Q3 2021 Helmerich and Payne Inc Earnings Call
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Good day, everyone and welcome to today's Helmerich <unk> Payne fiscal third quarter earnings call. At this time, all participants are in a listen only mode.
Later, you'll have an opportunity to ask questions. During the question and answer session. You May Register task of question at any time by pressing the star and <unk>.
1 on your Touchtone phone.
Please note today's call may be recorded I will be standing by should you need any assistance. It is now my pleasure to turn the call over to the VP of Investor Relations. Dave Wilson. Please go ahead.
Thank you Ryan and welcome everyone to Helmerich, <unk> Payne conference call and webcast for the third quarter of fiscal year 2020.
With us today are John Lindsay, President and CEO, and Mark Smith, Senior Vice President and CFO.
John and Mark will be sharing some comments with us after which we'll open the call for questions.
Before we begin our prepared remarks, I'll remind everyone that this call will include forward looking statements as defined under the securities laws such statements are based on current information and managements expectation.
1 because of the state and are not guarantees of future performance forward looking statements involve certain risks uncertainties and assumptions that are difficult to predict.
And as such our actual outcomes and results could differ materially.
You can learn more about these risks and our annual report on form 10-K, our quarterly reports on form 10-Q, and our other SEC filings.
You should not place undue reliance on forward looking statements and we undertake no obligation to publicly update these forward looking statements.
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Copies of the program will start from the very beginning.
Good day, everyone and welcome to today's Helmerich, <unk> Payne fiscal third quarter earnings call.
At this time all participants are in a listen only mode.
Later youll have an opportunity to ask questions. During the question and answer session. You May Register task of question at any time by.
And the star and 1 on your Touchtone phone.
Please note today's call may be recorded.
And you will be standing by if you should need any assistance. It is now my pleasure to turn the call over to the VP of Investor Relations. Dave Wilson. Please go ahead.
Thank you Ian and welcome everyone again to Helmerich <unk> Payne conference call.
The webcast for the third quarter of fiscal year 2021, with US today are John Lindsay, President and CEO and Mark Smith, Senior Vice President and CFO.
Both John and Mark will be sharing some comments with us after which we'll open the call for questions before we begin our prepared remarks I'll remind everyone that this call will include forward looking statements as defined under the securities laws such statements are based upon current.
The presentation and management's expectations as of the state. They are not guarantees of future performance forward looking statements involve certain risks uncertainties and assumptions that are difficult to predict.
As such our actual outcomes and results could.
Differ materially you.
You can learn more about these risks and our annual report on form 10-K, our quarterly reports on form.
The 10-Q and our other SEC filings you.
And you should not place undue reliance on forward looking statements and we undertake no obligation to publicly update these forward looking statements.
And we will also be making reference to certain non-GAAP financial measures such as segment operating income and operating statistics, you will find the GAAP reconciliation comments and calculations and Yesterdays press release with that.
I will turn.
Information of the John Lindsay.
Thank you, Dave and good morning, everyone.
Since the industry rig count hit bottom almost a year ago, <unk> rig count and market share gains have positioned us as the leading drilling outcomes provider and the U S land market.
In line with our guidance, we exited the third.
And third fiscal quarter at 121 rigs.
And today, we are at 123 active flex rigs.
We expect to continue to have a moderate and somewhat choppy upward trajectory and our rig count.
And as well as improved pricing over the next quarter.
Although there are of.
Turn the call ultimately.
260, idle Super spec rigs are available and the U S market.
We believe fewer than 10 of those rigs have actually worked within the past 12 months.
And many of those rigs have been idle from well over 18 months.
And there is a high cost involved and react.
<unk> long idled rigs, which typically presents 1 of those classic pay me now or pay me later conundrums.
Most importantly, striking the right balance of the startup costs enhances safety given operation, but it can also significantly impact the value proposition.
For customers by driving better metrics and drilling performance downtime and crew retention.
Our stellar track record of efficient startups.
Delivers greater customer adoption and is 1 reason why we consistently outperform as the rig count increases.
And as demand grows these reactivation expenses will continue to drive rig pricing higher as the.
The supply of work ready Super spec rigs become scarce.
All of the drivers that lead to enhanced pricing and contract the economics are in place.
Higher crude price.
The higher activity levels.
Higher reactivation costs pricing discipline within the industry and perhaps most important of all of our ability to deliver value and better outcomes to our customers.
In light of these factors, we have been and discussions with customers to increase pricing.
Further we remain optimistic that current oil prices will translate into higher 2022.
E&P drilling budgets and activity and the U S land market.
As of today discussions with customers regarding activity for the rest of 2021 and form our estimates.
<unk> of approximately 50 to 75 incremental industry rigs returning to work by year end, and we expect that to be backend loaded in the fourth calendar quarter.
That expected rig increase.
Coupled with the long idled fleet also enhances the potential for further.
For the rig pricing improvements and the.
Calendar quarter and into 2022.
Assuming oil prices remain stable and near current levels we.
We would not be surprised to see 2022 budgets for public companies drive further incremental increases and rig activity next year.
We expect the Permian.
We will continue to lead the way and incremental rig adds or.
Our leadership position in this region is multifaceted.
Have a superior infrastructure experienced people and the leading number of active super spec rigs at 67 rigs as well.
And as the largest inventory of idle super spec rigs.
This combination of attributes bolsters, the company's capacity for further growth and the Permian basin.
With this context in mind, let's now turn the field performance and the implementation of digital technology solutions.
And combined with new commercial models.
There is a growing appreciation for the value proposition.
<unk> provides us we're successfully growing our rig count with existing customers as well as partnering with new customers to achieve better drilling outcomes.
When.
And when utilized on a flex rig platform Hmp's digital technology and automation solutions like auto slide.
Our enhancing drilling outcomes, both in terms of efficiency gains and Wellbore quality.
The resulting in improved long term well economics.
Ex and returns.
We have multiple customers large and small public and private utilizing our flex rigs and digital and automation technologies.
This combination and enable them to reliably lower their overall well costs.
Improved.
Poor quality.
And reduced downhole risks.
Let me give an example of <unk>.
Recently, where we had a customer with the performance contract that was paying us well over market spot rates.
They were nervous about explaining that to their management team. However, they also mentioned and to.
And our management team that they were saving.
The quarter million per well by using A&P.
So as a result of that realization management wanted to continue to use <unk>.
On all of their wells and that expanded our rig count with that customer.
This outcome based approach, which.
As data driven delivers more predictive consistent and superior well results over an entire drilling program for our customers.
The great news these aren't 1 off examples.
We have these partnerships and results with majors large e&ps.
And private companies.
Over the past few decades, the methods the equipment, the technology and the risk profile and the drilling of unconventional oil and gas wells has evolved significantly.
However, the legacy day rate model construct has not.
As of the model for providing better drilling outcomes, we will continue to evolve and <unk> along with several of our customer partnerships as.
And is pioneering new commercial models to better align our performance with our customers' goals and allow us to share and the value added outcomes we help.
Create.
And less of pricing model and equitably share the benefits derived through better technologies and efficiencies.
And the ability of the industry to continue to innovate and improve will diminish.
We're pleased to see international activity start to pick up again after a long.
Hendrik pandemic driven hiatus.
We are participating in several tenders with both NOC and IOC, but these are very thoughtful flow processes and uncertain of timing.
In addition to working on new growth opportunities.
Argentina, and Colombia appear to be ready to put rigs back to work.
During our fourth quarter.
We are seeing some traction of our digital technology and automation solutions internationally as well our.
Our international Flex rig digital platform is capable of hosting our automation solutions.
Which we believe will be a driver of additional flex rig adoption.
Before turning the call over to Mark I wanted to touch on sustainability.
We have a long history of offering solutions, which helped both A&P and our customers' sustainability needs and we continue to invest and these and other sustainability efforts that.
And that benefits all our stakeholders our employees.
Customers vendors and investors and society at large.
We're partnering with our customers and taking a thoughtful and methodical approach to offer solutions to fit their desired outcomes, both from an environmental and economic perspective.
We have many solutions and our toolkit that we have.
And our for many years such as using alternative power sources at the rig like natural gas engines highlights power or dual fuel engines.
More recently, we've invested and energy storage solutions, using battery technology and rig engine efficiency software solutions.
To help reduce greenhouse gas emissions and lower rig fuel consumption.
As I mentioned on the last earnings call. We are committed to publishing our inaugural sustainability report in 2021, which will include important data and information about our sustainability efforts and success.
Hedges.
In parallel to the development of the report we have also increased sustainability disclosures on our website.
Which includes data and information about emissions safety and diversity equity and inclusion.
Last year, 1 of the renewable investments, we made was and geothermal resources.
<unk> many years ago, we intermittently drilled conventional geothermal wells, but of new unconventional closed loop approach to geothermal is creating a viable source for renewable energy going forward.
<unk> has a team dedicated to investing and participating in geothermal and where.
The drilling technologies and expertise are readily transferable.
So in closing we remain optimistic about the industry and our ability to capitalize on our scale and our distinct capabilities as we focus on delivering the best outcomes for customers and value for our shareholders.
And now I'll turn the call over to Mark.
Thanks, John.
Dave I will review our fiscal third quarter of 2021 operating results provide guidance for the fourth quarter update the remaining full fiscal year, 2020, 1 guidance as appropriate and.
And comment on our financial position.
Let me start with highlights for the recently.
And we completed third quarter ended June 32021 the.
And the company generated quarterly revenues of $332 million versus $296 million and the previous quarter. The quarterly increase in revenue was due to higher recount activity in North America solutions as expected.
The total direct operating costs incurred were 257.
And for the third quarter versus 232 million from the previous quarter.
The sequential increase is attributable to the aforementioned additional rig count and in North America solutions segment.
General and administrative expenses totaled $42 million from the third quarter also consistent with our expectations.
Our Q3 effective.
<unk> million dollars ex rate was approximately 30%, which was above our previous annual guided range taxes were positively impacted by a discrete tax benefit primarily related to a change and the state deferred income tax rate.
To summarize this quarter's results agency incurred a loss of <unk> 52 cents per diluted share versus the loss of $1.13.
The income dense and the previous quarter.
Third quarter earnings per share were impacted by and by a net <unk> <unk> gain per share of select items as highlighted in our press release.
Absent the select items adjusted diluted loss per share was <unk> 57, and the third fiscal quarter versus the versus an adjusted <unk> 60 loss during.
The second fiscal quarter.
Capital expenditures for the third quarter of fiscal <unk>.
<unk> 21, or $18 million with year to date spending levels below our previous implied guidance plan of spending continues to shift of the right, but we are expecting and more significant spend and our fourth fiscal quarter, which we will discuss later.
And.
Turning to our 3 segments, beginning with the North America solutions segment.
We averaged 119 contracted rigs during the third quarter up from an average of 105 rigs and fiscal Q2.
As John mentioned, we exited the third fiscal quarter with 121 contracted rigs.
Also had approximately 15 rigs roll.
Off term contracts and into shorter term contracts during the quarter as customers maintained their budgeted drilling programs.
Revenues were sequentially higher by $31 million due to the aforementioned activity increase North American solutions operating expenses increased $20 million sequentially and the third quarter, primarily due to the addition of 12 rigs and the 1.
And time reactivation expenses associated with those rigs was approximately $6 million and fiscal Q3.
Looking ahead of the fourth quarter of fiscal 'twenty, 1 for North America solutions as expected rig count growth was more moderate during the third quarter as of today's call. We have 123 contracted.
Rigs and our expectations.
And it is too and the fourth quarter of fiscal 'twenty, 1 with between 127, and the 132 contracted rigs and publicly traded customers continue to operate within their calendar year budget plans. So most of our recent and active rig additions were driven by privately held customers.
Still see opportunities for publicly traded customers to add rigs of late.
Dictation and this calendar year as capital budgets of refreshed heading into 2022.
And the North America solutions segment, and we expect gross margins to range between $72 million to $82 million with no early termination revenue expected as we continue to add rigs of onetime reactivation expenses continued to pressure margins, we expect those expenses.
Approximately $8 million and the fourth quarter as I mentioned and the last quarter. The length of time of rig has been idle and the cost required to reactivate it and have a direct correlation.
Most of the rigs we are reactivating and the fourth quarter of and Idaho for 12, plus months reactivation costs were mostly incurred in the quarter of startups of the absence of such costs in future quarters.
<unk> is margin accretive.
Said, some expected reactivation costs and the quarter ended September 30 will be for our rigs readied for October commitments.
As John mentioned, we are expecting to achieve higher pricing in light of higher demand and tight and ready to work Super spec supply.
However, due to varying.
<unk> effective date of new rates.
Most of the benefits of on margins will be realized in fiscal 2022.
Current revenue backlog from our North America solutions fleet is roughly 493 million per rigs under term contract.
Okay.
Regarding our international solutions segment International solutions business.
And this activity averaged approximately 5 active rigs quarter on quarter and.
And we did add a sixth rig late in the third fiscal quarter.
<unk> contribution was in line with expectations for the quarter, albeit towards the low end of the range.
As we look towards the fourth quarter of fiscal 2021 for international currently our activity.
And Bahrain is holding steady with 3 rigs working and we have 3 rigs under <unk>.
Contract and Argentina during the quarter, we expect a little churn and our international rigs as a rig and Bahrain as expected the stack, but and additional rig and Argentina is expected to commence work.
Further the contracted rig and Columbia is expected to commence operations very late in the quarter.
And the fourth quarter, and we expect operating and gross margins to be between breakeven and the loss of $2 million apart from any foreign exchange impacts.
Turning to our offshore Gulf of Mexico segment, we continue to have 4 of our 7 offshore platform rigs contracted offshore.
Offshore generated a gross margin of $9 million during the quarter.
Quarter was at the high end of our guided range.
As we look towards the fourth quarter of fiscal 2020.1 for the offshore segment, we expect of the offshore will generate between $7 million to $9 million of operating and gross margin.
To conclude third quarter results commentary I will highlight our non operating other segment activity.
As a reminder.
Under at the start of fiscal 2020, we elected to set up the wholly owned insurance captive to ensure the deductibles for our workers' compensation general liability and automobile liability insurance programs from October 1 and 2019 forward.
Our operating segments pay monthly premiums to the captive for the estimated losses based on an annual external actuarial.
<unk> analysis.
The result of the transfer of risk from our operating subsidiaries to the captive for the deductibles.
Which of our self insurance retention.
The actuarial estimated underwriting expense can vary from quarter to quarter as claims developed get settled or dismissed for the 3 months ended June 32021, and the estimated reserves and the.
The captive were adjusted upward for self insurance claim developments.
Now, let me look forward to the fourth fiscal quarter and updates physical.
Full year, 2021 guidance as appropriate.
Capital expenditures for the full fiscal year 2021 are now expected to be at the low end.
Previously guided range of $85 million to $105 million with as mentioned earlier more spend expected during the fourth fiscal quarter than the preceding 3 quarter average. This back end weighted fiscal year spend is primarily due to some skidding to walking pad capability conversions as a result of select customer demand.
All.
Our expectations for general and administrative expenses for the full fiscal year 'twenty, 1 and have not changed and remain at approximately $160 million.
We also remain comfortable with the 19, 24% range for estimated annual effective tax rate and do not anticipate incurring any significant cash tax and fiscal year 'twenty, 1 and the.
And the difference in the effective.
Rate versus statutory rate as it related to permanent book to tax of differences as well as state and foreign income taxes.
Now looking and our financial position.
We had cash and short term investments of approximately 558 million of June 32021.
Versus $562 million at March 30.
Including the availability under our revolving credit facility liquidity was approximately $1.3 billion.
Our debt to capital at quarter end was about 14% and our net cash position again exceeds our outstanding bonds. As a reminder, we have no debt maturing until 2025, and our credit rating remains investment grade.
Good.
Given our current outlook for activity, we expect to see minimal changes and our cash balances and fiscal year and compared to June 30 balances.
At today's activity levels, we believe our forward quarterly operating earnings will fund, our maintenance capital expenditures debt service costs and dividends and our expectations beyond.
The 1 this quarter for rising activity drives our run rate cash generation higher while on the other hand at least and the short term a good portion of that higher cash and duration will be consumed by reactivation expenses and working capital investments required to enable that future higher activity.
As John mentioned, the cost control remains of high priority.
And since we last spoke on the March.
Earnings call. We are advancing along several work streams that are being carried out in parallel to adjust our cost structure. Some items expected to be completed and the fourth.
The fiscal quarter will culminate and approximately $7 million of annualized savings, primarily and operating expenses. We are working on other.
Other initiatives that will be completed in the coming quarters to further optimize future run rate expenses.
And as these plans progress we will provide updates on future calls about the expected magnitude and timing of these various cost structure initiatives.
That concludes our prepared comments for the third quarter now, let me turn the call over to.
David.
For questions.
At this time, if you'd like to ask a question. Please press the star and 1 on your Touchtone phone you may remove yourself from the queue by pressing the pound key.
Reminder, if youre using speakerphone, please pick up your handset to provide optimal sound quality.
And that is.
Star and Juan.
We will take our first question from Tommy Moll.
Please go ahead.
Good morning, and thanks for taking my questions.
Good morning, Tommy.
John I wanted to start on.
The issue of cost inflation, any anecdotes or number.
And as you could offer in terms of what youre seeing whether it be on the labor side transport materials.
And thats hitting that.
Average daily cost line, you would want to call out.
Tommy.
And.
Our labor.
Number of costs have not increased.
We did and reduce our our wages and the field operation.
During the downturn and.
So there hasnt been any impact there, there's not really anything specific that we can.
The point.
Right now other than.
And the costs associated with reactivating rigs.
Overall, you've heard discussion and just in the industry in general in terms of tubular both casing as wells drill pipe.
And I think Thats drill pipe is probably something and that will be.
And 2.
And something we're going to have to be acquiring more of and the near future and I would imagine with steel prices at the.
The cost of 2 bidders are going to be higher there.
So those of the things that come.
Come to mind, right now and the inflation side.
That's helpful. Thank you John.
Wanted to follow up on the geothermal comments that you made.
And the earnings release, you talked about some investment opportunities and into other companies.
And so I just wondered if you could share of any any thoughts around what those might look like or what should we think about these is likely.
Artist size of investments or something larger and and more broadly just any anything else you want to offer in terms of the opportunity of going after there with geothermal generally would be great.
Sure well like we said and our.
And our.
Remarks.
We think it's of great.
The opportunity.
And there are several different technologies that are out there that are much different than the conventional.
Geothermal that we've seen forever I mean, I remember hearing about wells we drilled.
Probably back in the <unk> and the seventies, but much different type.
The mother of operation and I think these are opportunities for us, yes to make investments and the companies, which we have but they have been modest investments.
But it gets us a seat at the table and there's some partnership opportunities.
And definitely transferable expertise that we have.
As of as a driller and as a technology provider.
And that we can that we can use so we've made some really strong.
What I would consider early partnerships with the 3 different companies and.
I think we're going to actually have Juan.
Operation that will be starting up here soon and drilling.
The operation if I'm not if I'm not mistaken so that's encouraging Mark do you have anything no John just.
As it relates to the drilling operation we have some some of these investments and these early partnerships that are and cash and somewhere in the form of any kind of investments through the drilling services.
And in addition to the 3 John mentioned.
Have we have a couple of other things and the pipeline, including and LOI on Juan So excited about a variety of different technologies and the Geo spectrum, including the closed loop system, John mentioned in prepared remarks, as well as from some other type of emerging technologies as well.
Thank you both I will turn it back.
Alright Tommy.
Thanks.
And again that is star and 1 task of questions. We'll go next to John Daniel with Daniel Energy Partners.
Please go ahead and good morning, guys. Thank God of Johnson and the call.
I'm driving here is not a lot of miss something but.
If I heard you.
And you correctly opportunity for call. It 50 to 75 rigs across the U S by year end.
And yes, mental math mental math as you are about 25 per cent of the U S market, the ballpark give or take.
And do you have and excellent reputation. So my question is what if you just said and out of your customers. If they don't want us and on your pricing model.
What happens.
Well.
I would imagine there would be and well first of all of that.
That wouldn't be our approach and that.
The.
We see this we see this as of.
It really is a part as a part.
Yep.
But but clearly the market is tight and and.
And customers are looking for the best solutions.
Looking to the <unk>.
Better outcomes more reliable outcomes, we are of great track record.
And for starting rigs out of stack as I said and the remarks, there's less than 10 rigs that have worked and the last and the <unk>.
Last year everything else is.
15% to 18 months I mean, there have been idle for a long time so.
You want to make certain that youre working with somebody.
<unk>.
It's going to be able to deliver coming right out of the chute. So.
Yes.
It's a great question, but the difficult 1 to answer I think and general we'd be able to.
And really the encouraging.
The news is that we do have customers that are interested and shifting the model.
Model, because they see better results out of it so.
While theres going to be some customers that are going to want to continue to use the day rate model that's fine.
Yes, it will be we will obviously be pushing pricing on the day rate model as well.
Do you find that those willing to sort of embraced that model.
The view are they.
Don't want to say private companies aren't sophisticated that'd be a sense of the some of my friends, but is it the larger public people that are more likely to embrace the model are now.
John and and.
Past cycles I would.
Of course, we didn't have near as many rigs working for private companies.
And back in those days, but I've been very encouraged that weather.
Super major large independent.
Net cap.
PE backed small private company.
Across the board, we have customers that are interested and technology.
They're interested.
And it and trying to figure out how to be more effective more efficient more reliable and we're all trying to do this right. We're trying to make our business as efficient and effective as possible and we're working together with other suppliers.
On location to do.
That so.
I see it is really across the board and I think we will continue to see that trend and a great example is look at the number of private companies today that are using AC drive Super spec rigs.
Whereas 3.
3 years ago, and many cases they were using.
Smaller players with SCR rigs and even some mechanical rigs.
So there's a there's a big shift.
Those private companies that are the most sophisticated that or the the best.
And doing what they do.
And are the ones that are that are getting the the.
And the investment dollars and and we're just pleased to be able to partner with them.
Okay very.
Very good color and get get anecdotes and the messaging and the prepared remarks the final 1 from me.
More of a I guess, a housekeeping I guess, but can you remind me where you peaked in Argentina.
And then just.
Just some thoughts on that specific market as you head into next year.
Let's say 10 or 11, and I think it was was it the.
Because the tender of 11, Dave do you remember the kind of moving out of the Max.
11.
So we have a we have 3 working now and the fourth 1 is.
They said about to go back to work.
With the discussions with the operators for even more interest.
Okay.
Thank you guys very very much.
Thanks, John and be careful.
Okay.
Well go next to the station.
Because we don't go and Palmer.
Please go ahead.
Hey, guys. Thank you for taking my question.
And Sir.
So it seems like.
The near term dated improvement can come from as the rig that had been idle for a long time they have to be on stacked up.
Maybe if you can just frame it for us.
Like what is the rig reactivation cost today, where can it go.
And is that how are you getting paid for that and maybe just on top of that if you can think of if you can help us just think about what drives the.
<unk> improvement from.
The year on given we still have about 200 and so.
Net rigs available.
And that will be helpful.
Rather simple.
We'll start I'll start with just the the reactivation process and then turn it turn it over to Mark.
I think cost wise, we're probably at least and our fleet today.
4.
The 500000.
To reactivate a rig and.
And.
Early on as you think about how many rigs we've reactivated we've reactivated I think 76 or 77 rigs.
And so those early rigs were 100100.
The $50000, so as we've gotten deeper into.
The rigs that have been idle and I have a longer and longer period of time, obviously it costs it costs more money.
Our our goal is to get that reactivation cost paid back and there are several different ways ways to.
Do it and obviously term as is.
A portion of the term or performance based pricing.
And we're just not going to go out and reactivate a rig and spend 4 of $500000 and just and just drill 1 well.
We're going to have to have quite of bit of work lined up and then again, we're going to 1.
I want to be able to.
Share and the.
The.
And the improved outcomes that were that were delivering and fortunately and like I said before and our prepared remarks and the earlier question. We do have customers that are that are willing willing to do that.
What else to add on to.
I would just question I'll, just footnote the Atlas and <unk>.
A little bit of numbers detail, John and if you think about them the.
The margins from our perspective really the the regular apples to apples quarter to quarter operating margins bottomed out in Q4 of fiscal 'twenty and what.
And we've seen this year.
And margins are affected by these recommissioned and cost primarily and if you think about what we just guided for Q4.
They were and now <unk>.
$8 million, if you do the math on that.
And that can of.
Basically equate to about $700 of day detriment.
Our key.
For earnings and the absence of that.
Q1 fiscal of 'twenty to $700 improvement and margins just for those reactivated.
Rigs does that helpful.
The effect and actually that's a good segue into my next question. So.
And you guys have obviously.
And then good job on bringing on.
And the cost you guys still looking on that I can understand.
And let's say in a couple of Esa of maybe.
Maybe if you are talking about 200, <unk> HB and rigs working how should we think about the normalized cost we don't have.
This is particularly active share cost and we have kind of normalized.
<unk> cost levels.
Can make any day of aggregate that input.
Sorry go ahead.
Kind of say if it would come back to that impacted the 13000.14000 barrels of artist at a different level now.
It's TBD and other pressures in multiple directions, but.
B G.
And just to remind you of little bit last year, we had significant across the board cost reductions and I think we took.
And and.
And the last fiscal year about $50 million of Opex of $25 million out of SG&A and.
And that was to reduce what had been of growth scale for the company.
No.
We did not cut to the bone and we have the largest super spec capacity. So we have the.
Available to put back to work and we have the highest public company exposure, which positions us well.
As John mentioned for potential of calendar year, 'twenty, 2 budgets and the resulting rig additions.
So what we're working on now.
And this is really.
Further cost out initiatives that are very targeted.
We're trying to improve efficiencies internally and processes and service delivery models automation and technology.
And so that $7 million. We just mentioned is the first installment as we continue to work through numerous work streams and internally.
Sure.
So it's too early and it's too early to tell but suffice it to say we are working to get that.
Historical daily average cost back down and then just see how the market <unk>.
In the interim and really the related to any inflation questions as John said, we certainly arent experiencing that and labor today, but.
We just have to see as we unfold through the coming quarters, what happens for the pressures of the other direction.
And <unk>.
If I can ask squeeze and the last 1 so obviously you guys lowered the capex budget towards the lower and for this fiscal year.
Given the steel prices, increasing and activity.
David the increasing.
How should we think about Capex for next year.
Well.
We've been at this lower capex level.
A level as you said and.
And the short of short term, we hope to continue a bit of momentum and that range, but I think it's early days there.
Actually and our budgeting process as we speak so not ready to be definitive yet but.
And through fiscal 'twenty, 2 I can see.
The south of 500000 per active rig maintenance capex per annum today and could see us going from a $500 of 750 range in fiscal 'twenty, 2 although as I said.
Early days and our budgeting process and then as we move through time and maybe the fiscal 'twenty 3 prognosticating back to the historical range of 750000 and $2 million. So we're still benefiting from being able to harvest a lot of the componentry that we had back when we were a scaled up to be of larger growth company and as we as we are.
And move through time, and reactivate rigs will obviously have to eventually catch back up with harvesting and those kind of.
And those components that are really benefited us.
Here in fiscal 'twenty 1.
That's helpful color. Thank you and thank you for taking my questions.
Thank you.
We will go next to Waqar Syed with ATB markets. Please go ahead.
Thank you for taking my questions.
John as your rigs return.
Back to work and the international markets.
Do you expect the day rates to be higher.
And they were getting before they were stacked or do you think they're going to be discounts.
Versus prior day rates.
Well, we have some rigs that have gone back.
I'm not certain on.
And what our level of pricing is today versus when the idled I don't.
Dave If you do it.
It's going to vary.
Yes, I think it's I think it's.
And some cases there'll probably be similar again.
Wish I knew more of the details of car, but but.
But I don't at this stage.
I would imagine early on and there'll be probably some.
Some of discount compared to.
When when there were more rigs running just from a supply demand perspective.
Okay. So the market right now for internationally generally you would say is still.
Yes.
Despite the reactivation of.
Cost of reactivation rates are likely to be soft for now and maybe a year. So not from now when the market tightens and then is that a fair statement.
It's hard to it's really hard to say what car to say yeah.
I mean.
You've heard us say before it's kind of it's really hard to see out more than a quarter or 2 but it doesn't take much activity to tighten that rig count.
The rig supply pretty quickly and countries like Argentina as an example.
And and that sort of the case I think we could see some improved pricing.
And pretty quickly but.
The international market has just responded very slowly and again, our expectation that's kind of pick up here soon but.
It's hard to say that much on the on the pricing side.
No John I would just add to that I think.
And certain markets it could be analogous.
Year to what we've been talking about today with the U S and.
Of course for example, some of these customers and Argentina are interest of the car and Super spec.
And so again, you get to that very tight supply and meeting that customer demand and that is.
As we are experiencing and the U S and ours.
And that's very helpful. The pricing.
Yes.
Now in Bahrain, and you've mentioned that you're right.
The stack.
And Jim our view would have been that more rigs are going to go back to work. So this is kind of a surprising data points that the rig is being stacked and it was working is there anything specific to.
And that particular range that particular.
The clients are.
How should we be reading that data point.
It's just where the customer is at this point and the program and I think its I think its budget driven and it's.
1 of those things that.
We're so good we've drilled ourselves.
But out of work and so I think we had 3 rigs running and.
Just have enough budget to run too for the next whatever period of time my assumption would be the third rig would eventually go back to work but.
Generally speaking there has not been a huge change and the program.
Yes.
It's a low.
Last question.
And you hear about labor shortages, and especially on the trucking side and the truck drivers and.
Are you seeing any inefficiencies developed in the.
And the.
The drilling process because of the sites and not getting.
Getting ready on time.
Fast and that are getting ready on time or.
The customer or any other service companies and not getting equipment on time, and the well site and thus.
The time to drill wells is increasing are you not seeing that at the moment.
Well.
The car and at least and our operations and I can't really speak to others.
We've got very high levels of <unk>.
Performance efficiency levels are high.
Our customers are managing their pad construction well I mean, you are right there as of.
Really and overall national.
Shortage on the truck drivers.
To my knowledge, we've not had a huge impact and and moving our rig of the good news is as we move rigs as often as we used to because of pad drilling.
But in general I see I see us performing at very very high levels of.
And really we've not had any challenges to speak of simple.
We've got a great group of people in the field, great leadership, and a pretty strong bench so.
We're pleased with that but I can't I can't think of anything and we are.
Where we're having to wait.
And we're seeing inefficiencies.
Great. Thank you very much I appreciate the answers thank.
Thank you Waqar.
And we'll go next to Neil Mehta with Goldman Sachs.
Hey, this is at the on for Neil.
So looking at the rest of the yard and into 2020 to most of the incremental activity here on seems like it could be driven by the majors potential.
Potentially some private as well could you remind us of the exposure you have with them relative to your peers and what the upside could look like for.
And the number of rigs that could be either from here on.
Sure. That's a great question and I will say that it's interesting and we all we.
And we've all heard these numbers, but 1.1 snapshot as of the last 100 days 42 rigs of gone to work and 39 of those rigs were from <unk>.
Privates, so the privates have really been making a difference in 'twenty, 1 and about 75 per cent of the work. We got 11 of those 42 rigs, but I think going forward, it's going to be a combination of.
The majors large independents.
I think just the public.
<unk> traded companies in general when budgets are reset for 2022.
Let's assume.
With the current budgets are $45 to $50.
If you think about.
The 60.65.
Type type of number is going to have I think of.
Pretty significant pickup and activity.
So I think it could be that we're seeing some of that even hitting at the back half of the year.
I think our current exposure I think we've got 35% of our current fleet working for privates historically it.
20%, So we're very pleased with.
And that ability, but we still have 65% of of our.
Current fleet.
With the publics and if you look at those customers, who were our largest customers as the top 10 customers.
Prior to the pandemic.
Those were the companies that.
Reduce the rig counts the most and so again, our hope is that those companies are responding.
And of strong fashion for them.
Much stronger 22, and we will see and outsized growth on our our rig count.
And that's our hope.
Ben trade.
And then.
It looks like around 80% off.
Current active rigs of Super spec based on the supply numbers you provided.
What do you view as the upper limit to the Super spec rig share of the act of U S accounts.
Well as you said it continues to grow.
Share I think today, Dave, 70% or 70 still SCR rigs.
<unk> rigs that are out there working.
We're seeing.
Really just every type of E&P out there small and large that are.
Continue.
<unk> to shift to Super spec capacity.
And it really makes all of the sense and the world because youre going to.
Laterals are getting longer well complexity of getting greater and those rigs just have a much greater capacity to drill those wells and do it do it and a really efficient fashion.
I mentioned in my prepared remarks about data.
It's really difficult to utilize the dataset coming off of and old technology, SCR and mechanical type rig so the dataset that we're creating coming off of our <unk> platform really enables.
Is to utilize technology.
Software solutions that you just can't do.
And older generation rigs so.
I think at some point in time, and you're just going to continue to see those those rigs.
Rig numbers continue to drop and get displaced because of the value proposition is so huge.
Great. That's very helpful. Thank you I'll turn it back.
Okay. Thank you.
And we'll go next to Derrick part of <unk> with Barclays.
Hey, good morning, so it looks like your margin implies margins are starting.
And for all of the reasons, you mentioned before and market. Thank you touched on and a little bit but thoughts on it.
And it fits Gulf <unk> represent the bottom and the North American loose and margin margins and EBIT margin growth heading into fiscal <unk> 'twenty 2.
Yes.
I think it's what I said in Q4 'twenty.
So.
Suddenly, it's we're going to we're going to continue to have as I've mentioned.
Drag on current earnings with the re commissioning expenses.
But as those free up eventually and you have a more normalized higher.
The rig count and certainly more cash flow and margin.
From the absence of those costs, but maybe more importantly.
All of the stuff John has been talking about this morning related and the pricing that can help drive up those margins.
I think those 2 things added together bode quite well potentially for fiscal 'twenty 2.
Yes got it and so just to clarify you believe the margins will come up from the 6600 implied range, even even with the burden of the reactivation costs just thinking about the trajectory as we start in fiscal 'twenty 2.
Well, that's going to depend and we just have to see how many.
Divisions, we have and those quarters, and we have not yet guided too.
Okay understood.
1 of your extend the geothermal market wanted to get your thoughts on what you see is the total addressable market for you guys and maybe any sort of insight of what that can mean and your top line growth over the next.
Reacting of 3 to 5 years and it starts on the call.
I think it's.
I mean, obviously, we've done some modeling, but I think it's still too early.
For us to put a put a number out there because these technologies are really still and the belt of the developments.
Pages.
I mean it.
And the technology looks great.
We've got to go out and actually do the work and see what kind of.
Energy can be generated over time.
But I think it could be.
It could be a bit of a needle mover.
And again I think.
The internal capacities that we have and expertise we have is really aligned well with with that but I. Just think of trying to trying to give a number today is pretty hard to do and just the footnote and some details of what why that's so hard and our.
Our own research and modeling.
<unk> certainly what we're trying to do is of an alternative use for the installed rig base of assets and we do see opportunity for that but as John saying what that is is hard the hard to pinpoint.
Even though the U S department of energy.
Potential wells that could be drilled.
It just varies of why wildly and why is that and that's because all of these technologies are and such early stage development and it's hard to know which of them will be successful and if successful to web scale and there'll be applied.
So more to come but.
But.
And again I think 1 of the things that and that's exciting for US is the transferability of the technologies that we're using to drill these horizontal wells.
We drilled a U shape horizontal well a couple of weeks ago that was just amazing when.
When you look at it and you just think about that type of technology and and how we're just continuing to advance and our capabilities. So but as Mark said, it's just impossible the nail and number at this stage.
Right no fair enough, but all of that color was very helpful. And then if I could just squeezing 1 more.
And you talked about some of the newer equipment on the rig side and missions friendly also helps economically can you just maybe give us some details around the emissions savings when thinking about high line are dual fuel or some of the power management with battery backup I'm just curious your thoughts on how the admissions, it's the savings and how much of a needle move into sales.
For your customers as far as the.
He is a more friendly with ESG.
Yes.
Highlight and power has been around for a very long time of we've worked in fact, the very first flex threes that we built the very first 1.
And as fourth was actually on highway empower the problem is of course with the local grid.
So again and then it also depends on the Where's the power.
And that's generating.
Are you burning natural gas are.
And our coal as an example.
So clearly.
And we build natural gas is is just the super clean fuel.
What we've seen as a company over the Dave what over the last 2.3 years, we've had what sort of percentage and emission reduction.
Around 10% 10 of 11%.
And a lot of that.
Really the say we've been successful by more manual methods and so I think as we become more effective with power management at the rig site.
Even burning diesel.
To continue to improve our emissions.
Don't have.
It on.
<unk> dual fuel or no.
And going to depend on from the location and athlete and the application.
Yes, there are some challenges at times associated with the dual fuel applications with the methane slip.
But what we do know is that we are continuing to drive.
On improvements Youll see that and our sustainability report that will we'll publish later later this year obviously the battery power has some advantages at this stage of the game not super economic because the cost of the batteries.
There are some other solutions that we're.
We're working on internally.
To help our customers.
And together working with our customers to reduce emissions, but I don't have any real hard and fast numbers at this point.
Got it more to come with more to come on that Youll see that in October November timeframe.
Great and I look forward of it that's all my.
And thank you.
Thank you.
Time for 1 last question, Dave since we started a little of late.
And we will take our last question from.
Aaron and Shanghai.
Please go ahead.
Yes, good morning, Arun <unk> with JP, Morgan and John You mentioned.
And good morning, you mentioned you know for the calendar year do you expect maybe 50 to 75.
The incremental rigs industry wide.
With some potential for maybe a mix shift over time towards the publics.
And I was wondering if you could maybe comment on at a base.
And level, where you are you seeing some of the incremental rig demand and are you starting to see some.
The improvement in demand conditions, and natural gas basins with the with natural gas now at least the spot prices near term price at $4 per Mcf.
We are.
And low we were actually talking about that this morning.
It's been about 30 days or so since that.
Real uptick and Nat gas prices and we're starting to see that flow through and.
Hopefully going to begin to see customers.
Investing more and the drill bit for the natural gas.
Sure.
And so I think thats, an encouraging so any of the any of the natural gas areas.
Some of the gasior areas, even in the Eagle Ford.
We're seeing some.
Some interest so really it's just it's kind of across the board as you look at the.
And the.
And whether it's in the northeast or the other gassy basins.
Got it and then.
You mentioned in terms of the major you'd expect call. It their activity has been actually down since the bottom of the rig counts. So you would expect.
The new budgets and next year that could rekindle some.
<unk> set demand for the majors is that correct.
That's what we're expecting and what we're seeing and discussions with.
And with customers and it really it only makes sense.
Dave just everybody has done all of the E&ps have done such a great job in terms of being disciplined and sticking.
Some of the hits.
And.
And clearly.
And a higher commodity price environment, whatever that oil price may be.
60 to $65.70, and we're going to we're going to see much larger budgets and then what we have today, so I do expect to see.
The rig counts grow.
And with with the majors as well as really all of the publicly traded companies that we've had conversations with at least.
Have have talked about having rig needs.
Late late Q4 or into the first calendar quarter of 'twenty 2.
To the right and then just as my follow up John and the whole industry has been driven.
By a day, we're kind of philosophy read some of the history and.
The use.
Articulated kind of the evolution of your contracting philosophy and just.
And more.
I wanted to ask you about what kind.
And of barriers.
See from traditional E&P major procurement departments.
Focus on day 1.
I'm trying to think about is it difficult to break down some of these historical.
Historical Bayer barriers as you kind of move forward.
I would I think I would.
Or is it is.
Change will change is never easy and this industry.
Is it.
As an easy to change I mean, we all struggle with it.
But at the same time, we're also.
<unk> and each of our companies to figure out ways to do things.
The <unk> better more efficiently.
And you can't you.
Save your way to prosperity.
Got to invest and you've got to invest in technologies and so yes, the supply chain plays a role but in the and the customers again like I said earlier.
Large and small that we partner with today.
There is of value component that supply chain recognize recognizes so using that example of.
If we're able to work together deploy our technologies and.
And and be able to share.
And those savings and we're saving the customer a quarter of a million dollars of well.
Well thats really what they want and so it's it's.
It's really leveraging the technology building commercial models that makes sense for <unk>.
For both parties and.
And we just want to share.
Share and that because we're investing real money and.
And our technology solutions, we've invested millions of millions of dollars and these and the solutions and they at the end of the day add great value for customers. So.
It's like anything it's.
It's slow in some respects the early days.
Flex rig we're not easy.
But.
We have early adopters and Thats, the great news and the.
And this business is pretty small so people.
People share share ideas and began to want to try it out.
So we're encouraged by that.
Great. Thanks, a lot John.
Alright, Thank you have and good day.
Yes.
Yes.
And there are no further questions I will turn it back to the speakers for closing remarks.
Okay. Thanks, again, everybody sorry for a little bit of a late start there but.
And again, we remain optimistic about the industry and <unk>.
And how things were looking for the rest of 'twenty, 1 and going into 'twenty..2 so look forward to talking with you in November.
Take care.
And this does conclude today's program and I appreciate your.
Shannon you may now disconnect.
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Yeah.
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