Q1 2021 Precision Drilling Corp Earnings Call
[music].
Yeah.
And ladies and gentlemen, thank you for standing by and welcome to <unk>.
Uh-huh drilling Corporation 2021 first quarter results conference call and webcast.
This time all participant lines are in a listen only mode.
After the speaker's presentation, there will be a question and answer session to ask a question during this session.
Tier one and your telephone.
Yeah.
Todays conference and Macquarie.
If you require any further <expletive>istance. Please press star zero and I would now like to hand the conference over.
And that's been calling director of Investor Relations and corporate development. Thank you. Please go ahead Sir.
Thank you Denise and good afternoon, everyone welcome to precision Drilling's first quarter 2021 earnings conference call and webcast participating.
Participating today on the call with me are Kevin nephew, President and Chief Executive Officer, and Carey Ford Senior Vice President and Chief Financial Officer.
Through a news release earlier today precision reported its first quarter 2021 results. Please note that these financial figures are in Canadian dollars unless otherwise indicated.
Some of our comments today will refer to non <unk> financial measures, such as EBITDA and operating earnings.
Our comments will also include forward looking statements regarding precision as future results and prospects, which are subject to certain risks and uncertainties.
Please see our news release and other regulatory filings for more information on financial measures forward looking statements and these risk factors.
Carey will begin today's call by discussing first quarter financial results. Kevin will then followed by providing an operational update and outlook with that I'll turn it to you Gary.
Thank you Dustin and our first quarter adjusted EBITDA of $55 million decreased 47% from the first quarter 2020.
The decrease in adjusted EBITDA, primarily results from a decrease in drilling activity and all regions.
Also included in adjusted EBITDA during the quarter is $11 million and share based compensation expense and $9 million and choose <expletive>istance payments.
As a reminder, the accused program supports employment and Canada and precision has utilized this program to preserve jobs within our organization.
We applaud the Canadian Federal government for this program and its impact on supporting employment during the pandemic.
The recent Canadian Federal government.
Budget.
That was presented include a proposal to extend the Qs program beyond its current June exploration, we will provide additional guidance on how the program will affect precision when details firm up but now but for now we expect to precision and.
Impact to be greater than what we communicated in February.
And the U S drilling activity for precision averaged 33 rigs in Q1 and increase and set of seven rigs from Q4.
Daily operating margins and the quarter were 7027 U S dollars a decrease of 4131 U S dollars from Q4.
The decrease in margin is primarily due to lower <unk>.
Idle, but contracted revenue earned during Q1.
This year higher operating costs, driven by start up costs relating to 12 year 12 rigs activated year to date and turnkey activity.
Perhaps and impacts from idle, but contracted rigs and turnkey daily operating margins would've been 1217 you on.
U S dollars lower than Q4 with the balance of the difference driven mostly by lower day rates and start up costs.
For Q2, we expect startup cost and turnkey activity to continue.
Along with no ABC revenue such that normalized margins absent turnkey and I B C well.
The decrease between 500 and $750 per day.
I'll make a few comments on start up costs and the U S.
And 2018, our peak activity reached 82 rigs and November.
And activity trough debt 19 rigs and September last year.
And that 22 month period over 60 rigs were stacked and preserved and good condition to be reactivated at a later date.
Precision had 57 rigs working in March of last year and substantially all of the rigs we have reactivated since the trough last year for <unk>.
Working on the first part of 2020.
Activating those rigs require us to incur some on operating cost to cold start rig crews and inspected and certified critical components, such as top drives and engines.
<unk> consumables and sometimes mobilize the rig on rig components.
We have found the average cost to activate each rig has been approximately $150000 to $200000. Some of these costs are incurred before the rig goes to work and some of it is incurred and the first few months of operations.
We expect this level of startup cost to continue as we add the next 25 to 30 rigs and our U S fleet.
And Canada drilling activity for precision averaged 42 rigs and the quarter a decrease of 21 rigs from the first quarter, 2020 and 'twenty 'twenty.
Daily operating margins and the quarter were $8106 and increase of $901 from Q1 and 2020.
Margins were supported by a strict focus on operating cost and Qs <expletive>istance offsetting lower fixed cost absorption.
Absent accuse impact margins would've been 6000 and $760.
$445 lower than Q1 last year.
For Q2, we expect margins absent of queues and onetime recoveries to be up 500 to $1000 per day compared with last year due to cost reduction initiatives higher fixed cost absorption from increased activity.
For reference daily operating margins in Q2, 2020 absent cues and onetime recoveries were approximately $4000.
Internationally and drilling activity for precision and the current quarter average six rigs.
And International average day rates were 53744 U S dollars down approximately 1500 U S dollars per day from the prior year. This was due to rig mix and lower rig move revenue.
And our CMT segment adjusted EBITDA This quarter was $7 8 million.
And.
140% increase.
The increase from the prior year quarter.
Adjusted EBITDA was positively impacted by a 2% increase and well service hours, reflecting improved industry activity lower cost structure skews program support.
And $2.3 million and restructuring charges and the prior year quarter.
Well abandonment work in the first quarter of this year represented approximately 15% of our operating hours.
Capital expenditures for the quarter were $8 million and our full year 2021 guidance remains $54 million.
Comprised of $38 million for sustaining and infrastructure and $16 million for upgrade and expansion, which relates to anticipated investments supporting alpha technologies and contracted customer upgrades.
As of April 21st we had an average of 36 contracts in hand for the second quarter and an average of 31 contracts for the full year 2021.
Moving to the balance sheet, we continued to reduce both absolute and net debt levels, primarily through free cash flow generation.
As of March 31, our long term debt position net of cash was approximately $1 $1 billion and our total liquidity position was approximately $700 million, excluding letters and letters of credit.
Our net debt to trailing 12 month EBITDA ratio is approximately five two times and average cost of debt is six 6%.
We remain in compliance with all of our credit facility covenants and the first quarter with and EBITDA interest coverage ratio of two one times.
During the quarter, we reduced total debt.
And about $29 million and Maine and additional.
$22 million debt reduction and subsequent to the quarter and.
Totaling $51 million debt reduction year to date.
Over halfway to meeting our debt reduction target range of $100 million to $125 million for this year.
Our capital allocation program remains substantially weighted to debt reduction and we remain on track to meet or exceed our 2021 debt reduction targets and our long term debt reduction target of $800 million between 2018, and 2022, where we have already reduced debt by $601 million.
Since the beginning of 2018.
For 2021, we expect to continue generating free cash flow through operations.
We expect some benefit from working capital release in Q2.
With lower activity during the Canadian spring breakup.
After an $18 million working capital build and Q1.
For reference the working capital build since our trough in Q3, 2020 has been approximately $44 million, which has been driven by higher activity.
For 2020, one our guidance for depreciation and SG&A and interest expense remains unchanged at $290 million $555 million before share based compensation expense and $85 million respectively for the year.
We expect cash taxes to remain low and our effective tax rate to be in the 5% to 10% range.
It's one of note.
As a result of the previous previously reported change and our accounting treatment for a portion of our share based compensation plans from equity settled to cash settled on.
And we incurred an additional charge of $2 million and the quarter as a result of our increased stock price.
This treatment of share based compensation change will lower future equity dilution and we'll introduce a bit more volatility and reported share based compensation expense and the future.
With that I will now turn the call over to Kevin.
Thank you Carrie and good afternoon.
We're in the midst of strong drilling services recovery cycle coming off the cl<expletive> of 2020 without any doubt the outlook is substantially improved even from just a few weeks ago.
Global excess inventories of crude are rapidly declining.
And for crude continues to recover trending towards pre pandemic levels as the global economy gradually opened.
And while the pricing for our services generally legs increasing demand.
Through this recovery cycles, we see many indicators that the fundamentals for land drilling are well into a rebound.
We firmly believe the firm and stronger commodity prices for both gas and oil will lead to increased drilling demand does Europe progresses, however, financial discipline by our customers the oil and gas producers is here to stay.
<unk> investor returns, while carefully managing growth as a way of today and the future for the oil and gas industry.
Precision digital technology offerings fit this need by enabling our customers to lock and performance improvements.
Eliminate human error and variance, but most importantly, this drives industrial scale based cost and risk reductions across their complete drilling programs.
So let me begin by updating you on customer adoption and the success, we're having with our alpha digital suite of technologies.
First we view the very strong sequential and customer adoption is leading indicator that the efficiency. The performance and repeatability that also provides will drive market share growth for precision. We noted eight new customers utilizing these technologies since the beginning of the year. We also mentioned, 27% sequential growth and <unk>.
Double days for the <unk> automation platform.
We've also increased our suite of Alpha apps from six to 16 as we commercialize 10 additional office during the quarter.
And this resulted in apps revenue doubling the pace of last year with over 200 billable apps days during the first quarter.
Importantly, our Elfa digital technologies are allowing our customers to drove better quality wells and reduce our drilling costs reduced fuel consumption and importantly, reduced GHT emissions, while delivering consistently predictable and industrial scale repeatability and their operations.
Now I'll say analytics utilizes precision on stuff experienced drilling engineers, who comprehensive comprehensively analyze offset well data to improve the customer drilling plan by providing process placement and performance recommendations.
Through the first quarter, we built alcohol on analytics for almost 1000 drilling days and our customer view customers view this as a high value service and we expect customer adoption to accelerate.
And if you want more details on the specific efficiency and cost reduction benefits of our office suite.
Technologies, you can find over dozen and field case studies on our website.
Turning to our business update I'll start with our Canadian well service business, which is experiencing a sharp improvements in customer demand and offers insight to the operating leverage precision can deliver as this recovery takes shape.
Most of the listeners on this call will know that we undertook a comprehensive organizational restructuring and cost reduction effort and this segment over the past couple of years.
And I'll note that sequentially, our well service activity was up 28% to 35000 man hours during the first quarter returning to pre pandemic levels.
Also point out that only 15% of our work was due to the federal well abandonment programs, suggesting a strong increase and underlying customer demand.
We expect demand will stay strong throughout the year.
And notably by the close of business on the first day of April.
Our 2021 monthly hours exceeded the full months hours, we achieved in April of 2020.
And as another reminder, today, we have 20 service 26 service rigs running compared to zero on the same day last year.
So, we're obviously seeing that business rebound nicely into the stronger commodity prices.
We expect this business is on track to deliver strong free cash flow and we'll continue to demonstrate excellent operational leverages the activity remains strong.
Moving to the U S drilling.
Drilling activity and the U S recovered a little faster than we expected with precision now operating 40 rigs by mid April well ahead of our prior guidance, which suggested we would reach this level by the end of June and.
I mentioned earlier, we continue to see strong uptake on our alpha technology products with 60% of our U S rigs running off automation and if apps.
<unk>.
We continue to closely monitor our customers' completions activities as they worked through the excess inventory of drilled but uncompleted wells.
Drilling activity levels are not matching the completion rates were even at levels to sustain current oil production volumes. We believe this points to increase and rig demand when the documentaries are exhausted later this year.
We have further visibility for potential rig activations through the end of the third quarter and expect our activity to move into the upper Forty's later this year.
From a pricing perspective, we believe leading edge rates bottomed and the first quarter and we see opportunities to charge two to $3000 premiums with these recently reactivated rigs re price as our customers have a strong preference for what they term hot rigs.
And now Kerry mentioned, the activation cost we experienced restarting rigs during the first quarter.
I expect these transitory costs to linger as we activate additional risks, yes, I'm confident those each of these rigs returned to full operation the costs will quickly normalized and London long term averages.
Now the potential inflationary effects of the pandemic economic recovery stimulus plans is a growing concern.
Labor cost inflation is less of a concern as most of our customer contracts provide for increased day rates of labor cost increase and labor accounts for roughly half of the daily operating cost of our rigs.
The other half of the operating cost is procured materials, including rig expendables spares and miscellaneous repairs parts.
Steel and other commodity inflation will likely impact these product costs as the year progresses, we believe our operational scale on our volume procurement and leveraging our supply chain will help mitigate some of these potential inflationary factors and I think this reinforces the importance of scale is a key competitive advantage and the land driller segment.
Now we believe the impacts of inflation will be well understood across the drilling value chain and rate increases to increase to offset these costs will ultimately be expected by our customers we.
We will keep a very close watch on inflation and we still expect to improve our margins as the year progresses.
Turning to our international business as mentioned in our press release, the financial performance of this segment remains stable and encouragingly pre tender work has commenced and Kuwait and we're expecting to see opportunities develop and the second half to reactivate, possibly all three of our rigs in Kuwait.
And Saudi Arabia forward visibility is less clear, but our expectation is that once all of the industry <unk> rigs in country are reactivated debt the tender opportunities will begin to emerge it.
It seems that rig activations will track the reduction of OPEC related export curtailments.
Moving to Canada.
And the middle of the seasonal spring breakup slowdown period.
And in our press release that we have 20 rigs operating today and this compares to less than 10 at this time last year, we have indications and commitments for a normal summer recovery period, and expect to exit Q2 with close to 40 rigs operating and.
Again more than twice last year's activity and we expect that will trend up through Q3 into the fourth quarter.
While pricing has been challenged over the past 12 months and the Canadian market, we see opportunities for price recovery later in the year and would expect to fully recover any inflationary inflationary factors.
We also expect full utilization of our super Triple rigs and the Montney and Duvernay drilling programs and expect strong customer uptake on our alpha digital product and products for these risks.
The company's positioning and Canada and the Canadian market remains very strong and provides us an excellent source of free cash flow as we seek to continue reducing our total debt levels.
And as Kerry mentioned with $51 million of debt reduction already achieved.
We remain highly confident and our ability to meet or exceed our 2021 debt reduction targets.
Moving onto our third priority.
We have several customer collaboration based GHT emission reduction projects underway in both Canada and the U S and.
Canada, we will be deploying a hybrid natural gas generating and battery energy storage and storage system on a drilling rig during the third quarter and the.
We have several customers transitioning to 100% natural gas for blended gas diesel power systems, and say reactivate our rigs.
During the quarter, we deployed a real time rig based ghd emission monitoring system and the field debilitated monitor precisely direct rig and mission estimates.
We're also developing several partnerships with green power solution providers to seek solutions to further drive down on field emissions.
We believe this strategy, which is similar to our partnership the partnerships, we utilized to develop our alpha digital products spreads up both the risk and investment requirements to several industry participants as we develop green solutions for our rigs.
We believe that precision drilling will be a critical contributor to reducing and eventually eliminating the GHT emissions from the upstream oil and gas drilling industry.
I will conclude by thinking and the employees of precision for their perseverance dedication and hard work as we've all dealt with the many challenges of the past 12 months.
I'm, especially proud of the high quality work our team has delivered and the strong and effective pandemic risk management program. Our team has implemented and successfully executed.
Precision and our people have completely avoided any field service interruptions due to the virus and the related challenges. So thank you to the full precision team and I'll now turn the call back to the operator for questions.
Ladies and gentlemen to ask a question. Please press star and the number one on your telephone keypad.
Your question.
Your first question comes from Taylor Zurcher of Tudor Pickering Holt Your line is open.
Hey, good afternoon, and thank you, Kevin and I wanted to start by asking a question on pricing and you made the comment that in the U S market do you think you'll be able to get at.
And a two to $3000 a day premium offers.
I guess, some other rigs out there at least for the rigs that are hot.
And I, just wonder I mean, the rest of the market and the rest of your peers are all doing the same thing and and they're all reactivating hot rigs as well. So I was hoping you could just explain that a bit more and and what you mean by two to $3000. A day what premium are you measuring that against so any color there would be helpful.
Yeah for sure Taylor I think.
As this market has kind of evolved off the bottom of 2020 and.
We and the industry activated rigs those rigs are being activated from from stacked into operations. We are bringing crews back out to the rigs we were getting the rigs kind of back up and going again.
Competition was fairly intense.
<unk> heard lots of talk about leading edge day rates on those rigs.
You know comment that those are kind of like mid teens, sometimes a little higher sometimes a little lower for the activation of those rigs once those rigs up and running and drilled through their first contract. Those contracts are generally short term we've been trying to keep that book of kind of near term. So 30 day contracts from 68 contracts.
And so well to well contracts when those rigs re price on the next contract.
We expect that that rig will get a premium over a cold stacked rig.
And that premium could be we're seeing the range of two to $3000, maybe more depending on location and availability and timing, okay. Yeah that makes sense and and just to be clear. When you identified that two to $3000. A day, you talked about some labor and and input cost inflation and that that two to $3000. A day, you're talking about would be pure margin fall through and would that be.
And some cost recovery as well.
Really I view that as pure margin flow through okay. Okay, you'll certainly.
The day rates coming off bottom, we are unsustainable for the industry and and we need to see strong leadership on getting rates back into a sustainable range.
Okay and.
And I follow ups on international you talked about some early tendering exercises going on and Kuwait and elsewhere in the Middle East and I was hoping you can help us think through what the typical timeline is as it relates to that.
Some of these early tendering activities and eventually turning into a contract and and eventually the rig going back to work and you talked about and the potential for all three of the rigs and quite to get back to work and the second half, but any color around the typical timeline there would be helpful.
We did give some guidance, we'd hoped or thought that we might have a likelihood of getting some or maybe all of those rigs activated before the end of the year.
I'd, just say stay tuned and listen to our updates.
Likely we'll have a lot more information from our July Q2 conference call.
And the work right now in Kuwait is all pre gender and work its kind of vendor survey and.
Analytics to make sure the rigs meet the specification and certainly our Newbuild rigs all meet specification and so we're quite confident that we'll be quite competitive on these rigs.
And that's helpful. I'll turn it back thank you.
Thank you.
Your next question comes from the Waqar Syed.
Capital markets. Your line is open.
Thanks for taking my question.
Kevin you mentioned that your rig activity and the U S could be up into the high forty's by late this year.
On all of those things kind of spoken for already or is that.
Do you have from contraction, because just like and discussion.
Right now.
Waqar I think it's a combination of open bids we have out there and customer discussions we have ongoing and.
And then maybe a little bit of reading the tea leaves that we see out there.
And is this incremental demand still from the private and so you're seeing some public e&ps and getting involved as well.
It's still weighted towards the privates, but what we've seen so far.
This year has been about two thirds privates about one third publics and I think that waiting and looking forward.
And would be similar.
But I think there is likely room for the publics to start moving.
And moving into a few more rig activations and the second half of the year, let's say demonstrate a couple of quarters, a good free cash flow, which we think they will.
Now how about and in their call yesterday mentioned that they now expect U S E&P budgets to be up about 10% or so year over year.
Previously you gave a common thing that it's going to be down by maybe 2% to 3% or so.
And your discussions with private and public do you get that sense.
Walker and usually with a lot to hear because of course they are trying to.
Run game theory, and also on our day rates. So we're less likely to hear forward guidance on capital spending than some other services might but but listen and it makes sense you have to realize these budgets were probably created when the WTO prices were in the <unk> not the 50% of <unk> late last year, and certainly we expect that our customer.
Both on the U S and Canada will demonstrate very strong free cash flow during Q1, and obviously again during Q2. So we think some of that money comes back into drilling.
Okay. Good yes.
And then the expectation is that.
Public E&ps may pick up activity need and the year in November December.
And that Capex number may be reported and next year's number and not and this year's number. So that's kind of debt thinking from from discussion. So I hopefully hopefully that's the case.
And that's all I have.
I was going to say one thing we are certain of is the current drilling rates are inadequate to support current E&P production levels.
And we do see our customers using their inventory of.
And I am completed wells to support production right now that can't go on forever, that's going to work its way down.
Okay, Yes.
Thank you that's all I had thank you very much.
Great. Thank you.
Your next question comes from Kunal <unk> with Stifel. Your line is open.
Good morning, everyone.
Just wanted to start on margins, so and the U S. It sounds like they're going to take a bit of a step down next quarter, which I mean, it's understandable.
The start up cost, but I mean, as we think about the rest of the year. Obviously the startup cost will continue but at the same time I expect there'll be some sort of economies of scale.
I mean you.
And you kind of expect a bit of a recovery and that metric even as you activate more rigs or how should we think about that.
I think youre thinking about the right way call. Kevin mentioned, we think that the spot pricing bottomed and the first quarter. We've got more rigs that have been fired ups, we have hot rigs to market, which should push pricing up a bit more and Youre also correct about the startup cost will be spread over more activity days as we keep adding to the rig count So we would.
Expect after the second quarter, if the fundamentals for the industry hold together that the margins will start expanding and the third quarter.
Okay perfect that's helpful. Thanks.
So as we think about the international rig tenders. I mean are you are you able to quantify how much capex you might how much you think you might need to spend to to activate these rigs and I <expletive>ume if you did have to spend that it would be obviously contracted.
Cool that's great question.
There will be Capex involved we have those rigs have been idled now for a year and before that their ages.
Over six years old so there'll be some time based re certifications and particularly on things like <unk>.
We're thinking that's going to be and the range of $3 billion to $5 billion per rig and.
We would expect that that would be recovered very quickly and the contract likely wells and the first year and we would expect to contract that.
And there is measured in years duration not not quarters.
Okay perfect that's helpful. Thanks.
Just curious on the Ghd monitor pilot I mean should we be thinking about it as a relatively immaterial and the near term from a cost perspective.
And how are you thinking about that from a revenue model standpoint would you like it to just be sort of a day rate add on or how do you think about that.
Yes, I really see all of the things, we're going to be doing around reducing our environmental footprint as part of the value we provide and if it.
Involves capital, we will look for capital recovery and some normal upgrade window, whether that's one year two years or four years will kind of depend on the scope and the length of the contract.
But we think that I would tell you that.
And with our customers and finding ways to reduce the footprint.
But doing it on and capital recovery basis is very important for us.
Okay Gotcha and.
Does that answer your question.
Yeah, Yeah, that's it and networks so from a balance sheet perspective, I mean, given where the bonds are trading right now.
Do you see yourself more paying down the credit facility and the near term and then maybe think about terming out some of that debt even more on the later half of the year.
And so so we're in a position where we have optionality, obviously, we're generating free cash flow that we can use for debt reduction we have a healthy cash balance we have a little bit of balance left on our revolver and we have a R. 23 notes that are callable at par in December of this year. So we will look to.
Essentially to make open market purchases throughout the year or pay down the revolver and.
And at the end of the year, we will have.
The ability to call those 23 notes to meet our debt reduction targets.
And in terms of longer term.
At some point in the next call. It 18 months, it's likely that we would.
Execute our high yield transaction to term out some of the some of the longer actually and I should say near term maturities.
We think it's probably a little bit too soon right now and.
We actually had been chipping away at the 23% and 24 notes so as we move along and time those balances will be.
Smaller than they are today.
Okay, Great. That's good color that's all from me I'll turn it back thanks for the answers.
Thanks, Paul.
Your next question comes from John Guinee with Danielle Energy Partners. Your line is open.
Hey, guys. Thank you for including me.
Hey, John Kevin just on the on your activity comments nice progression and the high Forty's can you just elaborate on that.
The duration on those opportunities given where the strip is when they are trying to lock it in for 2022, just any color on that would be appreciated.
We have some customers trying to lock in.
Kind of leading edge rates for a longer period of time.
But few of those go beyond about a 12 months cycle, where obviously you want to always keep a blend of.
And kind of medium and short term contracts, we're not too exposed to either direction and this.
Type a rising market.
We are anxious to see contracts rollover.
Okay.
And then give you last every day on that answer, but I would tell you most of the contracts are less of the year.
Well, yes.
And I understand that you wanted to be less and the year to day, but I Didnt know if because of where the strip is if people are now asking for more.
Term and.
Notwithstanding where you want the pricing would be but just.
Conceptually if they want to lock these things and for longer.
Very few companies and what each way into budget identified yet so.
And as stretching beyond the first few months into 2020 two.
Okay got it and then just what the reauthorization and trying to recover from 2020 and really understand where they are going to be sitting financially over the course of this year before they get too.
Two committed to 2022, although although I will tell you the language plenty on 'twenty two is looking quite robust.
Right.
I just it seems to me that.
There could be a rush.
Waqar alluded to and the fourth quarter and people trying to lock stuff up and they're not at that place.
To you guys in terms of rising inquiries and equals rising rates and I don't know if people just want to get ahead of it.
And like a smart on the customer so for sure right now every previous save matters, but if they're back into getting rigs and at a rig and three or $4000 a day more.
And.
And theyre going to be drilling 20 day wells, that's only $16000 against was probably a two or $3 million well. So the rig cost is just a lot less meaningful than.
And it might've been and any previous recovery cycle.
I agree, but they always look at that number first thing they look at right on and AFP day rate typically.
And do they do it.
And a rising tide I would tell you that getting you a good rig is probably more important the JV loss cutting off the price.
Absolutely and I thought I don't disagree on that last one Kevin just.
And the sort of big picture thoughts on your well service business and as it relates to opportunities and the United States for expansion.
Huh.
We have a very small footprint pressing into north Dakota, which really leverages, our southern Saskatchewan and capabilities, but we don't really see any expansion beyond.
And that natural extension of our activity is nothing nothing beyond that.
Okay. That's all I got thank you guys.
Thank you John.
Your next question comes from Keith Mackey with RBC capital markets. Your line is open.
Hi, good afternoon, everyone.
Sure.
And I just have one.
One one question for you.
And I appreciate it might be a bit sensitive. So would appreciate any comments you can make on it but.
And given given the $9 million wage subsidy is pretty pretty substantial and the context of Q1, and 55 million EBITDA and like what is the sense or the strategy as that program potentially ramps down through through Q2 like is the day.
And we're holding on to capability and four four and upswing and the second half of the year or or is there potentially some restructuring.
And be done and any comments you can make to that to that effect would be.
And would be helpful.
Well.
Keith through most of last year, we did most of the restructuring that we think is necessary, but but I'd add a couple of things here I think that we did preserved jobs.
And <unk> that would have otherwise.
And maybe not a bit of a company without a program.
But I would tell you that today, a large portion of the value is actually across the field operations and drilling and well servicing.
And you could say that.
The drilling rigs are running a little cheaper right now and those service rigs, we're able to cheaper and that value is kind of being earned by the operating company is getting the services a little cheaper so I'd expect that as those of.
Likely as those relief programs start to wind down we will look to.
Push rates higher to reflect the increased cost.
Got it and maybe just on a as a follow up on that I was sort of also wondering if yes.
And if that.
And any potential ramp up and the site reclamation program spending that's unexpected and the second half of the year.
Plays into into your footprint the way, you've got and set up now.
Oh Wow.
And I'll tell you that we're pretty enthusiastic right now, but our performance and well servicing any increase in <unk>.
Our reclamation awards and we've been very well.
Got it blanketing and that business right now is all really good flow through rates on the bottom line for us. So I think we'll be pushing hard to win more of those awards and.
Continue to support the increasing demand, we see on the field for conventional well serviced and remediation work.
Got it okay. That's it from me thanks, very much okay. Thanks Keith.
Again as a reminder to ask a question.
And the number one.
Your next question comes from.
And.
And with Morgan Stanley Your line is open.
There's been a lot of talk about whether operators and U S are going to kind of stick to managing budgets to production maintenance mode or if theyre going on maybe pick up activity.
And I kind of wanted to ask a similar line of questioning but in Canada. Just in your conversations with customers do you get the sense that on.
Canadian operators are kind of and maintenance mode as well we're on.
How would you kind of characterize the strategy and that market.
Dan I would say that that transition and probably happened two or three years earlier, and Canada, where are the e&ps were forced into a maintenance or fiscal discipline mode really as early as 2014 2015.
After the first sort of.
OPEC collapse, so I think it's been running longer and Canada, I think the E&ps and Canada are trying to find ways now to do both generate good shareholder capital returns and find ways to develop modest growth you've seen a couple of transactions up in Canada that are designed to eke out a.
A couple of E&P transactions to Eke out some of the <unk>.
Synergies grow production, but not not necessarily increased capital spending.
And certainly we're going to see activity and kind of come up off of the 2020.
Extremely low levels, we experienced last year.
Got it and yes that was kind of my my follow up is.
<unk> said and U S and you think that we're running below.
Maintenance activity levels, and obviously the answers a lot more complex and Canada, given seasonality and the different resource plays but just wondering if theres any kind of a bogey you could point to for what might represent maintenance activity levels.
<unk> rig count and in Canada.
A little hard to that because the mix of hydrocarbons is a bit different from Canada.
And the emphasis last couple of years for our triples has been around what I referred to on the prepared comments was montney and Duvernay and Thats.
It's a natural gas basin, but it's actually very wet and the wells are essentially being paid for by the natural gas liquids that are being produced and those are still go into.
Pipelines and get shipped over to the heavy oil producers and it's used as a diluent for heavy oil being pipe to the U S.
<unk> got natural gas liquids, you've got natural gas and you've got oil all three are quite constructive right now and.
And with the Canadian oil and gas complex operating and a disciplined mode I think theres room to see activity move up and still be disciplined.
Understood. Thanks, a lot from color and turn it back thank.
Thank you.
Your next question comes from Jeff.
The.
Your line is open.
Good afternoon, everyone. Just a quick follow up question on the technology side So Ken.
Kevin you've obviously laid out.
Adoption and successes, you're seeing across alpha and some of the emission and stuff how should we think about the impact on your day rates and margins from both first alpha but also the emissions piece.
So on the emission space and I'll start there.
Mick and capital addition to the rig.
Guests and Jude or a battery power pack.
I'll look at that like it's and upgrade and we'll look for a typical upgrade economics, which means.
Pay back within the contract period and that could be one year could be two years unlikely and stretches out to three years.
So if theres a capital enhancement to the rig.
Want to see that capital recovered so we view our customers being partners with us and those GHT emission reduction efforts now.
And I think you've been talked about a couple of those on last call, where we had some upgrades. We did that were specific to both natural gas conversions and.
And footprint of the rig where our customers pay for those upgrades.
And now coming back to the Alpha.
Great question and I'm glad you asked it so I can dive into this a little bit.
And the price we posted for Elfa automation, and Canada is 1500 always predict and area and the U S 15 and orders per day U S.
That price has stuck in the market.
We introduced originally 3% to four years ago.
That's essentially.
Price and allows us to.
Recover any capital investments, we need to make within a couple of hundred days.
And.
And after that it is essentially EBITDA for us.
On the apps were charging and the range of anywhere from $202 50 up to about $1000 per day, depending on the value of the up creates and.
And some cases, if we own the up although the revenue comes to US if it's owned by our partner there may be some revenue sharing agreement, but generally theres no operating cost for and apps. So it's all EBITDA on our.
Revenue model for our optimization and Alpha analytics, we're charging a per day rate for the days that we do.
On the optimization for our customers. So these are all per day added to the base rig cost. So what we see happening Jeff is that the rig may need to compete on a per rig basis.
But all of the others Elkhart to the price of the rig go on top of and there is simply no competition on these technology offerings from not being bid down on our technology offerings.
And so conceptually, we should think and vote.
The $1500 per day base rate being applied across the 30, plus rigs and consistently that you have running today.
I think we gave a U S.
A penetration rate of about 60% and and Canada on our Super triples, I didn't give a rate on that but it's less than 50% right now, but we expect over time that both Canadian and U S fleets will trend towards full utilization.
Thank you and on the Capex side, the $54 million budget.
Is there some room built and for maintenance capital tied to the U S fleet ramping up faster than you had previously talked about or is there some.
Some potential that your capital program and do some expand obviously ignoring the comment earlier about the reactivation internationally.
Hey, Jeff, It's Terry I would say that that capital plan of $54 million incorporates steady increase and activity and our U S rig count throughout the year.
That's how we budgeted it now if there's a if there's a sharp ramp if we get two and activity level thats higher than what what Kevin guided to kind of high <unk> towards the end of the year there'll be a little bit of and increase but we're talking probably low single digits millions of dollars.
And the $3 million to $5 million per rig for the international debt that would be incremental to that 54 number and thats currently guidance.
That would be but again that would be that would be <expletive>ociated with signing a long term contract.
Okay. Thanks for that growth.
Your next question comes from Dan healing and with Keith.
Your line is open.
Hi, guys. Thanks, and thanks for taking my question.
Hi, I was looking for some comment on on.
Joe Biden and.
And just and turtle announcing bigger emission targets from Canada, and the U S by.
And by 2030, and I heard on the call that.
Precision drilling is doing things to help customers reduce emissions, while they're drilling.
And from a higher level in terms of what the industry can expect.
To happen and and.
And precision drilling specifically over the next half years.
And what's what's the impact on the B.
And these are obviously extremely.
Aggressive targets being laid out by leaders in Canada, and the U S and.
I think there was an absence of process or plan behind the targets, but you didn't start with the target and I understand that.
And I think the.
The objectives that they're trying to achieve we agree with and we support and.
And our case.
There are solutions for drilling rigs to take them to essentially zero emissions almost immediately we've done that and the past with.
Grid power drilling rigs and Thats not.
So on.
Fishing is it's easy to accomplish the only issue is having adequate grid power in the field to the rig, but as these fields mature and become.
More industrialized I expect to see more.
Industrial grade electric power applied to the fields and that likely gets better so I think that from a drilling perspective.
Getting to zero or near zero or are certainly getting to the targets they've talked about which are 40 and 50% reductions.
Are achievable and.
Our case to convert one of our Super Triple rigs from diesel.
Diesel powered rig to highlight powered rig is a very small amount of capital.
Yes.
Okay, and just as a follow up on.
Are there things that the government should be doing for the oil and gas companies and the drilling companies to get them to these things.
I think that any of the.
Technology incubators or technology.
<unk> supports the government's giving for all of the alternative energy sources, the oil and gas industry should be looking at very hard and that would include everything from.
Solar and wind power to hydrogen fuel cells, and I'll highlight power, but I think those avenues are open to us now and I think that I don't.
My team is looking hard at the opportunities we have to seek out.
Federal R&D.
Assistance for alternative power that we're looking at.
Okay. Thanks very much.
Thanks, Dan.
And there are no further question and at this time I'll turn the call back to Dustin honing for closing remarks.
Thank you everyone for joining today's call. We look forward to speaking with you and we report second quarter results in July and Eastern may disconnect. Thank you.
This concludes today's conference call you may now disconnect.
Okay.
[music].
Okay.
And.
[music].
And then.
[music].
Yes.
[music].
Okay.