Calfrac Well Services Ltd.
Q4 2020 Earnings Call Transcript

Published: 4 Mar 2021

[Operator:]

Ladies and gentlemen, thank you for standing by and welcome to the Calfrac Well Services Limited Fourth Quarter 2020 Earnings Release Conference Call. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. [Operator Instructions]. I'd now like to hand the conference over to your speaker today, Mr. Scott Treadwell, Vice President of Capital Markets and Strategy. Thank you. Please go ahead.

[Scott Treadwell:]

Thanks. Good morning everyone and welcome to our discussion of Calfrac Well Services fourth quarter and full year 2020 results. Also on the call today are Lindsay Link, Calfrac's President and Chief Operating Officer; and Michael Olinek, our Chief Financial Officer. This morning's conference call will be conducted as follows

[Lindsay Link:]

Thanks, Scott. Good morning and thank you everyone for joining our call today. Before Mike summarizes our financial position and results I'd like to offer a few opening remarks. As we expected the fourth quarter was a continuation of the improved activity levels seen in all our geographies from the third quarter, specifically in Argentina, where a large shale fracturing fleet went to work and added significant revenue stream to our businesses there. Outstanding performance continued in Russia and we also saw a better performance in North America including the addition of incremental fleets ahead of schedule in our United States operations along with a robust finish to the year in Canada. At a corporate level, we successfully closed our recapitalization transaction in December and saw changes to our board of directors. This process has been very complex and lengthy and I'm proud of the work put in by our team and grateful for the assistance of our advisors and the support of our stakeholders. I want to also specifically acknowledge our employees. Despite so many potential distractions over the course of 2020, our performance in the field continued to improve and as a result Calfrac achieved record safety performance for the second year in a row and delivered further reductions in non-productive time. This excellent result is due to the hard work and dedication of our field employees and operational leadership and I can't say enough about the quality of our team. The improvement in commodity prices over the latter part of 2020 enabled most producers to contemplate improved spending and activity levels for 2021. While announced budgets do not indicate significant production growth, even modest improvements in activity along with a return to more balanced pricing for our services should deliver notable improvements in our financial results for the year ahead. Now I will pass the call over to Mike, who presents an overview of our quarterly financial performance.

[Michael Olinek:]

Thank you, Lindsay. And thank you everyone for joining us for today's call. Our fourth quarter results increase significantly as compared to the third quarter as activity improved in all of our operating areas. These higher activity levels particularly in Argentina also resulted in an increase in operating margin despite no change in pricing. Consolidated revenue in the fourth quarter decreased by 43% year-over-year to $180.7 million primarily due to lower activity in North America offset modestly by higher revenue per job in Canada due to the mix of work. Adjusted EBITDA reported for the quarter was $13.7 million compared to $26.9 million a year ago. Operating income was down 26% to $15.6 million from $21 million in 2019. These weaker results were driven by lower activity and pricing in North America although significantly improved financial performance in Russia partially upset this decrease. The net income for the quarter was $125.9 million compared to a net loss of $49.4 million in the same period of 2019. This change was driven primarily by a gain on the settlement of debt of $226.3 million partially offset by a deferred income tax expense of $54.2 million, both the result of our recapitalization transaction which closed in December. For the three months ended December 31, 2020 depreciation expense decreased from the corresponding quarter of 2019 by $38.1 million to $30.8 million. This decrease was driven primarily by $227.2 million impairment to PP&E that was recorded in the first half of 2020 as well as lower levels of capital spending on items with shorter useful lives and corresponding higher depreciation rates. Calfrac spent a total of $44.6 million on capital expenditures in 2020 which also included a portion carry forward from our 2019 capital budget. In December, 2020 Calfrac's board of directors approved the company's 2021 capital budget of $55 million. As always, we will monitor industry conditions and adjust our capital spending as needed. Working capital grew sequentially by $52.3 million due to the significant increase in revenue seen over the third quarter. This growth in working capital was the primary driver of the reduction in total cash on hand of $10.3 million, but was offset by improved operating cash flows and the cash impacts of our recapitalization transaction. The final settlement of transaction costs related to the plan which totaled $27.1 million also impacted consolidated cash balances as well as the $35 million reduction in credit facility borrowings. Calfrac's completed recapitalization transaction significantly improves the company's financial position and lowers its debt service costs. Total long-term debt was reduced by over $550 million relative to the end of the third quarter as the company's senior unsecured notes were exchanged for common shares. Based on the Calfrac's debt balances at the end of 2020 combined with that current forecast and expected exchange rates Calfrac's cash interest costs are expected to total approximately $32 million in 2021. It is important to highlight that this amount includes $6 million of interest expense related to our 1.5 lean notes which can be paid in kind at the discretion of the board. Concurrent with the closing of our re-capitalization transactions a number of amendments to Calfrac's revolving credit facility were enacted. The total facility capacity was reduced from $375 million to $290 million and the waiver from the funded debt bank EBITDA covenant was extended until the end of the second quarter of 2021 with the relaxed covenant in place until the end of the year. To summarize the balance sheet as that December, 31 the company had working capital of $128 million including $29.8 million in cash. At December 31, 2020 the company had used 0.8 million of its credit facilities for letters of credit and had 130 million of borrowings under its credit facility leaving 159.2 million in potential borrowing capacity at the end of the fourth quarter. As at December 31, Calfrac was in full compliance with all of the covenants that are currently enforced during the covenant relief period. I would now like to turn the call back to Lindsay to provide our outlook.

[Lindsay Link:]

Thanks Mike. I will now present an outlook for Calfrac's operations across our geographical footprint. As expected reduced oil supply over the second half of 2020 has significantly eroded surplus inventories. With accelerating vaccine rollout in most developed nations, the prospect of normalized demand has shifted focus to inventory depletion and a need to reverse supply curtailments. This has also caused oil prices to increase to levels that could support growth spending by many of our clients. At this stage we do not expect to see material upward revisions to existing budgets or significant growth in spending in North America. The focus on capital discipline and free cash flow generation remains consistent in the producer community. However, I would expect to see inflation due to input costs as well as service pricing generally impact capital budgets as 2021 unfolds. Natural gas fundamentals remain solid aided by the severe cold weather in February that drove significant withdrawals from storage in North America and resulted in price spikes in a number of global natural gas hubs. Given its energy density and impact on emissions relative to coal or other thermal energy sources we believe natural gas can provide significant benefits to our society for decades enabling developing nations to accelerate economic activity using low-cost reliable energy while permitting a significant reduction in emissions intensity. Calfrac's operations in Canada and Argentina have significant exposure to natural gas activity and our flexible footprint in the United States and Russia permits us to deploy our assets to respond to shifts in market activity that may occur in the years ahead. Much has been written and spoken about pricing in our industry and the fracturing sector specifically. As the past is just past and assigning blame is a bit pointless, I prefer to focus on the future. It is pain to see that pricing for our services remains unsustainable in any sense of the word. Service companies have enacted significant cost reductions but a number of those changes like benefit reductions cannot be maintained indefinitely. Our industry has also delivered significant improvements in productivity and partnered with our clients to better understand and develop resources. The value of our industry has never been higher in terms of what our customers receive and yet the pricing is still challenged. Our core values at Calfrac are honesty, commitment and resilience. I'm being honest when I say that despite significant structural cost reductions in our industry current pricing does not permit long-term investment and so its continuation is not acceptable. I am making the commitment to work with our clients to find pricing and service structures that recognize the financial realities of our industry by sharing both the risks and the rewards of what we do. Finally, while I know many will have strong opinions on the economics of our industry I know Calfrac's resilience will enable us to work with our partners to find the best possible solution. In our U.S. division, the quarter delivered ongoing improvement in activity. Our original projection was to return to seven active fleets by early in 2021. However, that plan was accelerated due to the needs of a number of key clients. As a result, while activity and revenue exceeded our estimates margins were impacted by the restart of fleets during the quarter. We have seen continued interest from clients for further equipment within our U.S. operations particularly in oil focused areas. At this point, I do not expect to add significant equipment to our footprint as the economics did not support such steps. If activity levels continue to increase, I would expect incremental tightness in the U.S. marketplace which should further improve pricing for our services. At that point it may be prudent to consider targeted equipment reactivations but our focus in the near term will remain on increased utilization and profitability of our current active asset base. We expect to see operating levels near breakeven level in first quarter as weather impacts in the United States were severe in most of our operating basins, characterized by delays and unforeseen costs as well as fewer stages per day for periods of up to a week for several crews. Based on our fleet disposition and frac calendar, I would expect profitability to improve beyond the first quarter. In Canada, we saw a strong October followed by a weak November and a solid December. This volatility impacted our results as our cost structure cannot respond effectively to month to month revenue changes that approach 50%. However, our team performed well in managing this challenge and delivered good results overall. As the fourth quarter completed we completed reactivation of the fourth crew for the busy winter period without significant costs. To-date operations in Canada have been strong through the first quarter despite some minor impacts due to the extreme cold weather scene during February. All four crews are fully booked through the end of March and into April. And while we expect to slow down inactivity in the second quarter, our expectation today is that Canada will remain profitable in this lower period due to the work programs of some clients that focus on larger pad completions during breakup. Our visibility remains limited for the second half of the year outside of our core clients, but based on what we know and current commodity prices we expect activity levels to be strong through the summer and fall. At the current time we do not expect to add any fracturing capacity to the Canadian market as our current footprint is sufficient to service our long-standing relationship customers, and spot market pricing does not currently compensate for the more variable utilization experience in that market segment. Our Canadian team will continue to monitor the marketplace and Cwill as always be ready to deploy incremental assets should the right conditions appear. I will take a minute now to cover Calfrac's international operations. In the fourth quarter our operations in Russia continued a run of strong performance. Although the onset of winter conditions did impact results marginally improved job mix and more consistent access to our clients operating areas are the primary reasons for the improved results. Although the prudent cost management of our team there is also worth noting. Wind conditions have impacted our ability to operate in the first quarter with almost two weeks lost to cold temperatures to date. While we expect revenue in Russia to be close to flat on a sequential basis, this cold weather will impact margins significantly relative to those posted in the fourth quarter. In spite of these seasonal challenges, Russia should remain profitable during the first quarter, and we expect to see a return to stronger margins in the second and third quarters of the year as volumes are forecast to remain robust. Our operations in Argentina completed a full restart during the fourth quarter with our large shale fracturing crew going back to work in Neuquén [Ph]. There are some remaining pieces of equipment that can’t go back to work but for the most part our operations in Argentina are back to full operating capacity. So incremental improvements will come from utilization and efficiencies. Work volumes in the first quarter have been slightly below our expectations but largely consistent with the fourth quarter. The change in job mix in gaps in the schedule are also expected to impact profit levels during the first quarter, but like Russia we expect to deliver positive operating income in Argentina in the first quarter with further improvements in the remainder of the year. The federal government in Argentina recently enacted policies designed to incentivize the development of natural gas resources in the Vaca Muerta field. These policies are expected to drive higher levels of activity than we witnessed in 2019, which should further improve the performance of Calfrac's operations in Argentina. As with other geographies we do not expect to add significantly to our footprint in Argentina without appropriate risk adjusted returns. There is also a good time to speak about Calfrac, how Calfrac is addressing ESG issues and how we plan to improve. I want to make it clear that in our eyes ESG performance does not start or stop with Co2 emissions. We have and continue to invest in technology that will improve our emissions profile, but there is much more to our approach than that. We have materially improved our safety and operating performance so that we are now regularly achieving 98% operating efficiency meaning our idle time and the missions associated with it are reduced. We continue to examine new technology from power generation to pump design and auxiliary equipment with a view to delivering a more capital efficient operation that delivers improved performance at a lower environmental impact. One final word, the greatest strength of Calfrac is our people and from our pump operators to our support and administration staff to our leadership team, I am consistently impressed by what we do and how we do it. But most importantly, I'm proud of who we are. With that I returned the call back to the operator for questions. Thank you.

[Operator:]

[Q - Taylor Zurcher:]

Hey thanks and good morning guys. My first question is on Argentina, obviously a really strong performance there in Q4. It sounded like the guidance you gave for Q1 you pointed to still positive operating income, but if I heard you correctly there's some gaps in the schedule which is going to dent the profitability a bit. Could you just provide a bit more color on what's going on there in Q1 and then more importantly for kind of the Q2, Q3 period? Do you expect to be able to sustain that mid-teens level of operating income margins that you did in Q4 looking beyond some of this noise in Q1?

[Lindsay Link:]

Good morning Taylor. Thanks for the question. The Q1 performance is is really due to working for one client and then switching to another client. That's a full-time fleet allocation client and it just had some down time during the switch as well as startup operations on these major shale fleets. These are not from our side just the whole operation. It's the same as an American operation. So very intense and you have to get all the supply chain pieces working there. So a little bit of gaps that have occurred but we are now in full operational mode. March should be an exceptional month for the Argentine guys both in Baccamorte [Ph] and then in the South. Scott I don't know if you wanted to answer that the second part of Taylor's question?

[Scott Treadwell:]

Yes. Sure Taylor. I think Lindsay did a great job talking about Q1. As we see activity kind of normalize, while we don't provide any guidance we don't see any big potholes in the road. So you would expect things to kind of normalize but our business can be a bit of a surprise factory. So lots of stuff can change that but we're pretty happy with the operating footprint and the cost structure as it sits today.

[Taylor Zurcher:]

Understood. A follow-up on the U.S. market. Lindsay you talked about how pricing is obviously down in the dumps right now and one of your focuses is trying to work with your clients customers to figure out some new pricing structures that help you both share in the risk and reward and it seems to be a refrain. We hear a lot during downturns but coming out of these downturns nothing really seems to change. So I was just curious if you could help us think about what you're focused on when you're talking with customers around pricing and there is any sort of creative structures that you're thinking about or hoping to implement moving forward?

[Lindsay Link:]

Thanks again Taylor. It depends on what basin you're in and what client you're with. Some are very straightforward pricing discussions and even improvements that we've had in the recent past. Places where you've had cost increases are quite they're quite straightforward to talk to the client and kind of show where you are and why you may need a pricing increase. Where you haven't seen that though is where you haven't had that cost inflation but yet the margins aren't satisfactory for long-term continuation of a operation but we've had good success with those guys. It probably helps when they are have a significant uplift in their revenue and for the most part because the service quality has been so well the guys like who we're working for we like they like us. I think they've been received a lot more positive than maybe even in the past of 2017 say where we had those kind of price increases. I think there's a genuine acceptance that pricing has to recover for the pressure pumping business in order to do what we do which is still I think one of the most important parts of the completion operation.

[Taylor Zurcher:]

Got it. I'll sneak one more in for 2021 in terms of your free cash flow outlook, I know there's a lot of moving pieces and certainly some utilization noise in the first half of the year but you've got about $30 million of interest expense $55 million of CapEx is the budget. Now under that sort of scenario do you expect to be able to generate some positive free cash flow in 2021? I guess working capital would be the other available getting you to the free cash flow number but do you think you can stay positive in 2021 or is it just a bit too soon to make that call?

[Michael Olinek:]

Hi, Taylor it's Mike. Good morning. Yes as far as what we're modeling ahead for the year ahead we're certainly mindful of all the cost drivers that you've talked about. And I think given our present expectations we're certainly driving towards positive free cash flow for the year. We know it's going to be something that we have to manage and really the biggest driver is the working capital and really how that fluctuates will likely be the largest driver. The other two I think we're safely believing that we can manage through and generate positive cash flow, but the working capital might be the one outlier but we're hopefully to be neutral to positive as we get through the year.

[Taylor Zurcher:]

Understood. Thanks for the answers guys.

[Michael Olinek:]

Thanks, Taylor

[Operator:]

Your next question comes from a line of Cole Pereira from Stifel. Your line is open.

[Cole Pereira:]

Morning everyone. So there's been a lot of commentary on pricing in Canada and Q1 largely just that it was flat sequentially. Wondering if you're just able to comment on if it was flat as well in the U.S. or if it was maybe down a little quarter-over-quarter acknowledging some of the messiness from the Texas storm.

[Lindsay Link:]

Good morning Cole. The pricing on the U.S. side we have had some price improvement. It's late in the quarter I mean we're already in March. So we do have some improvements taking place in there, but there is a lot of noise I guess with the winter weather and in addition we're moving a fleet from a less profitable climate up to what we believe is a more a better margin area and so that will also have a little bit of cost impact without an associated revenue. But we do have some positive improvements in there and you're right on Canada most of the work is pre-called in the fourth quarter so the first quarter is generally speaking flat.

[Michael Olinek:]

Yes Taylor the only thing I would, sorry the only thing I'd add to that Cole would be that Q1 was so fully booked for us that we didn't have opportunities to step into the spot market to move pricing higher. I know we were certainly have been looking pricing where we can but as Lindsay said your your Q1 pricing was largely set in the fourth quarter and I think we did our best to hold the line and then look for areas of improvement but there really hasn't been much. I would expect to see if pricing was going to move that it would do so coming out of spring breakup because you again you've largely got a lot of your work for the second quarter fixed. There is input cost inflation that's a different driver but I think kind of net pricing improvement is probably a back half where it shows up in the results.

[Cole Pereira:]

Okay. Got it. That's helpful. Thanks. I'm just wondering as well are you able to differentiate it all on the volume of customer inquiries you're seeing for bio-fuel equipment between the U.S. and Canada?

[Lindsay Link:]

Differentiate I'm not sure I fully understand what you're looking for there is a lot.

[Cole Pereira:]

I'm just wondering if you're seeing perhaps more biofuel inquiries in the United States versus Canada or vice versa on a relative basis for your fleet size.

[Lindsay Link:]

Okay. In relative terms we are more bio-fuel equipped in Canada then the U.S. So we can handle a lot more inquiries for bio-fuel in the Canadian market just because of our number of pumps that have already been converted or being converted. In the U.S. of course we have a lot more horsepower. So we we're operating or going to operate the bio-fuel fleets. It depends for additional ones it really depends on the cost. And so it is a cost area and of course bio-fuel by itself is only one answer. There are places where tier two diesel is actually an environmentally better footprint than even a tier two diesel bio-fuel pump. So different clients on different places will be looking for again different sets of equipment.

[Cole Pereira:]

Okay got you. That's helpful. Thanks. That's all for me. I'll turn it back.

[Lindsay Link:]

Thanks Cole A - Speaker

[Michael Olinek:]

Thanks Cole

[Operator:]

Your next question comes from a line of Keith Mackey from RBC. Your line is open.

[Keith Mackey:]

Hi, good morning. Thanks for taking my questions. Maybe if we could just stay on that dual fuel line of questioning with the 5 million you look to spend this year can you just give us some context on where in North America you plan to utilize that and will this be for fleets that are currently operating in the field or will this be additions to equipment that is not operating?

[Lindsay Link:]

Thanks Keith. It's a great question. Most of it is divided almost maybe two-thirds in the U.S. one-third in Canada. It's on existing fleets to give them more ability to deliver bio-fuel today and of course I think we've all seen this is on existing equipment because of the conversion for that amount of money I can do many pumps to make them bio-fuel whereas on a tier 4 dual fuel unit that basically would get you two units. So obviously we can impact fleets with the conversion as opposed to buying new equipment.

[Keith Mackey:]

Got it. Okay and can you just remind us I guess of the amount of bio-fuel horsepower you'll have available in total after you do these upgrades?

[Lindsay Link:]

Yes Keith it'll get towards 75% of the Canadian fleet so think of that as about 200,000 horsepower maybe a little bit less 175 that'd be dual fuel capable and in the U.S. I think it'd be just the three fleets so maybe just a little over 150,000. You could reconfigure that if you had some smaller and maybe get to four fleets but really it would just be three of your fleets. So the way it sits today call that about 40% of our operating capacity and again we would continue to look at that the economics of it, the customers particularly the logistics of it and see where it makes sense. I think on the dual fuel side in the U.S. because the basins are so geographically separated you've had to rely on third-party fuel delivery which blunts a lot of the cost savings that natural gas can deliver to customers but I think as that infrastructure grows for kind of in-field gas treatment and potentially the use of field gas or low processed gas there's definitely options for dual fuel to be economic not just for the client but for the service company as well.

[Keith Mackey:]

Got it. Thanks for that. And one last question for clarification Lindsey when you said break even operating income in Q1 that was specifically the U.S. that's not for the enterprise in total. Is that correct?

[Lindsay Link:]

Yes. That would be correct.

[Keith Mackey:]

Okay got it. Thanks. That's it for me.

[Lindsay Link:]

Thanks Keith.

[Operator:]

[Operator Instructions] Your next question comes from a line of Waqar Syed from ATB Capital Markets. Your line is open.

[Waqar Syed:]

Thanks for taking my question. Good morning. I got cut off in between so apologies if I ask a question that you may have already answered but first question like we've seen some consolidation amongst the EMP companies both in Canada and the U.S. how is that impacting Calfrac?

[Lindsay Link:]

So I'll hit on it in Canada that's the easy one. It's been a universal positive we're quite lucky that the history of our company has aligned us with a number of really high quality EMPs. They tend to have pretty smart capital allocation policies. They tend to have pretty good balance sheets and they tend to take a long view of our industry and so that's resulted in them being the acquirers in a number of situations. There is been a couple where we've been on kind of both sides of it and I won't say that we've been the sole beneficiary by any means. I think it's benefited the larger players as you would expect but it's definitely been a positive in the Canadian marketplace. I think in the U.S. it's probably still a bit more of a work in progress. Obviously we're more focused in North Dakota, Pennsylvania and then Texas I guess would be up there as well. I would say North Dakota you've seen a little bit of consolidation. Our customers really haven't been involved in that too much but again what I would say is consolidation is a net positive for the service space if you are a better than average provider kind of top quartile type provider and we certainly feel we are. Texas we're a small player in that market. So I would I would say at this point consolidation it's not like getting hit by lightning by any means but I don't think you're going to see consolidation materially affect our operations in Texas relative to the larger market. As I said you may have a customer who we start to work for and they get bought and that doubles our work volume or drops the work volume to zero but it would be tough to kind of predict that today. Q - Waqar Syed Okay. Great. Now in the U.S. what's your maintenance CapEx per crew running at right now?

[Lindsay Link:]

For crew? It would be -- it would be around 3 million, 4 million that would be Canadian per year per fleet and that would, it'd be a little bit less than that in Canada because really only about two thirds of your equipment is running in the high intensity areas but obviously all of it can. So that's probably a decent place holder for the North American business call it three to four and then the rest is a little tougher to kind of model the international stuff.

[Waqar Syed:]

So in the U.S. that C$3 million to C$4 million Canadian does that include fluadence [Ph] as well or that's outside of that number?

[Lindsay Link:]

No that includes [Indiscernible]

[Waqar Syed:]

Okay. All right. That seems a very low number when we look compare that to the industry in general. What are you guys doing that others are not that leads you to have well below industry standards maintenance CapEx because the lowest we're seeing is about $3 million U.S. and that excludes [Indiscernible]

[Lindsay Link:]

Right. I think what our guys have done an exceptional job in holding back capital expenditures on maintenance over the last three quarters and the fourth quarter it's okay. It's not as good as the last three quarters. I'll definitely that but they are doing a much better job on major component failures in there. Some of that though probably is where we are working. So if we're not at the very far end or tight end of high end of the capacity of the units that's having a positive effect. So some of the Permian especially some of the South Texas is pretty high rates and quite high pressures which when you have a failure it's typically a catastrophic failure which means you have a high expenditure. So I think a little bit is our diligence. I'm sure some of the guys would say it's there they have all to do with it, but the other part is I think we're pumping in easier areas.

[Michael Olinek:]

And Waqar just to add to that I think part of it is a little bit of apples and oranges. Obviously we do think about things in terms of our RMN expense and then capital outlay on components but given the way we report and kind of construct our finances really the only thing that flows through capital are the pieces of iron, the engines and transmissions, power and fluid ends there is an ability in U.S. accounting to capitalize some of the associated expenses with those components. We don't do that and so as a result you would see typically even if we spent the same dollars total on R&M that our CapEx would be lower but that our maintenance cost might be a little higher and as a result your EBITDA might be a little lower. So there is a little bit in there but I would say that by far the biggest delta would just be we treat the pumps properly.

[Waqar Syed:]

That makes sense. Thanks. Thank you for the answer. And just one final question you mentioned that you saw a little bit of a price pick up in the U.S. on the pumping side. Now is that kind of net price increase or is it just a pass through of some input cost inflation?

[Lindsay Link:]

It's a mixture of both but I would argue and I'm sure Mike agrees with me we're already eating the cost. So and we typically are behind in a cost improvement or a price improvement. So therefore it's you would almost have to say it's a net improvement because if the cost went up in January but I don't get the price improvement in until April is that a net price improvement or not I think it's a net in that way but I know what you're talking about and that's what we're working for is obviously net price improvement.

[Waqar Syed:]

Thank you very much. Thank for your answers.

[Lindsay Link:]

Thanks Waqar.

[Operator:]

Your next question comes from a line of Jeff Fetterly from Peters &Co. Your line is open.

[Jeff Fetterly:]

Good morning guys. On the CapEx side the $55 million budget announced does that contemplate or include any capital for additional crew reactivations?

[Lindsay Link:]

Yes Jeff. There is a little bit in there. So if you had a large pickup in activity in the fourth quarter it is possible that the CapEx would increase in there but we can handle what we've budgeted for inside our capital budget.

[Jeff Fetterly:]

And so what would the approximate cost be if you were to reactivate an 8th, 9th or 10th crew in the U.S.

[Lindsay Link:]

The cost right now I mean it does depend on a little bit of where it is because this time when we idled equipment we idled in the basins to a large extent. So some equipment will cost more than others but on an average probably a million dollars is a reasonable number. It is possible that it could go up to a million and a half with about a 50/50 split between R&M and capital. Just to do see oil changes some hoses and such that's all R&M but it's a lot right when you start talking 20 frack pumps and probably 20 other pieces of a kit and tractors. So you get a large maintenance hit and then you have the potential for some capital spend as well. That's without making it a bio-fuel.

[Jeff Fetterly:]

And the bio-fuel upgrades that you're doing are they all tier 2 kits?

[Lindsay Link:]

Yes. Right at the moment I mean it's very few tier fours that can be converted to bio-fuel because to touch a tier 4 you have to have 8,000 hours on it according to the EPA.

[Jeff Fetterly:]

Right. And so you seeing any pricing differentiation between diesel and bio-fuel either on the Canadian or U.S. side?

[Lindsay Link:]

We haven't seen that in the past. We should see it though Jeff by right that it's a capital expenditure. There is a savings on the input cost which is there but it has mainly in a low period of activity become an expectation rather than an ability to improve pricing. Prior to the downturn when we did buy fuel we did see a pricing premium but unfortunately when you dropped 300 fleets in the U.S. that benefit went away but it's a cost. That's part of that structure that I'm talking about that the money we spend has to be recovered somehow and whatever you're spending it it has to have at least an acceptable level of return.

[Jeff Fetterly:]

On the U.S. side what do you need to see to be comfortable reactivating additional equipment either from a pricing standpoint and/or from a utilization component?

[Lindsay Link:]

Jeff I think you you hit the points. We need to see it well utilized. We don't like activating on the spot market in the U.S. It hasn't worked well for us in the past. Maybe it works for some other people. So we want length of time something where you've got a couple thousand stages that you're going to be doing and then we would expect to see obviously especially from our fourth quarter results we need margin improvement in there. It's not that you need it all at one time but you have to have the expectation one that there's a step up and then that there may be a benefit further on. The client also has a lot to do with it. An efficient client can make your profitability night and day much like what we'll probably see with some of the weather related downturns. Those downturns cost the service company a lot of money. You've got whatever 60 - 70 people tied up that really aren't earning revenue and an inefficient client will also have that same effect on it. So we look at that as well.

[Jeff Fetterly:]

Thanks. Appreciate the color.

[Lindsay Link:]

Thanks Jeff.

[Operator:]

Your next question comes from a line of John Gibson from BMO Capital Markets. Your line is open.

[John Gibson:]

Good morning guys. Thanks for take my call. Just first one in Argentina, I'm wondering if you could give a magnitude of one time reactivation costs in the quarter?

[Lindsay Link:]

For like fourth quarter?

[John Gibson:]

Yes. It's for the fleet that went back to work.

[Lindsay Link:]

Yes. it wasn't terrible. It's a little bit different than in our other areas because we were shut down for almost six or seven months in Argentina but the startup went very well. The guys have a very reasonable set of equipment especially in the Vaca Muerta fields the South is relatively small and those startups are very nice to have because they just start and they start working and the improvement is seen right away but on the crew one the biggest the largest startup cost was probably bringing on people and getting them familiar with actually working shifts seven days a week again but I don't have a great handle on it I think it. It probably would have amounted to maybe 10% of the revenue that would have been kind of eaten up we wouldn't have been as efficient. So that I'm going that we were much more efficient now. We know that because of the number of stages that we are pumping. So today we're probably 30% more efficient than we were in the fourth quarter.

[John Gibson:]

Okay. Great. Just turning to Canada and specifically pricing. Some of your peers have noted an expectation that pricing could increase in the back half of the year. I'm just wondering if you share these thoughts and if so will this be dependent on operators holding the line in terms of activating additional fleets?

[Lindsay Link:]

Yes. I think that's exactly it right like you've got customers for the last I would say three to four years really haven't had to adapt plans or change their plans based on the availability of equipment in the services space and that's not just fracturing. That's pretty much everywhere. If customers if Calfrac is sold out because we decide to hold the line and don't reactivate anything more and customers know that there's one or two other providers that do have some spare equipment. Even if they're not their primary provider or preferred provider they're going to use that in the discussion and some of them may go to that person with spare capacity. Some of them may stick with you and try to work and get something out of you or find a hole in your calendar but I think as an industry we need to hold that discipline like our customers are doing. I mean you've seen our customers adapt very quickly to this new reality of focusing on returns, developing your inventory at a reasonable pace and generating free cash flow to the operations. It's not a complicated recipe and I just think that the service space needs to essentially copy it. If we get too far in front of activity by having equipment ready to go which Calfrac and everybody has been guilty of in the past we blunt the argument of needing to get higher pricing for our equipment and for our services. So it's a fine line and it's something that you have to balance because you've got relationship clients that quite rightly expect you to be there for them as a partner and then you've got clients that are maybe more transactional and then it's a bit more of a spot market conversation. So it's not one size fits all but at the core of it has to be disciplined.

[John Gibson:]

Okay. Great. Appreciate that. Last one for me just staying in Canada can you talk about your revenue split between the higher intensity money during areas versus the [Indiscernible] Bakken and both specific to Q4 as well as we look out into 2021?

[Lindsay Link:]

Yes. I mean the money for us is very important. So probably into that 70% range I think is a good number to use. Obviously it changes from month-to-month or quarter-to-quarter but it is the big heavyweight in it for sure.

[Michael Olinek:]

Yes and I wouldn't expect that to change here in the first quarter. We went to the fourth fleet which was really dedicated to focus on the of -- viking type areas. So if you did the math that's kind of 75/25 and then as you get into the second quarter it probably moves a little higher because obviously during breakup you're not going to be doing much off pad work. There will be the odd single well here and there but through the second quarter it's probably more like 85% or 90% Monty Duvernay intense deep basin type stuff.

[John Gibson:]

Okay. Great. And I'll turn it back. Congrats on the strong quarter.

[Lindsay Link:]

Thanks John.

[Michael Olinek:]

Thanks.

[Operator:]

And we have reached the end of our question-and-answer session. Mr. Scott Treadwell I turn the call back over to you for some closing remarks.

[Scott Treadwell:]

Thanks Rob and thanks everyone for joining us today and for your questions. We look forward to updating you at the beginning of May when we report our first quarter results. Just as a reminder the management team here in Calgary will all be around today. So if there are follow-ups that the analysts or investors need to run to ground please feel free to reach out. Thanks very much.

[Operator:]

Ladies and gentlemen this concludes today's conference call. Thank you for participating. You may now disconnect.