Q2 2021 Helmerich and Payne Inc Earnings Call
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Good day, everyone and welcome to this helmerich <unk> Payne fiscal second quarter earnings Conference call. At this time all participants are in a listen only mode. And later you will have the opportunity to ask questions. During the question and answer session. You May Register to ask a question.
And at any time by pressing the star and Juan on your Touchtone phone. Please note. This call is being recorded it is now my pleasure to turn the call over to Vice President of Investor Relations. Mr. Dave Wilson. Please go ahead Sir.
Thank you, Jim and welcome everyone Day Hurricane Pains conference call and webcast for the second quarter of fiscal year 2021.
Today are John Lindsay, President and CEO, and Mark Smith, Senior Vice President and CFO.
And John and Mark will be sharing some comments with us after which we'll open the call for questions.
And we begin our prepared remarks, I'll remind everyone that this call will include forward looking statements as defined and under securities laws such statements are based on on cash.
Current information and management's expectations and.
As of the state and 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 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.
We will also be making certain references to non-GAAP financial measures such as segment operating income and operating statistics, you will find the GAAP reconciliation comments and calculations and yesterday's press release, and all that said I'll turn the call over to John Lindsay.
Thank you, Dave and good morning, everyone.
Reflecting on where we were at this point last year I'm encouraged by the recovery. We are currently experiencing as well as how the company has navigated through a multitude of challenges in 2020.
Last year I said that two factors were crucial for our continued success going forward.
First maintaining our financial strength and second maintaining a long term focus for future opportunities.
I'm happy to report that the company continues to execute and both areas.
Today's mid $60 oil price is robust compared to what we experienced over the past year.
But going forward, we anticipate a degree of permanence and the change of historic industry behaviors and norms.
Energy markets are coming back into balance and global oil demand is reviving and oil inventories are falling back to their five year average.
The energy industries capital discipline, which actually began prior to the global pandemic also remains resolute.
Well. This last point is uncomfortably limiting for the industry's near term growth horizon. This is something we believe is imperative.
Focused disciplined spending that generates returns under a variety of commodity price scenarios.
It's what the industry needs to attract and retain investors.
Back to the long term focus and what we believe the future holds for H M. P.
And natural step and capital discipline is driving the most value per capital dollar spent not just and a one year budget cycle, but over the life of an investment.
This corresponds to where we believe <unk> as the leading drilling solutions provider <unk>.
Tributes the most value to our customers and is the driver behind the development of our digital technology solutions.
And our new commercial models.
And that are structured around achieving value added outcomes.
Aligned with our strategic objectives H M. P will continue to concentrate on delivering value to the customer by leveraging software data and flex rig technology.
Our digitally enabled drilling operations provide automation solutions that deliver both efficiency gains and wellbore quality.
Not only do our customers experience near term financial benefits like lower well cost and the reduction of certain downhole risks, but also improvements and areas that were historically beyond our ability to influence but have significant economic implications over the long term line.
For the well.
And important ingredient to a successful technology strategy is the integration of new commercial models.
Which incorporate performance metrics and eventually Wellbore quality metrics and one example is having a tortuosity index and tying them together with financial remuneration.
New commercial models are designed to generate win win outcomes.
The customer has a well with improved economics and H M. P is compensated for helping to create a portion of that value.
Currently approximately 30% of our active U S fleet is under some type of performance contract.
Contrasting the successful adoption of these new commercial models compared to a year ago, where we only had about 10% of our fleet on performance contracts.
Our digital technology is providing H M P and our customers another differentiating capability and delivering the best outcomes.
Let me give you a few examples.
Hmp's automation technology deployed on our flex rig is providing smoother well bores and reduced tortuosity.
Which helps extend downhole tool life deliver smoother casing runs increase reliability and reduced well durations and.
In addition, a less tortuous wellbore also saves the customer time and money during the completion phase of the well by lowering downtime events reducing.
And reducing overall completion time and creating more certainty for the life of the wells.
We are automating directional drilling with our auto slide solution and this is driving repeatability and consistency and drilling and the curve.
This enables landing the curve earlier in the zone.
Resulting in an additional frac stage and improve returns for the customer.
Well cost consistency achieved through automation and is providing more certainty and confidence to key stakeholders.
And a clearer vision and more confidence and future expansion.
I do believe that <unk> solutions are unique and the industry and contributing to the demand for H M. P. As our current rig count and the U S is at 118 rigs up 25% since the end of fiscal Q1.
In addition, we have approximately 35% of the public company E&P market share and.
And about 14% of the private E&P market share.
Both are leading metrics and the U S.
We're making good progress and deploying digital technology solutions, and introducing new commercial models to the industry.
All of that said, we also realize there's still a lot of work ahead.
As the demand for <unk> solutions has increased we find ourselves at a point, where rig reactivation are becoming an increasing financial burden.
We believe the market is fast approaching an inflection point, where this financial burden and we'll have to be carried by our customers as well either through lump sum payments or pricing over the life of the contract.
We estimate that industry wide there are only a handful of idle super spec rigs that have been active during the past nine to 12 months.
Particularly as longer idled rigs are put back to work higher reactivation costs will play a larger role and contract economics going forward.
We already see a shortage of ready to work Super spec rigs and the market. So theres momentum emerging in the near term to improve fluctuate solutions pricing and contract economics during the rest of 2021.
And if commodity prices remain strong and many believe E&P budgets will likely respond positively and 'twenty 'twenty, two and that will increase the demand for incremental super spec rigs.
Those incremental rigs will be those that have not worked and well over a year and it will be costly to bring those rigs back into service.
And on contract pricing and economics and must be supportive of that investment.
I will not soon forget last summer's reorganization and reorganization effort, where we downsized corporate G&A and operational and overhead and response to the pandemic.
Mark will give a more complete description of how these efforts are expanding this year, but I wanted to underscore that our industry is structurally smaller today and the prospects that trend reversing same very slim, especially near term we.
We must respond to the changing priorities, but it doesn't mean, there are no longer opportunities for H, and Peter innovate to grow and to thrive and this evolving environment.
Oil and gas is still critical to the global economy and it will remain so for many years to come.
Growing internationally is another strategic priority for H and P. While international markets are lagging behind the U S recovery, we are participating in several bid opportunities in South America, the middle East and elsewhere.
We are encouraged that several of these opportunities are unconventional resource type plays and we have industry, leading technology and expertise.
The process of obtaining international work has its set of challenges.
And we are shifting our strategy to drive success we.
We are committed to growing that part of our business and given our significant U S. Super spec capacity, leading edge technology offerings and financial ability, we are well positioned for many of these opportunities.
<unk> has long been committed to operating in a safe and environmentally responsible manner and we continue to invest and advancing cleaner and more efficient energy through new technologies that minimize the environmental impact of our drilling operations.
We are pleased with our ongoing partnerships with our customers to reduce <unk> emissions.
And our operational and technological experience combined with our rig design help our customers and minimize operational costs and risks and reduce the environmental impacts associated with producing oil and gas.
We are also investing and power management systems and alternative power sources.
The company recently launched our new website and its designed to provide greater insight into our solutions capabilities and outcomes based results and other important disclosures.
We've included new disclosures around our C O two emissions, including rig and vehicle emission improvements we've realized over the past three years.
And the coming months, we plan to publish our HSE sustainability metrics and other information as we continue to improve our ESG disclosures and culminating with publishing our sustainability report and 2021.
As we commented on our last call, we entered 2021 optimistically and so far so good.
One of Hmp's strength is its ability to adapt to changing and often volatile market conditions.
Our people are rig assets and digital technology, and our financial position are the drivers behind why <unk> is considered a market leader and partner of choice within the energy industry.
The industry will continue to face challenges, but I'm confident that <unk> and our people are up to the task and we will be successful.
And now I'll turn the call over to Mark.
Thanks, John Today, I will review, our fiscal second quarter of 2021 operating results.
<unk> guidance for the third quarter update remaining full fiscal year 2021 guidance as appropriate and comment on our financial position.
Let me start with highlights for the recently completed second quarter ended March 31 and 2021.
The company generated quarterly revenues of $296 million versus $246 million and the previous quarter. The quarterly increase in revenue was due to higher rig count activity in North America solutions as expected.
Total direct operating costs incurred were $231 million for the second quarter versus $200 million for the previous quarter. The.
The sequential increase is again attributable to the aforementioned additional rig count and the North America solutions segment.
General and administrative expenses totaled 39 million for the second quarter, consistent with our expectations and with the previous quarter.
Towards the end of the second quarter, we continued our focus on operating Super spec rigs and phasing out the less capable portions of our fleet.
As a result, we developed and began executing a plan to sell 60, a domestic non super spec rigs all within our North American solutions segment. The majority of which were previously written down and decommissioned and or use this capital spare donors.
We expect most of these rigs to be sold for scrap value. These assets were written down to their net realizable value of $13 1 million and were reclassified as held for sale on our balance sheet. As a result, we recognized non cash impairment charge of $54 3 million.
Additionally, during the second quarter, we downsized and moved our Houston and Flex rig Assembly facility as part of our ongoing cost management efforts.
And in conjunction with this initiative, we incurred a loss on sale of assets of $18 5 million, primarily due to closing on the sale of scrap inventory on obsolete capital spares for an aggregate loss of $23 million.
This loss was offset by approximately $4 5 million and aggregate gains on asset sales.
Primarily related to customer reimbursement for the replacement value of drill pipe damaged or lost and drilling operations.
Our Q2 effective income tax rate was approximately 23%, which is within our previously guided range.
To summarize this quarter's results agent and <unk> incurred a loss of $1 13 per diluted share versus a loss of <unk> 66, and the previous quarter.
Second quarter earnings per share were negatively impacted by and that 53 loss per share of select items as highlighted in our press release, including the aforementioned impairments and loss on sales.
Absent the select items adjusted diluted loss per share was <unk> 60, <unk> and the second quarter versus an adjusted 80 tusa and loss during the first fiscal quarter.
Capital expenditures for the second quarter of fiscal 'twenty, one were $17 million below our previous implied guidance as the timing and for that spending has shifted to the third and fourth quarters.
A&P generated approximately $78 million and operating cash flow during the second quarter of <unk>.
Fiscal 'twenty one.
And we'll have additional comments about our cash and working capital later and these prepared remarks.
Turning to our three segments, beginning with the North American solutions segments.
We have averaged a 105 contracted rigs during the second quarter up from an average of 81 rigs and fiscal Q1.
And we exited the second fiscal quarter with 109 contracted rigs, which is at the high end of our guidance range as demand for rigs continued to expand from the low reached back in August of 2020.
Revenues were sequentially higher by $48 million due to the activity increase North America solutions operating expenses increased $29 million sequentially and the second quarter, primarily due to the addition of 15 rigs.
And we ended up reactivating 21 rigs during the quarter due to churn across the base and geographies, where some releases offset the total number of reactivation.
Most of the rigs released during the quarter have returned to work or are expected to return during the third fiscal quarter.
As of this call we have added nine more rigs to the active accounts since March 31 for which a substantial portion of the reactivation costs were incurred prior to the third quarter.
This resulted in onetime reactivation expenses of approximately $9 7 million and fiscal Q2, including a portion of expenses for the April April incremental fleet additions.
Looking ahead to the third quarter of fiscal 'twenty, one for North America solutions as I mentioned earlier, we exited Q2 at the high end of our expected range and the activity level has continued to grow at a strong pace since March 31, but we expect that growth to be more moderate for the remainder of the quarter.
As of today's call with a nine additions I discussed we have 118 rigs contracted and turning to the right.
We expect to end the third fiscal and fiscal quarter of 2021 with between 120 and 125 contracted rigs.
As of March 31 about 30% of our active rigs were working under some form of a performance contract as John mentioned these new commercial solutions contracts reward A&P with incremental margin for delivering better and more consistent outcomes for the customer.
And the North American solutions segment, and we expect gross margins to range between $65 million to $75 million with no early termination revenue expected.
We will have quite a few rigs rolling off term contracts during the third quarter with many front loaded in Q3.
We expect and many of the operator programs for these rollovers to continue however, the rigs will reprice in conjunction with the term expirations as we continue to add rigs and one time reactivation expenses continued to pressure margins as I mentioned, a moment ago with regards to Q2, we expect those expenses to be approximately $6 million and the third quarter.
John mentioned that there is a strong correlation between the length of time and rig has been idle and the cost required to reactivate.
Historical experience indicates that rig stacks for nine months or longer.
We will incur cost in excess of $400000 to reactivate and that figure rises as more time passes.
Keep in mind that most of our rigs are stacked and back in April of 2020, some 12 months ago.
Activation costs are mostly incurred in the quarter of startup so the absence of such costs in future quarters as margin accretive.
Our current revenue backlog from our North American solutions fleet is roughly $370 million for rigs under term contract, but importantly, this figure does not include additional margin that ancient peak and earn his performance contract targets are achieved.
Our International Solutions segment International solutions business activity averaged approximately four active rigs quarter on quarter, but we did add a fifth rig in Argentina, and midway through the second fiscal quarter.
Margin contribution was above expectations for the quarter, primarily due to the incremental rig commencing work in Argentina, and coupled with revenue reimbursements for upgrades performed on a rig.
As we look towards the third quarter of fiscal 'twenty, one for international or activity and Bahrain is holding steady with the three rigs working and we have two rigs under contract and Argentina.
Also we still have a pending and rig deployment and Colombia, there continues to be delayed because our customer waits on required regulatory approvals to begin work.
And the third quarter, we expect to have a loss of between $1 million to $3 million apart from any foreign exchange impacts.
Turning to our offshore Gulf of Mexico segment.
We continue to have four of our seven offshore platform rigs platform rigs contracted and we have management contracts on three customer owned rigs one of which is on active right.
Offshore generated a gross margin of $6 million during the quarter, which was at the lower end of our estimates due to some unexpected downtime on one rig as.
And as we look towards the third quarter of fiscal 'twenty, one for offshore segment we.
We expect that offshore will generate between six and $9 million of operating and gross margin.
Now, let me turn to the third fiscal quarter and update.
Full fiscal year, 2021 guidance as appropriate.
Capital expenditures for full fiscal 2021 year are still expected to range between $85 million to $105 million with the remaining spend and distributed evenly over the last two fiscal quarters.
Our expectations for general and administrative expenses for the full fiscal year 'twenty, one and have not changed and remains approximately $160 million.
We also remain comfortable with the 19% to 24% range for estimated annual effective tax rate and do not anticipate incurring any significant cash tax and fiscal year 'twenty, one and the difference and effective rate versus statutory rate is related to permanent book to tax differences as well as state and foreign income taxes.
Now looking at our financial position and we had cash and short term investments of approximately $562 million on March 31, and 2021 versus $524 million at December 31, and 2020.
Including our revolving credit facility availability and liquidity was approximately $1 3 billion.
In mid April lenders with $680 million of commitments under our 750 million and revolving credit facility or Rcs and extended the maturity of the RCI from November of 2024, its in November of 2025.
No other terms of the RSV F were amended in conjunction with this extension the remaining $70 million of commitments under the 2018 credit facility will continue to expire in November of 2024.
Our debt to capital at quarter end was about 14% and our net cash position and exceeds our outstanding bond H and piece of debt metrics continue to be best in class and measurement amongst our peer group that allows us to keep our focus on maximizing our long term position.
And as a reminder, we have no debt maturing until 2025, and our credit rating remains and investment grade.
Now a couple of notes on working capital.
As discussed in our February earnings call, we received 32 million a $32 million tax refund plus $3 million of interest in January.
Still included in our accounts receivable was approximately $19 million related to further tax refunds and we expect to collect on the coming quarters.
The preponderance of our trade day are continues to be less than 60 days outstanding and from billing date and increased a modest $8 million sequentially, our inventory balances declined for the third consecutive quarter, even as our active rig count climbed and we continue to focus our efforts on reducing out of pocket expenditures.
Given our current outlook for activity and we expect our cash balances at fiscal year and to be relatively unchanged from March 31.
On one hand rising activity drives on a run rate cash generation and higher while on the other hand, and the short term some of that higher cash generation potential is masked by reactivation expenses and working capital investment investments required to enable that higher activity.
We believe that these higher activity levels, our point forward and quarterly operating earnings will fund, our maintenance capital expenditures debt service costs and dividends.
John mentioned cost control remains a high priority since we last spoke on the February earnings call. We have further advanced this initiative as we seek to adjust our cost structure to what we expect to be a smaller industry scale.
This effort is one of our current strategic objectives, and we have several work streams being carried out in parallel.
One such work stream was the reduction and size and relocation of our Houston Flex rig Assembly facility, which lowers go for and overhead while simultaneously increasing capabilities at that facility.
And as these work streams progress we will update you on the expected and magnitude and timing of these various cost savings opportunities.
That concludes our prepared comments for the second quarter.
Now, let me turn the call over to Jim for questions.
Yes.
Gentlemen, thank you and to our audience at this time, if you would like to ask a question. Please press the star and Juan on your Touchtone phone you may remove yourself from the queue at any time by pressing the pound case. Once again that is star and wanted to ask a question and the pound key will remove you from the queue.
We'll take our first question today from Ian Macpherson Simmons. Please go ahead.
Thanks, Good morning, John and Mark appreciate the.
Perspectives there.
It sounds like you provided us with the building blocks to confirm what we were expecting with respect to margins improving.
On your fiscal third because reactivation costs going forward as a percentage of the total pie should be should be easing spot pricing has bottomed and youll.
You will have probably increasing share performance contracts that are probably accretive to your margin as well so I wanted to confirm.
That directional bias for margins to probably began to tilt upward a little bit after the third quarter and thats the state of the world changes.
That's my first question.
Sure, Yeah, and I think I think youre right on that but we do feel like we've.
Rates in general have are off of the bottom and.
We've been able to see some improving pricing and as you said improving.
Our commercial base.
Our performance based type contracts. So yeah, we think we're.
We're working on increasing that I think just in general the fears.
<unk>.
The Super spec fleet, while not John.
And at near 80% utilization.
And I think when you look at what is available and idle and its been idle for quite some time and and I think that ultimately drive some higher pricing as well as we continue to activate rigs.
Okay.
And John as you go about this.
Sort of maintenance and scrapping program.
How much idle capacity.
Super spec rigs.
It makes sense for you to keep and the back pocket how much how much capacity do you think you need for the cycle ahead.
Well and all.
I'll, let mark give some some additional color and details on that but we haven't.
Scrapped anything Thats Super spec capacity everything that we scrapped as is.
As a as the lower tier flex rig four and older Flex three.
Yes, he and I, just just a footnote that on everything that we are.
Coloring and from the fleet as I mentioned in the prepared remarks is really been previously.
Impaired to and to some sort of salvage value, but also along the way.
These rigs on calling them rigs is really kind of generous and they've been utilized as donors for equipment and components.
They're not a complete rig if you will they're really mainly flex for rigs and and non super spec rigs that we impair and going back to June of 19 and March of last year.
And if we just subtract your working rig count now to where you were.
At the peak a year ago is that a good proxy for what you're less and a $1 million of reactivation.
Reserve looks like.
And then.
And I think Thats a good approximation okay.
Great. Thank you gentlemen, and I'll pass on.
Thank you.
Our next question will come from Taylor Zurcher of Tudor Pickering and Holt.
Hey, John and Martin and Thanks for taking my question.
First question I have is really a two part question as it relates to some of the moving.
Moving pieces for the June quarter.
Reactivation costs, obviously are a bit elevated as you're putting a whole bunch of rigs back to work and I just.
Wanted to clarify are you able to pass through any of those costs and a customer today and then secondarily you talked about.
Number of term contracts, which are rolling over and the June quarter I suspect most of those are under the traditional day rate model. So I was hoping you could help us understand if you expect any of those rollovers to transition to more of a performance based model as we progress forward.
Taylor I think I think it's going to be a mix.
And we won't be surprised by that I think they are.
And there are definitely.
Rigs are customers that were partnering with today on performance based contracts that have rigs that will be rolling off.
And they will I believe be interested in and pursuing a performance based contract again, because it's a win win.
Opportunity for them and and for US there will be some.
More than likely that will just roll into a day rate.
Type contract, which will be lower than what the leading edge pricing was there and but again I don't expect them to two I expect them to be at improved pricing.
From where the where you might see the average today or <unk>.
Definitely off the bottom on what we experienced.
On the reactivation costs again, that's a mix as well I mean, historically speaking, we're not going to put a rig to work.
For one well.
We're going on we're not going to reactivate a rig that's been idle for six 912 months for the expectation of only drilling a well where we're typically going in with some sort of a term or some sort of a commitment or some sort of a of a way to get paid back over time that reactivation costs and it's.
And of course, they're all different this is not unusual if you just think about market cycles over the past five eight years.
10 years, even with.
With the cycles that we've had where you reach a certain part and the cycle, where you are the market is tight enough that you are able to start passing more of the cost over and over to the customer, which again makes sense as the market tightens and hopefully that helps.
Okay. That's super helpful. Thanks for that and and my follow ups.
Unrelated and and more as it relates to capital allocation moving forward the <unk>.
Cash balance is obviously still very healthy the dividends are top priority, but you can cover that pretty easily and moving forward.
And so I was wondering if you could help us think about how we should view M&A for <unk> moving forward, particularly on the on the technology side I suspect that that's still going to be the focus but are there any kind of notable gaps that you'd like to fill and on the software digital et cetera side moving forward.
You might do inorganically versus organically or maybe it'll be a mix of both but any color there would be helpful.
Sure Tyler and that's a great question and you know on the M&A side on the rig the rig site.
That's not something of interest.
We've always got our eyes open on the technology side and we've made some what I think are some very strong acquisitions over the last.
Four years coming up on for years and.
And theres not anything right now that that comes to mind, but I'll say that we're we're obviously looking to be opportunistic and if something comes up.
And we're definitely going to look at that but I think right now I feel pretty good about about where we are.
Mark do you have anything you want to.
Yes, I would just I would just add that maybe and.
As we consider capital allocation and tailor beyond.
M&A will look and.
For the international expansion and John discussed in his prepared remarks, we will look at.
Opportunistic growth opportunities.
Including organic ones for the Middle East by way of example.
But when speaking of capital allocation for us in particular is returned to shareholders and our long history of the dividend and.
And something that we consider as we move forward potential dividend accretion and special dividends as others and the energy complex have done and and share buybacks as we have our $4 million per annum and authorized share buyback program that we can get into but but yes. These are the things that we're talking about.
At Helmerich <unk> Payne.
Alright, good to hear thanks and answers.
Thank you.
And.
Tommy Moll at Stephens. Your line is open. Please go ahead.
Good morning, and thanks for taking my questions Good morning, Tommy.
John I wanted to start on.
And progress with new commercial model and drilling automation and penetration.
All of those metrics are up and to the right, which is great to see I'm curious at the customer level.
Have you had any customers that maybe tried a.
The new commercial model on.
A handful of rigs and.
And then scaled the approach across their entire program and other words, a customer that's tried it and then leaned in and fully.
Or do you find that that you're driving those penetration numbers higher and more.
You know a larger number of customers trying out and the new models on a rig or two and.
And with this and I'm just trying to think about a potential tipping point there.
And what the pathway might be going forward I know it won't happen as quickly as we'd all hope, but I'm just trying to think about the building blocks right.
Okay. Thank you Tommy.
It's your first example, it's both we do have customers that started with one rig to rig and now they've got it on every rig that we have working for them and and the fleet.
Same way with the same way with the technology offerings are auto slide automation and.
Those solutions same way they start with one rig and then they continue to grow but we've also had new.
Doug.
New customer or customers adopt it new so we do have additional adoption.
We're seeing additional opportunities to partner on drilling automation and the new commercial models at times.
I.
Like and this to the early days of the flex rig it as you can imagine not every customer was looking for and advanced technology rig and particularly one that was.
On a much higher price and what the going rate would have been for a conventional rig, but we had the <unk>.
Ali we had the early adopters were able to partner with I saw the benefits and we created a whole lot of value.
So.
Now, where we're taking this very old commercial model with our with the traditional day rate and where we're having to approach it and a different way. So we're learning as an organization.
Our sales force and our account managers, our marketing group our operations folks everybody's working together as a team with the customer to make this happen. So I really think that we're going to continue to grow that capability and <unk>.
Pleased to share like I said, and our prepared remarks that 30%, 30% of our of our working fleet today have commercial orders and a year ago. It was 10%. So we are continuing to grow and that are in that respect another great point to make is auto slide.
Good.
Retention.
We've seen a 100% retention over these last Ive got I don't even know how long it's been we have over 30 30 jobs running it's another example, where.
We have customers, who start with one rig and then there are up to four rigs are up to six rigs and then we have new customers that are that are coming in and adopting the technology again, when you start thinking about.
The advantages to the customer the advantages with.
And with auto slide and automation is it's not just in the drilling of the well.
And we're leaving behind a better well a higher quality wellbore.
We have and we have advantages while drilling the well and like I had mentioned extended downhole tool life.
Smoother casing runs increase reliability reduce time on the well, but we're also delivering a less tortuous wellbore, which also has an impact on the completion side of the equation and really the lifetime value of the well so.
And so we're really encouraged that we're we're seeing additional adoption again as I said on the last call. It is a partnership we both have strength that we bring to the party and we're having to kind of expand outside of our normal area.
That we've worked with our customers. So overall I think it's moving along pretty well.
Thank you Jonathan you mentioned.
Wellbore quality, there, which is something that I wanted to follow up on so I believe in your prepared remarks, you indicated that.
Incorporating some some terms related to wellbore quality is either and the early stages or maybe we're not there yet in terms of the new contract structure, but.
Just conceptually on that point, how do you approach it.
With one of these more performance base models I think it's a newer theme for for us to think through and so I'm curious with that concept looks like.
Sure I think at two examples one is.
Well head and my prepared remarks, where and I think we may have talked about this on a previous call that we've had.
Several customers recognize that when drilling and the curve by using automation and compared to using a human.
Doing that the decision making of drilling that curve, we're actually able to land that curve of 150 to 200 feet earlier in the zone.
And it creates an additional frac stage.
Well, there's also there's obviously risks and doing that and what customers are saying is that it's more challenging for a human directional driller to do that and so that's an example of delivering additional wellbore a better a better curve.
The Tortuosity index, we have a tortuosity index and we've we've developed that we have other customers that are developing it and I think thats something that ultimately will will be used more and the future right. Now I think it's still really early stages. The good news is is that there's we're finding additional.
The advantages as we as we go through this process no surprising as you know as you start thinking about leveraging these technology. So there's more to come on that but I do think there'll be more.
Metrics that we can share and talk about and the future.
Thank you John we'll look forward to follow on the progress and I'll turn it back.
Thanks Tommy.
Our next question today comes from Waqar Syed ATB capital markets. Please go ahead. Your line is open.
And good morning.
John.
Good morning on couple of questions here first of fall and they look at summit and information provided in the press release I think that you've added maybe 10 to 15 rigs and Doug.
Kind of long term contracts like 18 to 24 months out.
And one is that correct and if that's so what do you think what are the rates on those the base based on to substantially above where the current spot is are they are being locked in on the spot rates with the performance based contracts to provide upside.
Sure I'll take that one yes.
Had a few.
As you've seen there and the press release.
Term contracts re signed and and those prices are.
Above what the current spot market is so we're happy to see that.
Okay. Good and then secondly.
And historically you mentioned the performance based contracts kind of add around 15 on a dollars per day or so to margins now as you can.
Collected the data on over the last six to eight months.
And then.
Number is coming and in line with those expectations on speed.
Exceeding those expectations.
How do you.
Frame the results so far.
<unk> this is mark.
We're still and it depends on on.
The customer the rig the region, but we're still and between 1002 thousand yes, and that same same zipcode. If you will on the incremental uplift for the performance contracts.
Okay, and I think I think to think that too and.
And it's one of those things and working with our customers again, we're working on delivering outcomes and and obviously you know, whether it's $500 or $2500 on a per day basis.
The outcomes we're delivering.
We're you know that.
<unk> revenue more than that and then pays for that additional value add so that that's the opportunity set what car is and then.
As we do a better job of that we do more of that and.
And the reality is I don't think there's others out there and our peer set that are able to deliver that same level.
Our performance, we're talking about so that's the opportunity set.
Okay. Appreciate that and then just finally like normally and international contracts you have.
Six to eight months kind of lead time.
And before the rig starts to two and do the right.
So from our modeling perspective.
For the next day.
<unk> calendar year and.
And Tony one should we not model any incremental rigs beyond the four to six that you've mentioned.
I think.
All we can really say.
<unk> heard me say this for years, where car, it's really hard to say for certain with certainty much past a quarter.
We're working really hard to hit that hit those targets like we did the last quarter and we're going to hit that 120 to 125 target. Obviously, we're pushing for 125 I do think we're going to continue to see a slight increase and rig count.
During the course of the remaining the remainder of 2021.
Obviously, a lot of that is a function of of oil prices.
We do think our customers are going to maintain discipline.
And they're going to spend within within their budgets I think.
Particularly on the public.
Companies. So I think that's going to be the case. However, as we began to setup for the back half of 'twenty, one and getting ready for 'twenty. Two if oil prices do remain higher I do think we're going to be we'll be entering into 'twenty, two with a higher budget.
Cycle than what we experienced and 21, so hopefully we're going to continue to see some.
The increase in activity and again, we think most of that activity is going to be directed towards Super spec type capacity. We think customers expectations are going to are going to grow in terms of both performance and wellbore quality. So I think I think that that positions us well for additional growth, but again, we can't we can't really.
And give you a rig forecast past Q3.
Go ahead, Mark I would just add John <unk>.
On a car back on the international part of that.
Youre right I think as we look at these through our planning horizon, we as John has said and we've said, we're very focused on international opportunities, but as you point out it's a longer sales cycle and I think those would be more calendar 'twenty two.
As we think fiscal 'twenty two.
To the extent that they come to fruition, but the good news is we are seeing more bidding activity tendering activity and internationally and various countries.
And it's a long process as you mentioned and your question and so it will just stay tuned for that but not in this year's fiscal model.
And just one.
Another question.
And there's talks of labor strikes and Argentina.
Is that affecting you and activity there.
Yes, there is.
Some health care workers that were striking down there blocking roads to the welcome Erika so.
Think as of yesterday and those have stopped so that kind of put a pause on a lot of activity down there, but hopefully that gets up and running relatively soon.
Okay great. Thank.
Thank you very much appreciate it.
Thanks Waqar.
Our next question will come from <unk> <unk>.
And at Coker and Palmer. Please go ahead.
Good morning, guys for taking my question.
Thanks.
So.
Our daily cost decline significantly and obviously you guys are doing.
On the cost saving so maybe if I can ask how much more cost savings to come.
And maybe timeline and these patients.
Essentially what I'm trying to think about is let's say if you think about <unk>.
150, 175 rigs working eventually.
How should we think about that David.
Operating cost.
Okay.
<unk>. Thanks for the question forgive.
Give me a couple of things to think about because we're not ready as I mentioned in prepared remarks to give you specifics yet on timing or dollar amounts, but we're very focused on cost management.
And just a couple of things we've started as I mentioned.
Scrapping and process for previously decommissioned rigs previously impaired rigs.
And you know another example that we will move forward with this consolidation of yards as a scrap sales are completed.
And last year, we had to make some tough choices on cost as John talked about the reorganization, we did and.
And were involved we're moving much of the labor element of consolidating our seven North American districts to four regions. We are now working towards the.
The physical physical structural geographic footprint to align with those four regions and Thats again kind of consolidating yards and that specific example.
And these are these changes will result in stack yard closures and.
And forward cost savings as it related to everything there with the timeline and impact around these and.
Is that specific initiative as an example, and many other things that we are working on now.
Those initiatives are carrying forward and protracted and we'll be talking more about that especially as we move towards fiscal 'twenty two.
On the day here.
And if I think about.
Your exposure to private groups can you talk about.
What's the average length.
Contract with private private operators and what I'm trying to think about it as well.
Commodity prices do go down what is the risk on those rigs coming down.
Fabs, it's it's really.
It's really across the board I mean.
We have spot market exposure too.
The public companies as well.
So.
It's kind of hard for us to pull that out and give you. Some information that would that would really help in that case.
Okay.
Yes.
To add on there yet and it's across the board I mean, we've had some private guys that were contracted earlier and the year and didn't add rigs when commodity prices moved up so yes, again there'll be some that might retract.
But yes, its a really mix for us.
And maybe if I can squeeze in one on one more.
And we've talked about reactivation cost, obviously to you talked about $6 million this quarter.
And maybe if it gets.
Conversations are going with customers trying to push that reactivation cost of dams.
Is that fair to think like that should not be any reactivation costs.
Amount starting fiscal fourth quarter.
No I don't I think it's too early and.
And the game for that I am sure we already have some commitments for rigs and in Q4.
And we're going to do the best that we can again, sometimes that.
And that.
<unk>.
Reactivation cost is captured through a term contract and built into the built into the day rate. So we still we would still potentially have some reactivation costs, but we're getting compensated for that over the life of the contract. So theres a lot of different a lot of different examples on that but no Q.
Q3 would be too early.
Thank you.
And gentlemen, our next question. This morning comes from the line of Chris Boy at Wells Fargo.
Thanks, Good morning, maybe just to start with a pretty high level question around efficiency. So in 2019, you saw a lot of dramatic increases and footage per rig and E&P presentations or can you just do the math and 2020, obviously pretty crazy year tough to track with all the volatility now that we've got some.
You know, obviously, the rig count and the increasing pretty solidly, but probably easier to measure at this point.
If I think about it.
The drivers for increasing footage per rig there is higher rate or rate of penetration when more super specs and service excellence and Eurocontrol and there's bigger pad sizes fewer modes and your customers control I'm. Just curious if you can give any perspective on whether increasing footage per rig has leveled off compared to the exit rates in 2019.
And if it continues to increase.
Chris I don't have a sense for how 2021 is measuring up to 2019, but I think and general.
Generally speaking and the U S. We continue to improve cycle times.
I can really only speak to.
And the HMP rigs, but we're improving cycle times, we're also continuing to drill longer laterals.
All the things that you mentioned play and play into that.
I will say on the on the technology side.
And as I mentioned in our prepared remarks.
And less less tortuosity and.
And.
And having fewer hard turns down downhole has an impact on downhole tool life, so fewer trips.
And also enhances.
The speed of drilling the well so I think we still have.
Runway ahead of continuing to improve performance and automation is going to contribute to that were.
And we're going to continue to see.
Technology advances, both downhole as well as with software. So I think I think we're going to continue to to see that happen.
Okay. Thank you that's helpful and then for a follow up this is more of a clarification, but in the prepared remarks. I think you are talking about a bunch of rigs this quarter rolling over to lower rates.
After contracts to expire and then and one of the queue.
And one of the Q&A I think there was a commentary that maybe suggested that leading edge now might be near or exceeding the portfolio average. So if we just think about gross margin per rig excluding reactivation costs.
Is that leading edge now near the portfolio average or is that going to keep ticking down and maybe as you head into <unk> from <unk>.
Hey, Chris This is mark thanks for the clarification question and it's not the portfolio average I think what John was talking about and Q&A as it's up from the reason and bottom of the spot if that makes sense. So we continue to have rigs rolling off of contract, they're repricing and the current environment, but that spot has moved up from arrow.
Rig count back in August of 'twenty.
2020.
And in addition to that we are with our sales team and working with our customers and looking at it.
Win win solutions, leading with those discussions for the renewables with performance based contracts.
So that to the extent, we're successful there and getting a better outcome for the customer we also get a better uplift with the bonus for hitting kpis at the end of the job.
Alright, okay. Thank you.
Thank you.
And this does conclude today's Q&A session I am pleased to turn the floor back to Mr. John Lindsay for any additional or closing remarks.
Thank you, Jim and thanks, again to everyone for joining us on our earnings call today as we've outlined we have several strategic objectives at the company is working on and that we believe are going to continue to bring about and evolution and our industry and.
The industry, obviously, we will continue to face challenges, but I believe that <unk> and our people are up to the challenge. So we're going to keep working working very hard.
To keep improving and so thank you again for joining us today and have a great day.
This does conclude today's program. Thank you for your participation you may disconnect at any time.
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