on the pads, well to well, in less than 30 minutes, and they're able to relocate pad to pad in less than 2 days, sometimes as quickly as 26 hours. The ST-1200 is unmatched in its drilling and moving efficiency, and I believe this might be the most efficient drilling machine anywhere in the world.

Similarly, our ST-1500s in the Delaware Basin have drilled wells out to 22,600 feet, and these wells have been drilled in less than 21 days. They walk well to well also in 30 minutes, and they move pad to pad, complete relocations pad to pad in 1.6 days.

Now achieving these levels of performance requires a Precision Super Series rig with a well-trained crew and high degree of collaboration with the operator. It also requires optimized well design. But we believe our efficiency, our safety, our crew competency and our Super Series rig design creates a substantial competitive advantage, which is driving our market share and our increased utilization.

To continue on this theme, I want to provide an update on our technology initiatives and how we're demonstrating that these technology initiatives will further drive efficiency and enhance our competitive advantage. So today, we have 23 rigs equipped with the NOVOS process automation package, and this includes our training rigs in Houston and Nisku. Over the last year, through our beta testing program, we've learned that training our crews in automation equipment is a critical step in implementation of this technology.

Now we've also learned that the experienced driller drilling the same well over and over, focused solely on speed can deliver remarkable results, like those I just quoted at the DJ Basin and the Delaware basin. However, the workload, the information intensity and the demands on today's driller are immense, and consistently repeating those results can be challenging. Our automation system takes over the repeatable steps by sequencing and operating the machines, allowing the driller to focus on managing the crew while overseeing the overall process. The result is that with automation, we can match that very best driller. We can match him day in, day out. We can eliminate human variance and deliver consistent repeatable results while the driller becomes more effective at a supervisory and oversight role, better able to ensure overall rig and crew performance.

Now our next steps will be in developing applications for apps, and those apps will be targeted at improving wellbore quality by automating various drilling algorithms to improve field -- and algorithms to improve field efficiency by managing engine and generator use on the rig. We believe these apps will continue to augment our competitive advantage while contributing additional revenue streams.

Now we know the industry is cautious when implementing new technologies, especially those that are software-based. However, we believe the results here are highly compelling, and those customers that are data and technology savvy will be the early adopters. And as with most new technology introductions, the balance of industry will watch the early adopters and eventually follow. This year, our plan will be to increase our PAC installed base from the 23 rigs I mentioned earlier to 33 rigs, though we're prepared to respond faster should customer demand accelerate.

Now regarding our directional guidance software, this technology was effectively proven in early 2017. As I described earlier, field deployment was limited to early adopters. We believe that in 2018, we may have reached a turning point. Customer interest has picked up substantially, and we'll run as many jobs in the first quarter of this year as we executed during the full year of 2017. Our DGS system is working very well and will eventually integrate with our PAC system, and we believe this also creates a unique combination of value for our rigs.

Now turning to Canada. The improved commodity prices providing a tailwind to the U.S. are muted in Canada by transportation bottlenecks, both for oil and gas. In particular, the depressed AECO gas price remains a challenge for our customers. Now that said, our first quarter activity in Canada has been in line with last year, and the rates for our shallow rigs have held up following price increases we mentioned in our third quarter conference call. Over the last few days, we're noticing industry rig count is starting to soften as the AECO-sensitive customers are beginning to wind down winter drilling programs prior to the normal spring breakup timing.

However, looking forward, based on numerous customer discussions at this point, it seems Precision's activity levels through the second quarter and the back half of 2018 are generally in line with 2017 levels. We expect that the Deep Basin liquids drilling, particularly the Montney, will remain firm through the year, and we expect to see constructive demand in the pure oil plays, such as the Viking, Cardium and particularly, our favorite area, heavy oil.

Now these comments should be viewed cautiously as Canadian E&P operators are sensitive to commodity prices and will be prepared to pivot quickly either up or down. Now while I think many have concerns about Canada, we believe our competitive positioning, our Super Triples and our Super Single asset base, our scale and our well-trained people and our excellent customer relationships will serve us well as this market evolves. We will focus on sustaining our market position and generating cash flow while closely monitoring the dynamics of the market.

Now turning to our well service business. As some of you know, Tom Alford joined Precision at the beginning of the year to lead our well services group. Tom brings over 35 years of Canadian well service experience to Precision, and he will be instrumental in our strategy as we continue to evolve this business. Now while Precision is focused heavily on the cost side, Tom brings a broad leadership capability. He will focus on strengthening our field operations, improving our customer exposure while continuing an intense focus on costs. Now I know all of you know the well service sector remains a very tough business with the structural oversupply of rigs, but we expect the focus and experience Tom brings will help set us apart.

Turning to International business. This remains strong and stable. We have only 2 contract renewals occurring late this year, and those rigs are performing very well. We anticipate constructive renewal discussions later in the year with our customer. We continue to bid our 4 idle rigs in the region. Interestingly, none of the projects we have bid have progressed through to award, and several have been delayed for rebid. We do expect to see some movement on some of these tenders in 2018, following the improved -- improving Brent crude price.

Now in 2016, one of our stated priorities was to be ready for a rebound. In 2017, we restaffed over 120 rigs from our low of 38 operating rigs at the bottom of the trough, and we did so with no increase in fixed costs, no abnormal maintenance capital and minimal startup costs. Also through 2017, we introduced several new technologies, continued our focus on fixed cost leverage while growing Precision's market share and continued to reduce debt levels.

While we have not disclosed our 2018 priorities yet, rest assured that debt repayment from cash flow, along with our technology and fixed cost leverage priorities, will not be neglected.

As a closing note, I want to thank the employees of Precision for their hard work and excellent results on all of our strategic priorities and especially the excellent progress made throughout the year on safety and all the very good work our team has done on the implementation of ProjectONE, our new ERP system. So on that note, I would now turn the call back to the operator for questions.

(Operator Instructions) Our first question is from Sean Meakim with JPMorgan.

Kevin, maybe to start off, I was hoping you could maybe give us a little bit of insight into just some of the mix as far as the Canadian rates from 4Q to 1Q. So given your pretty strong average day rate in 4Q, it seems like that was probably somewhat mix driven, with more weight towards Super Triples. I'm just thinking about how we translate that over to the first quarter. And I think you noted shallow war -- shallower markets have held up pretty well, where you've got some increases recently. But perhaps some of the incremental activity during winter drilling is more dilutive to the average. Just how should we think about modeling that change quarter-to-quarter?

So it's probably easier to compare Q1 '17 to Q1 '18 just because the mix in Q1 tends to be a little different. So what we find happens in Q1 is that the heavy oil delineation work and a lot of the thermal work, works only for the winter season. So we have a mix of shallow rigs that come into the mix every Q1, which are -- the shallower rigs, the rates are better than last year, so it's still a good comparison, but they're much lower than our Super Triples. Those rates would typically be in the kind of mid-teens or slightly below mid-teens for those rigs versus upper teens, low 20s for the Triples. So the higher portion of those thermal and delineation heavy oil rigs, it does pull down the average day rate Q4 to Q1, but I think it's more valid to look at Q1 '17 to Q1 '18 for trajectory in rates.

Okay, that's helpful. And then just as we think about the $10,000 comment in your prepared remarks as far as trough to current levels, could you remind us roughly where you consider trough levels of rates?

I would say that we saw leading-edge rates drop into the mid-teens, even below the mid-teens back in 2016.

Okay. So for clarity, do you think current leading-edge rates for your best rigs are approaching mid-20s at this point?

We'd say they're approaching mid-20s, yes.

Approaching, okay. And then one more, if you don't mind. I guess -- well, it seems to me, in the release, you're seeing the contract coverage for you in Canada has been eroding the last couple of quarters. Is it fair to say that's strategic or just a function of the customer and commodity mix? I mean, lots has been kind of moving in Canada in the last few quarters. Just curious how you think about contract strategy and balancing share versus price in 2018.

So in Canada, it's a little bit different in that contracts are not a normal function of the business. They generally relate to capital deployment. So in Canada, it's quite common, if you build a new rig, you got a long-term contract that might be 3, 4, even 5 years long. If you upgrade a rig, the drillers are very disciplined about getting contracts to cover the upgrades, where a lot of upgrade contracts will be 1, 2 or 3 years in duration. But for normal well-to-well work, throughout this season in Canada, there's very, very little or almost no contract work. A lot of that relates back to the early 2000s when the work was risk -- sensitive to natural gas prices and the rapid squeeze in natural gas pricing. But I can tell that the notion of a -- just a regular term contract in Canada doesn't really exist when you compare that to the U.S. market. So it's not really our choice for how many contracts we mix in with how many well rigs. We tend to insist on contracts for rigs that have upgrades or capital requirements, and we certainly insist on contracts for newbuilds. So the pricing in Canada tends to be more annual price negotiations that don't have any commitment for time required. Is that helpful?

Very helpful. Great.

Our next question is from Chase Mulvehill with Wolfe Research.

So I guess, a quick question. On the 10 to 20 upgrades, how many of those are actually working today?

You'll notice we don't actually give that disclosure. Some of those rigs may be working, and some of the upgrades may be taking a rig that didn't have a third mud pump and adding a third mud pump. And so we've given guidance that we expect to add 5 or so more rigs between now and the end of the quarter. We said there might be a couple more coming into the second quarter. So you could assume that some of the upgrades we've done so far will be to existing rigs and some of the upgrades may be the rigs that aren't activated yet.

Okay. All right. So don't put all those as incremental rigs is what you're saying?

Yes, correct.

All right. And on the upgrades, are there any that you're upgrading either Drillworks or taking them from SCR to AC rigs?

No, we're not. But we have a handful of rigs on our fleet that are DC SCR rigs, and those would come probably -- if you look at the next 10 after these and the next 10 after that, it's probably the last 10 rigs we'd be doing that have those SCR-to-AC upgrades, kind of long term scheduled in. And those upgrades will be likely $5 million or $6 million or $7 million per rig, something in that range. I don't expect we'll get much higher than that. But those are probably 10 to 20 rigs away after we finish the current plan.

Yes. Chase, it's safe to say that the upgrade plan that we have for this year in the stated capital plan, none of the upgrades are more than $3 million.

Okay. All right. That's helpful. On the technology initiative, do you all care to kind of quantify how much EBITDA you're generating from this technology -- the new technology initiatives and kind of where you think you can go by the end of this year?

So we gave guidance back in our Investor Day, and we really haven't come off that guidance. We commented, of the 20 units we have sold, right now, a number of customers are paying the full ticket. As we move through various performance benchmarks for those customers, eventually, all will trend towards the full price we gave on our Investor Day. So for example, on the automation system, we're looking for $1,500 per day fixed charge.

Okay. I'll squeeze one more in, and I'll turn it back over. On the international side, with the idle rigs, as these look to kind of restart in 2018, there are a few of them, how should we think about incremental CapEx on the potential for restart of rigs? And is that included in your CapEx guidance?

So we haven't announced any contract awards for reactivating any of those 4 idle rigs. If we were to reactivate them, it would likely be a contract in the range of 3 years, and the capital required would be $10 million to $15 million to get them up to spec.

And the payback can be within that 3 years?

The payback of the capital and then some sort of base rate on the existing rig, yes. But in answer to your question on if any of that capital is included in our capital plan, it is not.

Our next question is from Taylor Zurcher with Tudor, Pickering and Holt.

Just wanted to follow up on the prior question as it relates to international. Could you shed some more light as to which specific geo markets are seeing the most incremental demand or tenders on the horizon? And then secondarily, I think, some qualitative color would be helpful as it relates to the chances you could reactivate some of those 4 rigs in the middle of this in 2018. In other words, how many of these tenders that you're actively participating in today would have 2018 start dates?

Good questions. So first of all, if we won a tender in the second quarter of this year, the rig might reactivate in 2018. So that's kind of the timing. You're probably looking at 3, 3 to 4 months post tender to reactivate the rig, and that would be in line with most deployment schedules customers look for. So that's kind of the first piece of guidance. I don't have a high degree of confidence we're going to see any awards in the first half of this year. Even as we saw a real sharp move upwards in the commodity price and -- it's got to be driven by clearly defined oil supply/demand fundamentals that get these countries moving a little quicker with the drilling plans. But the issue going on right now that I think is going to be hard for the buy side especially is supply and demand because a lot of the things we're bidding on are projects that were scheduled to happen 2 or 3 years ago, and they still haven't started. So the concern that there's a growing sinkhole in production should be gaining momentum this year. Now these projects that we're bidding on now, well, some of these we bid on 2 years ago. And the rigs haven't been deployed yet, and the projects are falling farther and farther behind.

Okay. And second question, just as it relates to the U.S. With pricing now seemingly in the mid-20s, $1,000 a day, has the customer/operator mindset changed at all as it relates to extending duration of some of these contracts, at least those that are in the spot market today, longer than 6 months? Or what are you seeing on that front? Is contract duration increasing at all?

Yes, it is. Certainly, because we put it on our Q3 call that we could get pricing but we couldn't get duration, so going from 0 duration to anything between 6 months and 2 years is a notable increase. So yes, duration is increasing. But there's always a game theory or a negotiating ploy. We try to get the maximum day rate, and they would like to get the lowest day rate for longest term. And that happens every time. But the short answer is that we have contracts ranging between 6 months and 2 years right now. We don't give out an average. But of the 21 new contracts that we signed, some renewals, some new deployments, they're in that range of anywhere between 6 months and 2 years.

Okay, great. And last one for me, if I can squeeze it in. You talked about Process Automation Control or NOVOS employed on 23 rigs today. I think that was 20 rigs a few weeks -- or months ago. Are those 3 incremental rigs new customers relative to the customer base you had for the original 20 rigs? And if so, 3 incremental customers or less than that?

So I did comment that we're putting these on our training rigs. So 2 of those rigs on are training rigs, and that's a very important element; and the living -- the third one, which is a new customer.

Our next question is from Benjamin Owens with RBC.

How many of the rigs that you mentioned having line of sight on adding through the first quarter and into the second quarter do you already have contracts in hand for?

So I would comment that the rigs we expect to add are all contracted. Of course, we have a component of our fleet which is uncontracted. So if a commodity price collapse sort of happened between now and the end of March, some of the uncontracted rigs could be laid down. So I'll probably give that qualification, but the additional rigs we're adding are under these term contracts.

Okay. I was wondering if you could tell us what the average day rate in backlog for the 34 rigs you have under contract in the first quarter in the U.S. was?

Yes. And Ben, that's not something we would disclose.

Okay, just last one for me. A little bit different topic, but would you consider moving any idle rigs from other geographies into the U.S. if you had customer demand that supported the move?

Ben, I can tell you that I think I've heard at least a couple of other drilling contractors talk about moving rigs from Canada or from Saudi Arabia down to the U.S. We have no plans to relocate rigs from Canada to the U.S. right now. We have moved rigs both directions over the past several years. We moved some rigs from Canada to the U.S. and some from the U.S. to Canada. So we will do it if the market pull us there. But what I commented on is that if we see continued price trajectory upwards in the U.S. and if, for whatever reason, we saw prices eroding in Canada, we might change our view.

Our next question is from John Daniel with Simmons & Company.

Congrats on hiring Tom. He's a good add. Should we look at his hiring as a sign you might consider tactical acquisitions on the well service business?

I think that the space needs consolidation, John. I think that's really important, and I think you understand what's been going on down here in the U.S. It's a tough market in the U.S., tough market in Canada. Canada needs consolidation, no question. I think Tom has a history of consolidating companies and building businesses in the space, and he's done that a couple of times over. I think he does it quite well. I would tell you, like we've said in the past, we'd like to be part of a consolidation, less likely we'd use Precision capital to execute that.

Fair enough. Labor challenges is a frequent obstacle cited by the industry. Is your shift to more automation having any noticeable impact yet to your HR initiatives? Specifically, do you need a more sophisticated hire who's comfortable with that technology? Or is it the opposite, where automation allows you to have a less talented or experienced person?

Yes. Kind of an awkward question in that. As I said earlier, a really experienced driller, kind of working just fully focused, is pretty hard to beat. So automation allows you to replicate that or even a good driller -- like a good experienced driller rather than just leading-edge perfect performance. So -- but I would tell you that the skill set needed, as you increase technology on the rig, that increases the skill set needed by the driller to be an effective driller. So we've added these 2 NOVOS systems on to our training rigs so that we can train drillers to this new level of technology. So I'd tell you that well -- well, probably, he has to be a little less hair trigger on timing. He does need a broader skill set and more software knowledge. So it probably increases the skill set, and the job doesn't decrease it. But we really think it is going to really improve all the rigs, not just have really good rigs and then kind of normalized -- normal curve performance on the rigs. We think we'll push that normal curve to the right. But I'm quite proud of how Precision's handled staffing challenge in its entirety. I think last year, we processed close to 40,000 job applications, we ran over 1,000 people through our training rigs and restaffed that entire 120 rigs in Canada and the United States with nary an operational issue.

Okay. That's impressive. Last one for me, it's a quick one. Just you had pretty impressive data on and comments on your rig performance. Just given how well the super spec rigs are performing, do you see any demand for non-super spec rigs?

If you look through our rig fleet right now, you'll see that we have some of our SCR rigs running.

But as -- when we look at the U.S. land rig count, for instance, a lot of the rig adds have been from private. So are they being as discriminating, if you will?

On those rigs we have running, the DC SCR rigs, they have digital controls, and they have pad walking systems. And they've got high-pressure mud systems. So they're -- while they're not AC rigs, they're able to -- and by the way, John, those rigs are all DC top drives, so they're microprocessor-controlled rigs. We'd argue you could drill as well with that rig as you can with an AC Super Triple, but that's an uphill battle with a lot of customers.

Our next question is from Ian Gillies with GMP.

As you work through the rig upgrade program, acknowledging the next 5 rigs or so aren't that expensive, but as you sort of move in perhaps some of the SCR rigs, I mean, there is an opportunity cost associated with not moving rigs from Canada. And so I mean, how are you thinking about rig upgrades in the U.S. versus just moving the rigs from Canada, given what I assume to be higher rates and margins being earned?

Well, right now, Ian, all of our Super Triples in Canada are running, and they're booked. And so that gives us real clear definition of opportunity cost.

And so I guess, the follow-up would be, I mean, do you -- are the returns or the margins so wildly different from one area versus the other that it may warrant perhaps pulling some of those rigs at some point and moving them down south?

It's too early to say right now. I mean, I think for the -- if what we're hearing about the Montney stays in place, the answer is easily no. If there -- and especially if some of our peers take rigs out of Canada, I think that tightens the supply of -- in our sector. So I'd be not troubled to see other AC rigs leave Canada and move to the U.S. because we've got a pretty good business base right now. Now if market conditions change in Canada and utilization drops on those rigs or if there's, for whatever reason, intense day rate pressure, that might change our view.

Okay, that's helpful. And along that same topic, on the last quarterly call, you talked about mechanical doubles kind of nipping at the heels a bit on some of the AC Triple's performance. Is that something that's continued to be a theme through winter drilling season? Are you seeing anything that may have changed your view on that at all, that helped separate those rigs from the mechanical doubles?

We're doing pretty well this winter. And if we have that pressure -- as I said earlier, if we see pressure on day rates, if that pressure starts to cause our rates to go down later in 2018, that might change our view. But right now, for this winter, I don't see it impairing our rates on the rigs.

Okay. And with respect to some of the more expensive rig upgrades in the U.S. as you start to move towards a higher rig count, I mean, would it be fair to assume that we would need to think that, I guess, the day rate for those rigs would need to be in the $25,000 to $30,000 per day range to start doing some of those more expensive upgrades?

Well, Ian, I think for our fleet, as we mentioned, the upgrade plan that we have this year of 10 to 20 rigs, all of those upgrades would be $3 million or less. Once we get through those, the next batch of upgrades would be kind of in the $3 million to $4 million range. That would be about another 10 rigs. Again, as Kevin mentioned, some of those will be idle, some of them would be currently working. And beyond those, we would get to an upgrade range where we're upgrading AC stretch Super Singles, increasing capacity there. That would be more in the kind of $4 million to $6 million range. So I think we're a long ways away from hitting the upgrade cost that had been communicated to the market by some of the other drilling contractors in the industry.

Our next question is from Andrew Bradford with Raymond James.

Can you give us any comment or color on what the rate disparity might be between your 1200s and 1500s?

So in the U.S., I commented that we're seeing rates approaching the mid-20s on the 1500s and low 20s on the 1200s.

Okay. Was -- is there much of a cost difference on a per-day basis between those rigs?

The 1200s are less expensive to operate. They're smaller rigs, fewer truckloads, fewer pieces, less drill pipe, so less expense.

Will we be talking $1,000 a day or $2,500 a day?

I would -- yes. What I'd tell you is that -- I'd say that a rate -- that there's $3,000 or $4,000 less per day for a 1200. And probably, it earns us about the same margin as a 1500.

Okay, perfect. So just coming back, if I can, just to the leading-edge rates. You talked about this.

Let me qualify that comment. What I should say is the same return on our capital invested.

Yes. If you remember, Andrew, the capital cost of the 1200 is about $18 million, maybe $18.5 million. But the capital cost on a 1500 is going to be about $20 million or $20.5 million.

So just coming back to the leading-edge rates here. So is it your sense -- are you noticing that this rate -- this leading-edge rate is moving quickly right now? I guess, is that sort of a very recent number? Or is that something you've noticed over the last month or 2 months?

Even in November, December, we're talking about low to mid-20s, so what's really changed is contract term. So customers are accepting contract terms now for rates that are at that mid-20s number. They certainly weren't, back in Q4. So these things move with -- kind of step by step. First, rates go up, then term goes up. And then rates go up and then term goes up. So I'd say that the term went up quite quickly. The rates have been in this ZIP code for a little while.

Okay. So I know you're trying to avoid answering questions like this, but of the 21 rigs that were contracted in the fourth quarter, the rate -- the leading-edge rate shouldn't be too much different than what you got this contracted at but the term that you could have gotten might have been longer. Is that a fair takeaway?

There'll be variance in terms, and there's also a variance on spec there. Some of the rigs will be leading-edge rigs. Some will be ST-1200. So you can't take 21 x $24,500 and make that number match the incremental revenue here.

Yes. And Andrew, I'll just comment. If you remember, back on our Q3 call, we've talked about a little bit of lull in activity. And the reason for the lull in activity is customers were expecting us to make capital investments on rigs and not give us any term coverage. So there was no softness in the day rate at that time, but customers didn't really know what their 2018 budgets look like, so they were hesitant to enter into 1-year terms to cover capital cost. That changed towards the end of the year as they got more visibility on 2018. And then, as Kevin mentioned, as we entered 2018, it really accelerated. That's what's really driven the contract signing here over the past couple of months.

Just as a housekeeping item, the rigs that earned shortfall payments in Canada in the fourth quarter, are they working right now?

Yes. Some would be working, some might not be working.

So would -- just as a housekeeping item, but would we expect to see shortfall payments again in the first quarter then?

So typically, we have shortfall payments -- we'd get the majority of the shortfall payments at the end of the year. But if you remember, the shortfall payments...

On an accrual basis?

We typically don't have a whole lot of shortfall payments in the first quarter.

Okay. Last question for me. If we control for the mix changes in Canada quarter-to-quarter -- it doesn't look like the mix is all that much different year-over-year. But if we control for mix changes quarter-to-quarter, trying to get to a same-store sales day rate, is it your sense that you're getting better rates or the rates are improving at any kind of a pace right now in Canada on the larger rigs?

So I think, Andrew, our comments in Q3 kind of holds in that our Triples rates are flat with last year generally, and we were successful getting some price increases on the Super Singles and the shallower rigs.

So just reiterate those comments?

Yes. That was -- those prices were locked in back in by February -- by October, and they're holding. We haven't had any pricing pressure during the quarter but wouldn't expect much during the quarter.

Is there much of the leading-edge market in Canada for those rigs?

If an operator that wasn't talking to somebody back in October, November to book a rig comes along now and wants to take a rig in a window or take -- or add another rig somewhere for a couple of holes, that might be a spot market, but I don't think it's indicative of any kind of trend.

Okay. Are you noticing that your customers in Canada are concerned about a potential exodus of relatively fully featured rigs south of the border?

We haven't been talking too much about that ourselves because we just don't see it on the near horizon. I'm starting to hear a bit of it in the market, but if it tightens up the supply for us, we'll be really happy.

(Operator Instructions) Our next question is from Jon Morrison with CIBC.

Carey, of the shortfall revenue, $3.4 million would have been earned in Q4 had the rigs worked. Is it fair to assume that the rest of it would have been earned in Q1 through Q3 and none of it relates to 2018?

It's both. It's -- some of it's going to be in the first few quarters of the year, and then some would be in 2018.

Okay. And you wouldn't have any sense of how much of it would be 2018 that you could share, would you?

Let's say 1/3 of the non-Q4 would be in 2018.

Okay. Kevin, just a point of clarification. Based on the comments in your opening remarks, even though we're seeing heartburn around AECO and some early termination of drilling plans in Q1, you're thinking right now that Precision-specific activity levels in Q2 are going to be fairly similar to last year. Is that fair?

Based on all the contacts with the customers, that's what's coming back right now. We're already into earnings release season, so I don't see any -- last year, we saw a bit of adjusting work going on around earnings release periods, where customers are kind of resetting things around some public disclosure events. This year, we don't see that quite so much. And I'd say that our kind of front-end conversations right now are speaking to activity levels that look -- Montney, Deep Basin, relatively flat; and again, Cardium, Viking, relatively flat, oil weighted. But I'd just caution you, there's certainly a lot of anxiety right now about AECO, and we know that a lot of the cash flows in Canada are based on AECO and WCS. So we recognize that there could be a quick pivot, and the listeners should also recognize that too.

Is leading-edge pricing in the U.S. right now similar across geographic markets? Or is there any meaningful delta based on the basin?

No meaningful delta other than colder basins have rigs that have a little more winterization, but the rates are similar. Like the DJ, for example, are mainly 1,200-horsepower rigs, so they're shallower rigs that have the lower rate. But I'd tell you that high-spec, pad walking, AC Triple is garnering strong rates in all basins.

Just on the CapEx side, what order of magnitude would you be comfortable increasing the 2018 program, assuming that all of your IRR and contract duration thresholds got met on incremental upgrading opportunities above the 10 to 20 rigs that you said that you're planning to upgrade already? Like is there an absolute CapEx number that you wouldn't want to go above?

Well, there's a couple of things we look at, right? We have -- our upgrades are driven by customer demand, and then day rates have to cover the cost of the upgrade and the base rate on the rig. We have to get the appropriate returns and contract coverage. So that's one part of it. If we have an improving environment, we think that all of our rigs will reprice into an improving day rate environment, generate more cash flow. So we don't really see a situation where we would increase our CapEx plan for the year and have a less favorable cash flow forecast for the year.

Okay. Carey, can you just talk a little bit about your debt reduction plans and free cash flow harvest plans over a multiyear period? Is there any absolute level of net debt that you're hoping to get to, let's say, by 2020? Or is it all a relative kind of conversation?

Yes. The guidance that we provided on the last call, that we wanted to reduce debt by $300 million to $500 million over the next 3 to 4 years stands. Some years, that might be -- we might pay down more than $100 million; some years, maybe less than $100 million. But over the time span of the next 3 to 4 years, that's what we're targeting.

Last one just for me. Mexico, is there any line of sight to rigs going back to work in '18 at all? Or would it be further down the road that you think that maybe there's an uptick in that market?

So before we walked into this conference call, Carey asked me to strike my comment in my script that said we had no line of sight at this point to work in Mexico, but we're ready to turn rigs back on if something does come up. But I think if something happens, we might be kind the early cycle because probably the first work to start in Mexico is IPM project work. Mex -- PEMEX is going to award that to Schlumberger or Halliburton quickly because it doesn't require any engineering on PEMEX' part. And if one of those 2 companies was drilling some deep IPM wells, we have the rigs in country that would do that work. And we could fire up those rigs in a couple of weeks' time, and there's not a lot of capital or maintenance cost to get those rigs running.

Our next question from Jeff Fetterly with Peters & Co.

On the U.S. day rate front, in Q4 versus Q3, you were up about 5% sequentially. Is that a magnitude that you'd expect to carry in coming quarters, given the spot market traction and some of the renewal rollovers?

So Jeff, we commented -- in my prepared comments, I mentioned that if you kind of strip away the turnkey impact and the IBC impact, our day rates were up about $200 per day on average quarter-to-quarter. We would expect that trend to continue on from what we see today on the next couple of quarters as we have rigs coming off contract pricing into higher day rates and spot market moving up.

Okay. Let me derive off of that. What is your visibility for turnkey then?

We don't provide guidance quarter-to-quarter on turnkey. Typically, we have 1 to 2 -- 1 or 2 rigs running at a time. And so in a quarter like this quarter where we had $3 million of revenue -- I think kind of $3 million to $4 million or $5 million of revenue per quarter is a decent estimate for the next couple of quarters.

Okay. With contract term extending, rates now in the mid-20s on a spot basis or leading-edge basis, how far are you from contemplating a newbuild or the more aggressive refurbishment program -- upgrade and refurbishment program?

So Jeff, let me just make sure I understood the question properly. How far are we from contemplating newbuild programs?

Well, the reference earlier in the call about the next 10 to 20 rigs beyond the upgrades you've disclosed for this year being, obviously, much more capital-intensive and then, obviously, the newbuild extension off of that, how far do you think rates need to move up further? Or are contract terms long enough now to start to contemplate either one of those?

Well -- so for us, contract terms are not long enough yet, and day rates probably need to be much closer to or even over $30,000 per day. So I think we're still a little ways away for us to be contemplating newbuilds. But I think if the market moved that direction, we'd probably have utilization levels of our U.S. fleet approaching 90 rigs or maybe higher. We'd have day rates across the fleet that looks substantially stronger. So I think we have a building book of shorter-term contracts. But if we see both rates and -- move out to high 20s, low 30s and terms move beyond 2 years into 3- and 4-year terms, that's a couple of big steps that I think the market will be delivering a few new goals.

On the directional side, Q4 was one of the lowest quarterly revenues you guys have reported. How do you think about that business right now and in the context of the broader automation and optimization work that you're trying to do?

The directional business remains quite competitive. And I would tell you that we've gone through some organizational changes in the U.S. that caused us a bit of a drop in utilization in the U.S., but we're on a pretty good track right now in the U.S. In Canada, extremely competitive. The midsized directional companies are working hard to grow their market share. So I would tell you that we're really focusing hard on the abbl-assisted jobs, where we use the software with our directional jobs, and that's going quite well. And as I commented in my prepared comments, having essentially the same number of jobs in Q1 that we saw all of last year tells us we're in a good trajectory there. The software is working well. So I'm feeling good about directional going forward and particularly good about linking our directional service with our abbl software advisory package.

And Carey, just a couple of clarifications. On the SG&A side, you said $100 million to $110 million. Does that include stock-based compensation?

Yes, that would include it. So that's assuming we kind of go closer to historical levels on stock-based comp versus where we were in 2017.

Okay. And then on the Saudi upgrade side, you indicated $10 million to $15 million. Is that an absolute number or a per-rig number?

That would be a per-rig number.

And I'm showing no further questions. I would now like to turn the call back to Kevin Neveu for any further remarks.

Thanks for joining our fourth quarter call, and look forward to sharing our first quarter results in April. Thank you.

Ladies and gentlemen, thank you for participating in today's conference. You may all disconnect. Everyone, have a great day.