Q2 2023 Precision Drilling Corporation Earnings Call
Good day, and thank you for standing by walking through the precision drilling Corporation 2023 second quarter Conference call I would now like to hand the call.
So doing the director of Investor Relations. Please go ahead.
Thank you operator, welcome to precision Drilling's second quarter conference call and webcast today I'm joined by Kevin nephew, precision, President and CEO and Carrie Ford our CFO earlier today, we reported our second quarter results.
To begin our call today Terrie will review these results and then Kevin will provide an operational update and outlook commentary.
Once we have finished our prepared comments, we will open the call for question.
Please note that some comments today will refer to non Ifr S financial measures and include forward looking statements, which are subject to a number of risks and uncertainties for more information on financial measures forward looking statements and risk factors. Please refer to our news release and other regulatory filings available on SEDAR.
And Edgar.
As a reminder, we express our financial results in Canadian dollars, unless otherwise stated Carey over to you.
Based upon precision Q2 financial results exceeded our expectations for revenue adjusted EBITDA earnings and cash flow are.
The resiliency of our high performance high value business model.
Organizational focus on cash flow and return on capital drove our financial results and progress in strengthening the balance sheet.
We have not reached we have not yet reached our desired capital structure, but in the middle of 2023, we crossed a few milestones, including total debt below $1 billion.
Our net debt to TTM EBITDA below two times.
Well below two times and cumulative debt reduction of over $1 $1 billion since the beginning of 2016.
I'll move onto Q2 performance.
Adjusted EBITDA of $142 million.
So it's driven by healthy drilling activity improved pricing and strict cost control.
And included a share based compensation charge of $3 million without this charge adjusted EBITDA would have been $145 million, which compares to a normalized EBITDA at $75 million in Q2, 2022, representing an increase of 93%.
Margins in the U S and Canada were higher than guidance resulted from stronger than expected pricing and cost recoveries higher ancillary revenues and improved cost performance.
In addition to 5 million U S dollars and idle, but contracted revenue.
In the U S drilling activity for precision averaged 51 rigs in Q2, a decrease of nine rigs from the previous quarter daily operating margins in Q2, excluding the impacts of turnkey and idle but contracted revenue.
Were 15455 U S dollars and increase of 1276 U S dollars from Q1.
For Q3, we expect margins to be approximately 15000 U S dollars.
In Canada drilling activity for precision averaged 42 rigs an increase of five rigs or 12% from Q2 2022.
Daily operating margins in the quarter were $12203 decrease of $1355 from Q1 for Q2, I'm sorry from Q1 2023.
For Q3 2023, our daily operating margins are expected to increase by approximately $500 from Q2 levels with improved pricing offsetting rig mix.
We continue to build our North American contract book with Q4, 2023 drilling rigs undertake or pay term contracts, increasing 50% in U S and over 60% in Canada versus three months ago.
Internationally drilling activity for precision in the current quarter average five rigs International average day rates for 50551 U S dollars, a decrease of 7% from the prior year due to rig mix.
And our CMP segment adjusted EBITDA this quarter was $8 million up 55% compared to the prior year quarter.
Adjusted EBITDA was positively impacted by a 30%, 31% increase in well service hours and improved pricing.
<unk> results were further supported by precision rental business, which is realized and increased demand and utilization for equipment on our super triple rigs for customers in the Montney.
Moving to the balance sheet, we are committed to reducing debt by over $500 million between 2022, and 2025 and achieving a normalized leverage level below one times.
Our debt reduction target for 2023 is $150 million and we plan to allocate 10% into.
And 2% to 20% of free cash flow before principal payments directly to shareholders.
During the quarter, we reduced debt by $178 million and utilized $8 million to repurchase shares as of June 30, our long term debt position net of cash was approximately $940 million and our total liquidity position was $580 million excluding letters of credit.
Our net debt to trailing 12 month EBITDA ratio is approximately one seven times and our average cost of debt is approximately 7%.
We expect our net debt to adjusted EBITDA ratio to be approximately 125 to one five times at year end.
When we expect that to be below $900 million and our run rate interest expense to be approximately $60 million.
Our annual guidance for 2023 includes depreciation of $290 million in.
And SG&A at $90 million before share based compensation expense.
Our full year 2023 capital plan remains at $195 million we.
We expect cash interest expense to be approximately $80 million for the year and cash taxes to remain low with an effective tax rate of approximately 25%.
For 2023, we expect share based compensation expense to range between $20 million and $40 million for the share price range of $60 to $100 and Canadian dollars.
The annual share based compensation accrual could increase or decrease another $15 million based on relative share price performance and a multiple applied between zero and two times.
Year to date, we have had a recovery and share based compensation expense of $9 million.
With that I will turn the call over to Kevin.
Thank you Gary and good afternoon.
Larry you highlighted I am also thrilled with the rapid progress we are achieving against our debt reduction and capital structure objectives and this progress is underpinned by the strong operating cash flows we are producing and should continue to produce.
Equally thrilled with our recent contracting successes in both the United States and Canadian markets and more on that in a moment.
Now as some of the listeners may know precision has a large employee shareholder base, many of whom listen in on our earnings calls.
I'd like to recognize and thank every member of the PD team, we're all dedicated to providing a safe high value services, our customers expect from beauty.
While also tightly managing our cost optimizing our margins and producing strong operating cash flows the benefit of all PD shareholders.
The results of the hard work achieved the highest second quarter cash flow in the company's history Bravo DVD team.
So I'll start with our Canadian segment, which have been highlighting for several quarters, but really stood out during the seasonally slow second quarter traditionally known as breakup.
The Canadian market for conventional oil and gas drilling is radically transitioned over the past several years.
Perhaps now the best it has been and by best.
And the most stable and healthy that I've experienced during my career.
No longer is the summer fall drilling program pinned on the eco gas price realized in April may we now have visibility one two and in some cases three years out for Canadian drilling activity.
The Trans Mountain project the line three expansion and the coastal gasoline pipes are solving the basin takeaway constraints, which have hung over the Canadian industry for the past decade.
You can look through precision customer lists and find many directly linked to LNG, Canada, and others, who have recently announced long term LNG gas sales contracts to the Gulf of Mexico.
Precision Super Triple Fleet, which was fully utilized in Canada is linked to the global LNG market not seasonal equal volatility.
And then the Western Canada select discount has narrowed when combined with the weak Canadian dollar are heavy oil and segregate customers are benefiting with improved cash flows and a return to the drillbit, resulting in strong demand for our Super singles.
But probably most importantly, our customers have become adept at operating at a tightly constrained and capital disciplined framework.
They are not relying a capital market access to fund drilling programs that are self funding drilling we're meeting well inside their cash flows.
We have improved focus on balance sheets and they're operating.
Shareholder focused returns based corporate strategies and.
In this capital discipline has transitioned the way our customers think about drilling they are taking the focus off pure day rates, they're focusing on a comprehensive overall drilling cost efficiency when they develop their drilling plans.
For both gas and heavy oil development projects, we are experiencing increased demand for pad drilling and increasing pad sizes. All aimed at this cost efficiency essentially pad drilling has become the industry standard and led to full utilization of our pad walking rigs, where we continue to see customer demand exceeding our supply.
Our larger pads. These rigs can rigs can work street through spring breakup smoothing, our revenues and improving our cost efficiency.
This drive for capital efficiency also encourages customer adoption of our Elfa digital solutions and with all but a couple of our Super triples running at Alpha running in Canada now operating mill system.
So currently we have 58 rigs in Canada running marginally less than we previously guided primarily due to just one operator, reducing their drilling program.
With a stable oil price the reduced Canadian differentials and the soon to be commissioned Tms and coastal gasoline pipelines our outlook for the second half in Canada remains firm, we expect 100% utilization of both our 29 Super triples, and our pad Super singles is drawing utilization for our remaining 31 Super singles should.
We should see rig activity in the high <unk> or low <unk> in the third and fourth quarter setting up for a very strong start to 2024.
Notably during the second quarter, we added 10 long term take or pay contracts with some of those stretching out three years.
Most of these are contract renewals with operators seeking to lock in access to those rigs over the longer term.
This is another key Canadian market change whereby customers are now committing to contracting rigs on it.
Pay basis when in prior periods customers with only commit to is take or pay style contracts when supporting drilling contractor capital investments for upgrades or new builds.
This shift significantly stabilizes our activity levels and our financial performance for our Canadian segment.
Today 20 of our 2019 and Super triples are contracted with take or pay terms.
Still see customer demand well in excess of our available rig supply.
We have said we might consider mobilizing additional rigs to Canada of the DJ Basin are Marcellus. It seems this opportunity may emerge later this year or 2024.
Turning to rates are leaving at rates in Canada for our Super Triple two hundreds are now approaching the mid <unk> with base rig while our pads Super singles are now in the mid twenties.
<unk> automation is installed and running on approximately 90% of our Canadian Super triples.
To deliver solid performance results and meaningful value for our customers.
It remains incumbent on precision to continue to manage our costs and improve our day rates as we seek out financial returns exceeding our cost of capital. We've made good progress so far but we still have a ways to go.
Turning to our well servicing business it performed exceptionally well during the second quarter, despite industry activity lower than last year.
The regional diversification, we achieved with the high Arctic acquisition supported strong activity levels through breakup, specifically in our thermal operations.
Which remain a key strategic focus for our well service team.
Our expanded scale has noticeably improved our operating leverage providing a strong catalyst for free cash flow growth in this business.
We are expecting a busy second half of the year and with the industry wide crude constraints.
Even with limited industry capacity, we believe the outlook for well servicing looks very good for the second half.
Now in the U S as Gary outlined our utilization is trending a little lower than we guided as a result of the weekend natural gas prices and the uncertain oil prices experienced in the first half of the year. However.
However, as Brett and WTO have firmed up over the past few weeks customer inquiries for oil targeted rigs has accelerated.
We recently contracted nine rigs for Q4 and early 2024 startups, if the current oil price range. The sustained perhaps we are in the trough of customer demand with an upward bias later this year and it's 2024, where demand is noticeably strength strengthening.
Super spec rig supply remains very tight despite the reduced overall industry activity and very importantly pricing discipline remains a common thing theme among our industry peers.
Currently we have 43 rigs operating in two on paid standby.
Through the first half of this year, we've been prioritizing defending margins over pursuing market share.
Turned down several opportunities with rates lower thresholds and we'll continue to do so.
We do expect our utilization will remain around this level through the third quarter with an upward trend in the fourth quarter and it's 2024 as I described earlier.
Precision is current leading edge rates on a super Triple five hundreds are in the low to mid <unk> with some fully included rig rates approaching $40000 per day.
And those are for customers that are seeking immediate activations.
At current commodity price levels, we see a super spec rig demand trending towards near full utilization next year and it appears our customers are also anticipating the same market dynamics as they are seeking to lock in the best rigs and what appears to be market leading rates.
We are bidding on several contracts that have been awarded contracts with rates in the upper <unk> to mid mid to upper <unk> for rigs starting operation later this year and early 2024.
And virtually all of our operating rigs in the U S have also automation delivering again improve customer performance, while enhancing our field rates and margins.
Now turning to our evergreen products for a moment.
Our evergreen solutions continued to generate very strong customer interest.
Precision Evergreen solutions are no nonsense high value cost saving additions to applicable to virtually every PD rig with the added benefit of reducing GHT emissions. This is a win win win project in the very early stages of market penetration.
For example, we have 10 battery energy storage systems deployed we expect to add three more before the end of the year. We have several more systems in the final stages of customer approval right Bill.
Customer uptake of our evergreen products has spread from Canada to the DJ Basin and is now expanding with customers the Permian and Marcellus also exploring these products.
We'll have more to report on the evergreen product line in the coming quarters.
And finally, turning to our international business currently we have six rigs running as Perry mentioned three in Kuwait and three in Saudi Arabia.
The final two Kuwait rigs are nearing completion, and the recertification process and barring any customer delays both rigs should be running in the next several weeks.
We have five additional idle rigs in the region. We continue to pursue interesting opportunities tend to those rigs for several different projects. We will keep you updated on our progress as information becomes available.
And that concludes our prepared comments.
I'll now turn the call back to the operator for questions.
Thank you ladies and gentlemen, if you have a question or a comment at this time. Please press star one on your telephone. If your question has been answered or you wish to move yourself from the queue. Please press star one again, we will pause for a moment, while we compile the Q&A roster.
Our first question comes from Luke Lemoine with Piper Sandler Your line is open.
Hey, good afternoon.
Kevin pretty positive comments about the U S rigs that are being signed to begin in <unk>.
Can you talk about the shape of the U S rig count and do you think <unk> Jumpstarts 24, and then I just wanted to confirm that you said a super spec rig demand to be at full utilization next year.
We're actually quite surprised by how quickly.
Our customers seem to be ramping up they are thinking about 2024, it's primarily oil base, but we've had.
Also I think one or two rigs that are it looked like it would be contracted into gas primarily in the.
In the Marcellus.
But just looking at the profile right now.
Quick influx of lots of inquiries, we've signed the non contracts we mentioned.
Primarily oil primarily.
Either large cap or kind of IOC style.
E&ps that are definitely plan to wrap up activity into 2024.
And.
We're effectively repositioning from the haynesville into the Permian right now and really shifting our customer mix from what was largely private equity a year ago now to a lot of large cap publics and IOC in the Permian.
So as we watch that kind of play itself out if we just look at the inquiries we have to date it looks like the alternative rigs do not offer precision probably for the industry.
That's where I am thinking that over the course of.
2024, we could see that super spec rig market will be utilized.
Got it.
And then I know, Canada Youre sold out on Super triples in singles and you talked about moving some from the U S.
What kind of duration can you get on these contracts I know overall you talked about.
We're seeing one to two years in Canada for some time.
Are you towards the higher end, Jamie does from the us to Canada or how should we think about that.
Well the way you should think about that is number one.
Wanted to see the marginal rate in that upper Thirty's range. So that's really important on.
The customer has to pay for that move in addition to the day rate so weather.
Whether you sign two year contracts in place for over two years or one year contract in place for over one year.
<unk> been different but we do want to take or pay contract with fixed days, we want to have certainty of revenue we want to have a base rate for that base rig in the upper <unk> and we want low cost fully paid for by the customer.
I think it's a fairly high bar compared to today's market, but the market's evolving quickly.
Yes got it.
Alright, thanks, so much Kevin.
Great. Thank you.
One moment for our next question.
Our next question comes from Aaron Macneil with TD Cowen Your line is open.
Hello, and thanks for taking my questions.
Kevin if there's 27 rigs under contract in the U S. In Q4, what's.
What's the average duration.
43 currently active can you sort of.
Characterize the remaining 16 or so rigs I guess I'm wondering.
Service contract structures or the operating under I assume while dwell are they up for renewals do you have visibility towards continued work.
There's obviously always churn, but just trying to understand how solid the current activity level is in the U S.
Thank you.
Aaron This is carey.
The contract book, we've had over the last 18 months has been anywhere from six months to three years.
But up until I would say a few weeks ago.
The majority of the contract durations, where six months.
And we've seen more requests for one and two year contracts and we recently entered into.
Several one year contracts, so I think it's trending a little bit longer duration.
And we're not really seeing.
As many customers looking for.
Three or four wall programs. They are longer term programs. So I think it's a good indicator of future activity.
And the rigs that are sort of working today, but don't have long term contracts associated with them.
Yes, so those will be either go into long term contracts or are they going to switch hands to customers that are more interested in contracts.
It was renewed on a well to well basis with the same customer over and over correct.
Got it.
You had highlighted the relative strength since the Canadian market again this quarter.
If we compare.
Generic or average 500 horsepower super Triple in the U S with generic.
Generic 200 horsepower Super Triple in the Montney.
Which one is generating a higher rate of return today and do you expect.
As rates have returned to change at all.
Eric.
That's essentially how we arrived at that upper <unk> Canadian rate that rig in Canada. So are our cost in Canada are in Canadian dollars, our rates or Canadian dollars. So the operating margin at <unk> would be about the same.
<unk> in the U S on those rigs in those 1200 rigs.
In the.
DJ Basin.
Makes sense.
Ill turn it back thanks, guys. Thank you.
One moment for our next question.
Our next question comes from Waqar Syed with ATB capital Your line is open.
Thank you.
And Kevin have Kerry.
B C revenues and Q3 would those be still be around that $5 $6 million Mark.
Yes.
Probably be one or two rigs.
I don't know if it'll be that high but it will be one or two rigs or we have one RBC.
And how long you guys were in Q2.
Yes.
Yes, I think we had two rigs.
Okay.
Alright, and then.
Okay.
So if you look at the U S.
And kind of day rate.
Revenue per day in Q2 <unk> $4400.
And the leading edge mentioned is in the load.
To mitigate these.
Is it leading edge in line with where the revenue number reason or is it no below we know what's your revenue per day was for Q2.
Well I think we've got a couple of things going on here, we have a little bit of softness going into Q3 continued from Q2 and then we're seeing strengthening in Q4, so if youre talking about going back to Kevin's opening comments about where the leading edge rate is for Q4 and Q1 bookings we've got rigs there.
Some rigs that are pricing as high as 40000, all in so that is one leading edge rate and then if we're talking about where we've been.
Protein leading edge rates for the.
The last three months I would say, we've been saying kind of mid <unk>.
Low to mid thirties, and we reported day rates.
Little over 35000, a day in Q2, so there are kind of in line I think in this market.
Okay. So.
$15000 a day margin guidance for Q3 is that kind of the new floor.
There is potential for margins to decline further into Q4 and Q1.
Well part of what we have going into Q3 is just a little bit lower activity. So we have some more fixed cost absorption that we have fewer rigs bearing the same similar fixed costs. So thats part of the margin squeezed and then.
If we see.
More demand and higher rates in Q4 Q1, we'll see the margins go back up.
Well that's been pretty good.
And in terms of.
Incremental demand in the middle East.
How do you see that when do you expect maybe.
You still have about five rigs idle in the middle East.
The international markets.
How many you could go back to Ken or kind of what kind of timeframe.
Yes, I'm going to be a little vague on the guidance there look.
<unk>, we've got active bids for silver rigs right now.
I would say that the most likely ready to go back to work first would be the one idle rig in Kuwait and then they go back to work in Kuwait or Saudi Arabia, Let's say.
It's essentially the AC Super spec rig.
2000 horsepower size.
But I wouldn't expect that rig to be activated for the beginning of next year at the earliest.
And we've been participating in a number of other tenders in the middle East.
Throughout several countries that just keep sort of getting pumped that down the road or delayed or slow play.
So it's really hard to assess.
What the iOS with the.
National oil companies thinking around reactivating these tenders.
And turning those tenders into contracts.
Okay and so.
This is even if you win a contract for Greg Thanks, Tom.
Day of announcement to the day the DRAM revenues is it like a six month lag.
Less or more.
It would be in the three to six month range.
Just depend on how much recertification.
If we do what their schedule was they generally think about these things.
In that anywhere from three months to one year, depending on the tender.
Okay.
And what's kind of incremental capex may be required to ask.
Activate those rigs.
Well it could be as little as a few million dollars like maybe $8 million to $10 million per rig or it could be as much as 20 to 25 million depending on the scope of work we have to do to meet the standard but the day rates would be designed to recapture that capital within the first operating year of the contract.
Okay.
Great. Thank you very much.
Very helpful.
Great. Thanks, Nick.
One moment for our next question.
Our next question comes from Keith Mackey with RBC capital markets. Your line is open.
Hi, Good afternoon, I just wanted to start out.
Many have been trying to of course kind of call the bottom on the U S rig count and determine where it ultimately goes from there now Kevin from your prepared comments and some of the of course Q&A.
It sounds like you believe that we are close to there given the comment around super spec utilization.
In fully utilized in the U S through 2024.
But can you just maybe give us a bit more clarity on why you think that the.
Hey, how close we are to the bottom in the U S rig count.
Activity for the industry and then and then.
What gives you really the confidence what are the two or three factors that.
Do you think will lead that that rig count to ultimately be.
Are the Super spec rigs to ultimately be near at full utilization.
Keith.
Actually a very complex question. So I'll do my best here carrier you can pipe into if you have any more thoughts.
So what I'm sure of is that Q2 wasn't the bottom I'm sure of that.
But I'm also sure of is that about 90 days after the bottom you'll look back and say, yes for sure that was the bottom.
So there's a lot of uncertainty around trying to call it in advance.
I think what we're looking at right now as we saw this surge of inquiries come in when the oil price stabilized we bought commodity prices looking pretty good today I mean, we did see a month or two or three of this we really competence, but but it does seem like.
The problem wasn't $72 grew to $74 crude carload wty dropping into the 60% coming back out of the <unk> that uncertainty held back plans that have been in place even late last year to add rigs.
I mean the.
The inquiries are looking at today were ones, we were actually contemplating back in November December of last year, another come to fruition.
Pricing so stabilized so.
Certainly the market is doing better than it did even just a few weeks ago.
It would be hard to imagine that.
The world of $75 <unk>.
But the rig count go down much further so I was cautious in my comments.
Around our rig counts were up 43 today is it will be in this in this area through the third quarter, we could drop down a couple of we're going to defend defend price utilization. So we.
We have a renewal coming up where somebody wants to keep that rig, but cut the price by $5000. They will walk away.
So I wouldn't be surprised if our rig count were to drift a little lower.
But also if it stays flat at this level of moves up that Wouldnt surprise me either.
How's that for hedging my bets.
Okay.
I think that covers it pretty well.
Maybe just on the new contracts that.
That you've signed sounds like given the pricing you have sort of directionally talked about it sounds like you've been pretty successful despite.
Despite the increased availability of Super spec rigs in the market <unk> been fairly successful at getting decent pricing now can you just talk about why that is like do you get a sense that these rigs are for customers, who are drilling net new wells into 2024 or have these rolled off some other.
Sure.
Some other contractor and you've managed to pick them up.
So these are net new wells that we would have been talking to customers about a year ago last November December but there are 2023 plans that just got pushed back but I would say a second part. These are also customers who wouldn't be looking at some of the small drillers.
To do that works, we don't see the.
The small drilling contractors that have a couple of super spec rigs.
As the competitive these are really going to be focused on the top three or four drilling contractors. The customers are looking at like I was describing earlier in Canada, how our customers are shifting away from just pure rate looking at pool value. So I can tell you every one of these rigs that we've contracted has elfa running on the rig from day, one that's an important factor.
For these customers. We also have our clarity data solutions on these rigs where they want to get high frequency data from us. So these are sophisticated customers looking for a sophisticated drilling program.
And.
The leading edge day rates, just maybe a little less important than having the digital capabilities of the safety and the support we can provide.
Got it and one more if I can squeeze it in it looks like there is in <unk>.
Canada, maybe five or so rigs.
Doing direct to LNG type of type of drilling now how much more rig activity do you think is required for the current or to fill the current phase of LNG are we kind of there or do we need to see a few more rigs go to work and is that working its way into your <unk>.
Our discussions as well.
So it's probably more than five rigs, we have tied to LNG I think number might be closer to $50 2000. If you include everybody who is a partner in LNG, Canada that we're drilling four and the other company that's announced LNG exports through the Gulf Coast. So I think it's a larger number.
But I can tell you we're adding another rig in January that's the upgrade we talked about a couple of quarters ago. It starts January one.
<unk>.
I would be surprised if.
Three to five more rigs are not required to satisfy the first two trains of LNG, Canada.
Now.
That work will get done one way or another if we don't bring rigs out of the U S to satisfy that of our competition doesn't do it there may be some increased tele double work, but the efficiency gains on a triple.
On a three well pad or larger or just too hard to argue with and our customers are still focused on capital efficiency that will drive them into the triple direction away from the <unk> or the larger pads.
The LNG style customers.
Yeah got it thanks very much Greg.
One moment for our next question.
Our next question comes from Colby <unk> with Stifel. Your line is open.
So obviously on the Canada front the contracts is quite the change in behavior from the E&P side, you just get the sense that some of the producers are getting very worried about rig availability just given some of the LNG tailwind and can you talk about the length of some of the contracts that you've recently signed in Canada.
Yes.
We.
It might be the wrong word I think what they are trying to do is ensure they have the same crew the same rig for a long period of time.
So.
It's a very collaborative effort I have been involved in some of these discussions myself with our customers.
They have been.
Highly collaborative trying to make sure they have the.
Drillers the same rig managers are very consistent predictable operations. This year next year the year after contract durations have ranged from one year to a maximum of three years. The average is probably somewhere between one and two years so the contracts.
I wouldn't say our customers are worried I said, they're really focused on making sure. They can control their operations with our rigs and crews.
We know trust and have confidence in.
Got it thanks.
On the U S side, you talked about some of the publics and Super majors getting a bit more active over the next few quarters.
Have conversations with some of the private producers been recently acknowledging the fact that the ramp in crude it seems like it's really been just the past week or two.
Yes, so I think the difference is that the public who are talking to and that we've been contracting with likely we're looking to add rigs.
Earlier in 2023 and that didn't happen to their plan is ready and when the price got in the right range for them. They are ready to go quickly I think that the smaller companies don't do that kind of event planning don't have that kind of structure and they may wait a little longer and.
Work with their private boards.
Get through some early cash flow.
Bumps and then start looking to add rigs.
Got it that's all for me, Thanks, I'll turn it back.
Right.
Thanks, Paul.
One moment for our next question.
Our next question comes from Kurt <unk> with benchmark your line is open.
Hey, good afternoon everybody.
Hey, Kurt.
So.
But Kevin I just wanted to.
A follow on a little bit on the supply demand dynamics in Canada.
Referenced in the call again, when you think demand exceeding supply and that could potentially lead to some rigs moving up from from the U S to satisfy that demand. So just kind of curious as you might give give some context around what do you think the shortage of rig capacity is right now in Canada.
Yes, Kurt.
I could go back to what I, what I know for sure at the beginning of the winter in 2023, we had demand for five rigs that we couldnt satisfy and didn't satisfy.
A couple of those were handled by tele doubles drilling little less efficiently.
And then following that.
The blueberry resolution they happen to be see that seem to push another 345 rig demand.
Customers come to us, we actually moved rigs back into BC that seem to push things forward.
In.
Discussion with clients today looking forward.
It seems like most of that is still out there.
Whether thats five rigs with seven rigs, it's a little hard to tell for sure.
I do think we will put a bit of a pull on.
Tele doubles, if you look at the basin right now Theres probably already.
15, Tele doubles drilling Montney wells right now or there has been historically.
Some operators like the lower rig cost, but most operators are drilling medium to larger pads.
The academics pretty quickly and determine that.
Even at a 35% to $37000 a day rate.
Our rigs that can drill a well 40% faster makes a lot of sense.
So I think that math will work its way through the system.
I'll be shocked if any rig targeting LNG sales gas is anything left for the triples rig.
So I think five to seven rigs that kind of how we see it which is why we think we might be pressed to bring one or two rigs up in the U S. Maybe late this year next year early next year.
Okay.
So anymore.
Okay, Alright and.
And obviously you gave the economic sense too.
What would incentivize.
Aegean to make that happen. So just now comes down to the sense of urgency at the E&P company level.
So we'll have to see how that shakes out okay. So.
The CES.
Another question I had was you kind of referenced.
Some longer term contracts and obviously this is a unique situation.
For Canada.
The question would be.
How many how many precision rigs do you think could be on three year type contracts if thats the duration as you kind of look at the needs for the.
The LNG pipelines are coming on.
Got it.
If this is just any kind of.
Unique dynamic or if there is a growing definitive growing need to lock in rates for longer term.
We had we had number of discussions.
With customers about two and three year terms.
I would say that we were reluctant to walk into any rigs in those longer terms because we were.
We're still trying to get rates up a little more.
I made the comment that we won't get back to earning out earning our cost of capital, which we think are the appropriate thing to do for business that so capital intensive like ours, but we still think rates in Canada to move up a little further.
Our customers have worked really quite well and I'm really pleased with the job that our.
Our sales team has done and our customers have accepted the increases.
But.
But I'm not prepared to walk it at these rates for.
Two or three years down the road.
Yes, Okay fair enough so.
A follow up question here on the Alpha.
Addison software and everything else. So it seems like there is.
Definitely a growing.
<unk> penetration and adoption rate.
What can you talk to you in terms of the stickiness.
And the dynamic of the alpha so once it's on it ranked us as an E&P company say well again that was kind of a nice little toy, but I don't need it anymore. So just kind of give some perspective on.
Whats youre getting a feedback from the from the E&ps.
Kurt we haven't had any customers turn off elfa.
As Dr. <unk>, they're all renewing contracts paperboard, where are these long term contracts, we signed in Canada and the U S.
I'll tell you what we are actually really focusing on right now is I think we have.
And App library of about 30 apps.
And our up utilization has been a little less than we'd like so we're really focusing now on.
Working with our customers testing out app, showing them and trying to prove the value of each up so I think we have a pretty good runway to get.
Wider scale adoption over the next few quarters, we've got a number of apps.
Really help assist drilling performance drilling consistency drilling repeatability, even as simple as measuring emissions.
And.
They all make good sense, we just need to do a better job.
Fully.
Proving the value of our wide customer base.
Okay.
So in our.
I'll remind remind me if I may what's the kind of average.
Great that you get for deploying these apps on a rig.
The current Humira, it's about $500 a day for the base system and then the apps would be anywhere from $200 a day to about $1000 a day per app.
So sorry, if this is like kind of almost evolving into a software as a service type of business that fare well.
Well, it's sort of but remember what.
Would I be clearance were up so we're not selling software we are selling a drilling operation and we're trying to really.
Really support our ability to drill wells efficiently safely consistently predictability repeatedly so the software is designed and intended to support that service not.
Not be a product on its own.
Got it okay. That's great I appreciate the color.
Great.
Thanks Kurt.
And I'm not showing any further questions at this time I'd like to turn the call back over to Nevada.
Thank you everyone for joining our conference call today, if you have any follow up questions. Please do not hesitate to contact me. Thank you.
Ladies and gentlemen, this does conclude today's presentation. You may now disconnect and have a wonderful day.
[music].
Okay.