Ladies and gentlemen, thank you for standing by. And welcome to the Precision Drilling Corporation 2019 Fourth Quarter and End of the Year Results Conference Call and Webcast. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. [Operator Instructions] Please be advised that Today's conference is being recorded. [Operator Instructions] I would now like to hand the conference over to your speaker for today, Dustin Honing, you may begin.

Thank you, Towanda, and good afternoon, everyone. Welcome to Precision Drilling's fourth quarter and year end 2019 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. For a news release earlier today, Precision reported its fourth quarter and year end 2019 results. Please note 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 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 by discussing our fourth quarter and year-end financial results, followed by Kevin's operational update and outlook. With that, I'll turn it over to you Carey.

Thank you, Dustin. Precision, once again fulfilled its financial strategic priorities in 2019, retiring $205 million of debt during the year and leveraging our high performance high value strategy and scale along with disciplined cost management to generate strong cash flow. We are pleased with our 2019 performance and plan to continue the momentum into 2020 with debt reduction targets of $100 million to $150 million for the year. In addition, we are providing another year of debt reduction guidance, and raising our long-term target to $700 million of debt reduction between 2018 and 2022. I will now review some of the fourth quarter and year-end financial details. Our 2019 fourth quarter adjusted EBITDA of $105 million decreased 22% over the fourth quarter of 2018. The decrease in adjusted EBITDA primarily results from reduced U.S. and Canadians drilling activity and higher share based compensation expense during the current quarter and transaction related income received in the prior period offset by reduced operating and fixed costs in the current quarter. In the U.S., drilling activity for Precision averaged 63 rigs, a decrease of 9 rigs from Q3. Daily operating margins in the quarter were $9,876, an increase of $1,271 from Q3. Q4 margins were positively impacted by turnkey and IBC revenue, and certain reversals of prior period provisions during the quarter. Absent these effects, daily operating margins would have been approximately $8,500 or $100 per day lower than Q3. For Q1, we expect margins to be in the range of $8,700 to $9,000 per day, with IBC revenue more than offsetting lower fixed costs absorption. Turning to Canada. Drilling activity for Precision averaged 43 rigs, a decrease of 7 rigs from Q4 2018. Daily operating margins in the quarter were $7,391, a decrease of $296 from Q4 2018. Absent shortfall payments…

Thank you, Carey, and good afternoon. As Carey mentioned, we are pleased with Precision's fourth quarter and full year 2019 financial and operational results. I believe the Precision team performed exceptionally well in 2019, controlling every variable within our control to delivering on our strategic elements. I'll start today by discussing our 2020 priorities. Concerning our 2020 strategic priorities, we continue to believe to leveraging our scale to maximize free cash flow and prioritizing our free cash flow to play down debt, remains the best path create shareholder value. Secondly, by also prioritizing operational excellence, we are tightening our focus to deliver operational excellence to our customers, our community and our shareholders. We are measuring and will be reporting on several key metrics regarding operational execution, environmental impact, social impact, corporate governance. We believe these priority -- this priority aligns with our high performance, high value competitive strategy. And finally, continuing to enhance our technology lead with the Alpha technology platform is line to our customers’ urgent need to lower overall costs. We see this as a clear path to increase market share, deliver revenue and margin growth, especially as your capital discipline. The Precision team has a multi-year track record of meeting or exceeding our strategic commitments. And we expect – we’ll continue on this path in 2020. The priorities are detailed in our press release, and as in prior years, we’ll provide quarterly updates on our progress. We’ve also seen that these priorities are captured in performance metrics and management short-term and long-term instead of competition launch. Now turning to our business update, I'll begin with our Canadian Drilling segment. As Carey mentioned during the fourth quarter, we experienced early indications of strengthening customer demand. That momentum has continued into this year. Today we are running 80 rigs…

[Operator Instructions] Our first question comes from the line of Kurt Hallead with RBC Capital. Your line is open.

Congrats on the continued cash flow and debt reduction. I know it's been an arduous task in a tough market, so kudos to saying on plan. A question I had for you in context with respect to the automation, right. You mentioned you had 34 rigs outfitted exiting 2019, you're going to add another 24 systems through the year. So when you talk about on being outfitted on, are those rigs also getting paid for the automation? Or can you give us some general sense as to how many of those rigs you expect to actually get paid for that technology?

Yeah, Kurt, when we declared commercialization back in December, that was when we crossed the point where all systems were being paid. There may be some -- a little question if we have a rigs does not operating right now, and I would comment that not all of the rigs are operating. In fact, we mentioned the three in the Marcellus that were at least temporarily laid down. But the systems we have in the field right now that are out of rigs running and operating are being paid for.

Okay. And then in the context of the evolution is happening with kind of unconventional contracting -- unconventional contracts related to performance based dynamics. Can you give us some update on how you're thinking about that? I think, in the past, you've indicated, maybe potentially generating anywhere from like $250 a day, up to maybe a couple $1,000 a day depending on how the rig was outfitted in the technology deployed?

Yeah, I think as we think about our technology rollout over time, and I will just – I will comment on performance contracts at the moment. But our technology piece -- the base AlphaAutomation system running on the rig, which delivers consistent predictable results. We priced at $1,500 per day. And then for the apps that we're adding on for various drilling functions or tripping functions or even survey functions in the well or surface operations functions, the apps are being priced in the range of between $250 and $1,000 per day when those apps are running. And it sort of depends on whether or not it's just a hosting fee for a third-party app to get to the lower end of that scale or if it’s a Precision developed app like maybe your generator app it might be at the higher of that scale. But we see that anywhere from one to four apps could be activated any given time, and that's where we get the guidance towards somewhere between $250 and $1000 per day of additional revenue as we develop more apps. But I'll caution you just two or commercial right now. And we have a total of 13 more under development that should be commercial during the course of this year. And our partnerships on the apps include several operators, a couple of third-party service companies and a couple of universities. So we have a number of different constituents working on apps to improve drilling performance, but we think will have value for our customers. That's -- I'll stop there now and just come back on performance contracts for a moment. We've had a couple of operators particularly procurement teams looking to try to lever, kind of lower day rates, but incenting us for performance type metrics and performance type pay. It does need a little different allocation of risk. So we're looking at those very carefully and ensuring that we don't take on something, which just really pushes down the rate of the rig. And that gives us more risk.

Okay. And then, I just noticed that your relative market share within the U.S. -- it's a little bit going into the or through the fourth quarter. Any particular cause of concern there?

Yeah, I think, I don't get too worked up over real short-term trends. I was happy to see our market share rise up in 2019. I would say that we are remaining very disciplined on our pricing both for our rigs and for our ancillary services like automation. So, don't expect us to take use any tactics to kind of prop up market share. We will stay disciplined on the pricing for our super-rigs.

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

Maybe just following on the back of the Chris' question there. I think you had called out Appalachian as a source of some of the weakness in the U.S. rig count near term here. Do you feel like you've kind of taken your lumps at this point? Or do you have any visibility that rig count is going to stabilize there? Just general thoughts around that market this year.

Yeah, I think the short answer is yes. I think we've taken our lumps. I think we feel like we're pretty stable environment right now. I was actually expecting our rig count to be creeping up by now. But some of the jobs that we have lined up are just being pushed off with the commodity price right now. We mentioned Appalachian, and there was one other notable U.S. transaction that eventually resulted thus losing a few rigs.

Got it. That's fair. Maybe just pivoting to Canada here. What would you attribute the year over strength to? Is it the exemptions in conventional volumes? What's driving that substantial year-over-year increase?

Yeah, I discussed the regions, but didn't really say why. So I think, I talk first of all about Montney, Duvernay. I think the primary driver there is a strong natural gas liquids market where the pricing is remain firm. And that's because the natural gas liquids getting used as a diluent for heavy oil. And as the heavy oil projects, like oil sands projects get ramped up, the mining projects are increasing in scope right now. That demand for that diluent is remaining strong. That's, I think the primary driver of the Montney, Duvernay activity. That and a little bit of really work happening on the LNG project, which will come on stream in about three years time. And then, in heavy oil, and particularly stratifications drilling, we watched that business pretty much get turned off several years ago. And a lag of new SAGD wells, a lag of stratification work, a lag of heavy oil work that occurred in 20 – winter of 2017, winter of 2018, winter of 2019. And, listen, this is not a full rebound yet back to like 2015 levels, but, certainly is a little bit of a catch up going on right now in heavy oil. And I think, we were just well positioned with the right types of rigs. The ability to get those rigs fired up to have a leading market share in that area right now. And the indications to those customers are that the pace of Q1 won’t continue for the balance of the year, but we do expect heavy oil year-over-year to be stronger on a comparative basis. It's a complicated answer, but that's the answer.

Yes. Appreciate it. Appreciate it. I'll sneak one more in here, which is, have you seen that improvement in some of the heavier oil drilling support pricing for the smaller rigs? Or is that still pretty challenged?

We've got a rather unique position there in that. We've always been a large player in that space. I commented that our Super Single rigs are ultra-efficient. And we're able to get a -- what I call an acceptable day rate for those rates even with industry level activity levels being sold relatively light kind of long-term. But for the Super Singles rig, I'd say our pricing in heavy oil is that a raise right now that we're comfortable with.

Next question comes from the line of Waqar Syed, Autocat Capital. Your line is open.

Could you give us some numbers around how many of your rigs may be exposed to dry gas in Canada?

I think that we probably have the lightest exposure. I've recalled in recent memory. Because that activity is already running pretty slow. It's generally Southern Alberta, Southern Saskatchewan area where it tends to be a lot of competition. It's just an area we really haven't focused on before. So I don't see us having a lot of exposure there. The edge is 2 or 3 rigs, which is kind of why I expect the base will make up about.

Okay. And so the fee ST-1500 rigs that you have down. I'm assuming those are in the Marcellus area. Is that correct?

That's right. They are in the Marcellus right now. And we love to get those rigs back up and running given the right opportunity.

So would you consider relocating them to another basin? Or would you keep them in that basin?

Well, Waqar, since they're contracted for the full year, they're really under the control of the operator. So it's actually the operator of those contracts who decide whether or not they pay for the move. Certainly, wouldn't be at our expense.

Okay. Fair enough. And what -- $3 million per quarter, is that the right number for revenues from those rigs?

Waqar, that will be about right.

Our next question comes from the line of Taylor Zurcher with Tudor, Pickering. Your line is open.

Just a follow-up to the prior question on potentially relocating some rigs from basins like the Marcellus and others to stronger basins in the U.S. And that namely being the Permian from your competitors have talked about already doing that back by contracts. Is that something that you've already done over the past couple of months or something that you're considering doing moving forward, obviously, assuming that you get a contract to back stuff that movement?

Taylor, we have moved rigs in the Permian, earlier in 2019. We've actually moved some rigs around the basins in Permian, Eagle Ford, Texas and Haynesville. We’ve got some interbasin movement. I’d comment that if anytime we move, rigs are going to be backed by a contract period. And the cost of that move will be baked in the economics of the contract or paid upfront by the operator.

Would it be fair to assume that the pricing assuming it's ST 1500 would be better in the Permian than it is in some of the neighboring regions where we've seen rig count decline over the past three to six months?

As I said in my prepared comments, generally -- Marcellus aside for a moment, generally refunding pricing is pretty homogenous across the U.S. right now. And there is really more -- we have an ST-1500, which is kind of common with the U.S. 1500 rigs. We also have a little smaller ST-1200, which is actually quite common both in the DJ Basin and the Marcellus. It's a lighter, smaller, cheaper rig, but it offers almost the same vertical -- slightly shallower vertical but the same horizontal capability that’s necessary for both the Marcellus and the DJ Basin. And so we just see the differential rates between the 1500 and 1200. We don't see much differential between basins on 1500 horsepower rigs.

Okay, got it. Internationally, you talked about one rig in Kuwait that sounds like it at least go down temporarily here in the first half of the year, and then two more, which will be up for renewal at the end of the year. Any color on sort of the pricing dynamic for those three rigs relative to the current average revenue per day that you posted this quarter?

We're not -- I don't think we're giving you any negative guidance on what we're expecting for international business right now. I commented, we've done a very, very good job in Kuwait with these high-performance rigs that were all -- essentially all new builds with highly trained Precision crews who are actually doing a good job. We're drilling deep, high pressure wells. I don't expect to have any meaningful day rate, degradation on renegotiations.

Our next question comes from the line of Sean Meakim with JP Morgan.

So just kind of summarizing a bit of some of your comments. In Canada, it sounds like you're pretty confident you can grow revenues year-on-year just with the typical caveats around commodities and customer decisions coming out of breakup for the back half. International sounds like it could be getting better as well. Well servicing sounds pretty flat. U.S. is more challenging just given the exit rate, even if the outlook is relatively stable from here from rig count perspective. So we put that all together, is the suggestion that your revenue could be closer to flattish year-on-year compared to '19 if the year plays out as you see it today?

Yeah. So we would definitely -- I think your assumptions are pretty good, but we definitely would stop short on providing revenue guidance. The one comment I would add to your assessment of the U.S. market is that we have had a little bit of a customer churn, customer decision to lay down rigs, but these are the best rigs in the industry. These are all AC triples, and many of them have automation already installed. So we think the opportunity for us to add a number of rigs in a flat recount environment is pretty good.

Okay. Right. That's helpful. And then maybe just a follow-up on the Middle East discussion, as you get that fleet up and running and the counts look higher maybe than it has in recent quarters. Does that fixed cost absorption help you in terms of the margin profile for that segment?

Yeah. I would assume that the margin profile that we had in Q4 continues on into 2020.

But if we activate more rigs, there will be no further fixed cost or G&A additions. So it will be flow through the bottom line leverage in our sale. Correct.

Thank you. Our next question comes from the line of J.B. Lowe with Citi. Your line is open.

Just a quick follow-up on the workover rig that's rolling off now. You said you had a good line of sight to place it back to work in the second half. Will that be with the same customer in the same area or will that be moving somewhere?

I'm not going to comment in right now. We are involved in negotiations. And one rig, one customer, one country, it's hard for me to see too much publicly.

Fair enough. Okay. Just a question on the mechanics of the commercial position of the AlphaAutomation. Is the way that you guys get paid for the automation system like -- is it whenever the rig is earning a day rate, you're earning rate for the automation part of it? Or are you getting paid separately for when that's running?

So we're treating our pricing on automation and, for that matter, apps and automation as one of the la carte items we add to the rig, which is quite common. I know the day rate model is challenged by a lot of people that we don't capture all the value that we might give our operators. But what we do quite well is add capabilities to the rig. And we charge those as la carte item below the day rate for the rigs. So the rig can compete as a base rig, but if we added on, like in Canada, we’ll add boilers in the winter. We’ll charge for every day the boilers running. In the U.S. we might add a third shaker to the rig and we’ll charge for everyday the third shaker is running. In this case with automation we will charge every day the automation is running. So it won't run during big moves. We won't charge for that. But it will run the rest of the time.

Okay, great. Thanks for clarification. Last one for me is with Canada getting a little bit tighter here both in the heavy oil side and the NGL side, with all the rigs that have moved out of the area, do you foresee guys actually drilling rigs back into Canada? Would contemplate that?

I will make that answer really short, not a chance. I still think there's still a number of Canadian contractors looking to gain some U.S. exposure. But that's because I think they've got an asset mix, which doesn't really suit the Canadian market very well. In fact, some of the rigs have left the country which only doubles, which are no longer competing with us in the Montney and Duvernay because for these developments style drilling projects, pad-walking triple was simply the best answer.

Thank you. Our next question comes from the line of Ian Gillies with Stifel. Your line is open.

With respect to, I guess, the ERP implementation and how it's going to last a while. I'm just curious if there's much left you feel you can squeeze from that with respect to cost savings, and perhaps, tightening up working capital there help further improve the balance sheet?

So, Ian, that's certainly a focus we're always looking for ways to manage the business with lower working capital and to squeeze costs out of the business. I think most of that has already been achieved. But where we think we can really show the performance of that system is in an increased activity environment. We think that we're actually shown it in Q1 so far this year. The only people that we've added in terms of headcount have been people in the field working on the rigs. And we've increased activity 45% from where we were last year. So I think it is the same thing in the U.S. international as we add rigs and activity increases, we should be able to see fixed costs relatively flat.

Okay. That’s helpful. With respect to your, I guess, biofuel rigs, are you seeing any increased demand from your customers given the appeared focus on ESG? And if so, is there much in the way of economic opportunity right now in and around those rigs that can offer that service?

Yeah, again short answer, yes. We are seeing increased interest in biofuel rigs. I think the biofuel solutions are -- is a really good solution both for us and for the customer in that. It's a fairly modest upgrade to the rig, but does cut the carbon footprint dramatically for the rig and cut the costs for the rig. And I will make this comment, generally, most things our industry has done is only industry has been reduced to a content on the rigs, because fuels were the highest input costs in the drilling operation outside of labor. So in fact, have you just raced back over the last several years. I don't know that the industry is probably reduced its carbon footprint per meter drill, or any other industry that does anything on a regular basis.

And – are you seeing any – is there any intention, I guess to add any more kits this year? Or is that part of the upgrade CapEx at this point?

I think likely we will add more kits this year. I think at this point, we think we have enough capital inside our current budget to do that. But – and I think we'll charge extra for those rigs so that have been kit on there because there's value both for the customer and for us, economic value for the investor we make, and, of course, fuel savings value for them. So we'll make sure that we get paid for the investments. But there has to be a pretty good alignment of infrastructure, you have to have gas available. The gas has to be fueled grid gas. And we've got a rig, for example, in the Permian Basin we have rigs, where the gas is being trucked in. And while it's not an economic solution, there is a good environmental solution. But I think the best economic solution is where there's still gas available, you can scrub it completed application.

Okay. And last one for me, but, I mean, wells are still being drilled, folks, I know, again Peter focusing on free cash flow. But as you go out in market some of the rigs that have been laid down or you're looking for new customers, are you noticing any changes in, I guess, rig expects that producers may be looking for at this point in time that may require capital?

I know expect we have to do any meaningful upgrades the fleet to change. I'll give you my definition of super-spec or Precision’s definition of super-spec and that would be an AC digitally powered rig that had digital controls, so it's an AC rig. It's got a pad-walking system. So you can watch X and Y and all directions of the pad. It has three mud pumps and 7,500 PSI capacity. It’s got hoisting and rocking capacity to drill out 10,000 foot laterals. I think we have adequate number of regional fleet right now to service the demand that we expect unless there's some meaningful change in the commodity fundamentals upwards.

[Operator Instructions] Our next question comes from the line of Blake Gendron with Wolf Research. Your line is open.

I wanted to start in the U.S. here. We haven't really seen a flattish rig count, the expectation of the flattish rig count for the foreseeable future. I was wondering -- I'm just getting some of the pushback that we've gotten from investors on where day rates could go from here theoretically in a flat rate can environment even some of the supers-specs here maybe get a little bit more predatory on pricing. Where would you pushback, I guess, on that sentiment? And then, flipping of the cost side, you mentioned doing some things on the fuel side, but anything on the labor side or elsewhere in OpEx so you can kind of pull levers in terms of flattish rig environment, maybe getting a little bit more juice on the margin? Thanks.

Yeah. So I think, first off, flattish overall industry rig count environment. I still think there's -- I think the numbers in the 200 to 300 range, number of rigs that would be hydrated. And that's rigs are operating right now replaced with better quality rigs that can drill quicker, safer, more efficiently. So I expect that the demand for super-spec ratio continue through the balance of the year as customers operating lower quality rigs, upgrade those to higher qualities – high quality rigs. And we know that even in case of one super major right now, just looking at reducing their contractor count dramatically, that's a high grading exercise. They were going to picking higher grade rates. So we think that's going to drive demand on super-spec rigs. But beyond that, there's no question that we are delivering measurable real value without AlphaAutomation. We think that further enhances our ability to differentiate the Precision rigs. So we think that will drive our market share independent of overall rig counts. So I do see a clear avenue and clear path to get additional revenue per rig with automation and additional market share with automation. So I think we have two clear growth vectors that are independent of rig count. But I think that it's logical to expect there to be high grading of lower-quality, lower-performing rigs in the industry right now. We've seen that over the last 18 months. We'll see it again for next 12 months.

Okay, that's helpful. And then just seeing your Alpha comments and turning to directional drilling -- integrated directional drilling is something that you've implemented for a while now, any sort of customer preference now that we're overlaying the digital side on sort of a bundle package and the importance, I guess, from the drilling perspective to have original drilling capabilities in-house? Are you seeing any major changes in the marketplace there?

Well, we still have directional drilling capabilities in house in the U.S. and Canada. It’s something that we continue to focus on. However, the directional drilling industry is still quite challenged. And what we're finding is that the competitors have been highly pressured space continues to drive price down, which is attractive for the operators. And, I commented that there's a cost of switching drilling rigs. It's interesting, often, when operators change directional drilling contractors, there's no cost or could even be a cost benefit to them to switch. They can, sometimes get somebody to come in and replace the existing contractor mid hole and save money. So that he could view it as a negative cost to switch. And I think that dynamic is making the directional drilling business still rather bumpy. Ultimately, if we sit back and look in five years time, I think that the rig software will dictate directional drilling. But I guess, it is going to be a transition period. And I think we need to see the directional drilling business really kind of take it on the chin for a while before that's going to take rigs. And that's happening right now.

Got it. And then one more thing squeeze it in. You mentioned the debt reduction targets for this year, you upsize the four year reduction target to $700 million. You've been opportunistic about the buyback. If we do see upside to what we're modeling in terms of free cash flow for 2020, where would you suspect you deploy that to operations? Would you continue to buy-back shares? Or would you allocate any excess cash flow to debt paydown?

Yeah. I think we look at all of those opportunities. It depends if there are good economic opportunities to deploy upgrade capital at good contracts. That would probably be our first preference after debt paydown. Then after that, we’d look at where our bonds are trading in the open market and where our shares are trading and see if it makes sense to deploy excess capital to one of those spaces. So I think we're in a pretty good position with having strong free cash flow. We have some options on how we can deploy that cash.

Thank you. At this time, I would now like to turn the call back over to Dustin for closing remarks.

Thank you for joining today's call. And look forward to speaking with you when we report our first quarter 2020 results.

Ladies and gentlemen, this concludes today's conference. Thank you for participating. You may now disconnect. Everyone have a wonderful day.