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Helmerich and Payne Inc
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Good day, everyone, and welcome to today's Fiscal Third Quarter 2019 Earnings Conference Call for Helmerich & Payne. At this time, all participants are in a listen-only mode. Later, you will have the opportunity to ask questions during the question-and-answer session. [Operator Instructions] Please note, this call may be recorded. [Operator Instructions]
It is now my pleasure to turn today's program over to Dave Wilson, Director of Investor Relations. Please go ahead, sir.
Thank you, Tony, and welcome everyone to Helmerich & Payne's conference call and webcast for the third quarter of fiscal 2019.
With us today are John Lindsay, President and CEO; and Mark Smith, 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 on current information and management's expectations as of this date, 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 in 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 as we undertake no obligation to publicly update these forward-looking statements.
During the call, we also make reference to certain non-GAAP financial measures such as segment operating income and operating statistics. You will find the GAAP reconciliation comments and calculations in yesterday's press release.
With that said, I'll now turn the call over to John Lindsay.
Thank you, Dave, and good morning, everyone. I will address several topics today. First, I will talk about industry dynamics, our results and utilization. Next, I’ll discuss how our leadership position in the U.S. unconventional basins with our flex rigs and software solutions is allowing us to gain more traction in international markets. And lastly, I’ll discuss the momentum we’re seeing with our customers, who are early adopters of our next generation technology.
The industry saw further softening in U.S. drilling activity, resulting from crude oil price volatility and tightening drilling budgets. Notwithstanding these challenges, H&P produced solid operating results and maintained flex rig super spec utilization at close to 90% during the quarter.
Our expectation of the company’s rig count reaching the bottom during the quarter turned out to be premature. The effects of the industry emphasis on disciplined capital spending continues to reverberate throughout the oil field services sector. As such, H&P exited the quarter in the U.S. with 214 active rigs, which was slightly below the low end of our guidance range.
Even with the lower than expected activity in U.S., H&P still performed well, generated $250 million in operating cash flow for the quarter. We see further softening during our fourth fiscal quarter as our guidance would indicate. And while we’re hesitant to make another prediction, our sentiment now is that we should start to see some improvement around the time customers recalibrate during the final calendar quarter of the year and began to plan for activity in 2020. And looking at our last 30 rig releases, more than 80% were associated with a project completion or a budget related reduction. They were not related to pricing. We continue to win bids in the open market, however, there is a high level of churn in our rig count.
The good news is that US land industry super specialization remains close to 90% and pricing remains firm for the best in class of the fleet. Even as activity trends lower, we continue to see persistent demand for top performing rigs that are required for more complex wells with longer laterals and tighter well spacing. Evidence of this can be seen by peeling back the activity statistics.
Since January, we find that industry AC drive activity has declined approximately 8% to around 720 rigs and the legacy SCR and mechanical rigs that are drilling horizontal wells has decreased by approximately 24% to about 210 rigs. We believe this indicates that the highgrade cycle remains intact. As customer drilling plans grow in complexity, better rig technology that is capable of achieving higher performance and reliability remains in demand.
Also supporting firmness and super spec pricing is a market concentration, where the top five US land drillers currently own approximately 80% of the active super spec fleet.
Our leadership position in the U.S. unconventional basins with flex rigs and software solutions is allowing us to gain more traction in international markets. We announced last quarter a contract to deliver our first Super spec flex rig from the U.S. into Argentina. And we expected to commence operations in our fourth fiscal quarter.
In addition, we're pleased to announce that a letter of intent has been signed to send a second super spec flex rig from the U.S. to Argentina to drill in the Vaca Muerta basin. The company also saw an increase in activity in Bahrain and now has two rigs active. Transitioning to our H&P technology segment, we continue to make progress in rolling out auto slide an important step in H&P's drilling automation technology.
This technology becomes more significant as shale plays institute more manufacturing type profit where automation can be employed to drive further efficiency gains and where wellbore quality and placement become essential factors for well construction. We're finding that operators desire automation because they want to be able to deliver a consistent and efficient directional drilling results from rig to rig which drives capital certainty. And auto slide is producing these results.
In addition to efficiencies the wells have less virtuosity, meaning higher quality, have a higher quality well bore and they're placed more accurately and the curves are also landed more accurately.
Auto slide has been deployed commercially and purposely thus far in four U.S. shale basins the Midland, the Eagle Ford, the Scoop Stack and the Bakken. The company anticipates introducing this technology to the Delaware basin later this fiscal year and eventually, in all of the basins where we work.
Not even MagVar continue to grow their respective customer bases. However, both are experiencing the same headwinds of this industry environment in terms of rig count. We believe activity pauses here are temporary. And as these digital technologies provide higher levels of reliability, wellbore quality and placement we have the opportunity to be the industry standard.
The adoption of our FlexApp software continues to increase as customers see the value of these technologies deliver. And we are pleased to find that some are asking to use these solutions on non-H&P rigs. We are responding to this opportunity by migrating the FlexApps software to our H&P technologies business segment where these innovations can be marketed on both H&P and non-H&P rigs.
We believe this market environment, where there is a mandate for capital discipline, and investment return is ideal for demonstrating the benefits of H&P innovative software, and the meaningful impact these offerings can have on economics over the lifespan of a well. There are industry studies documenting what we believe and what you heard me say previously.
Even in this discussion, that wellbores with less tortuosity produce more oil, and cost less to maintain. While more accurately placed wellbores will provide more optimal drainage of a reservoir and produce fewer parent child well interference problems. The transformational shift for any industry takes time. And speed of adoption isn't as fast as we would like for some of these software offerings.
The challenge is not so much the software development and implementation, but the changes these technologies create in the customary workflow at the rig site. The jobs at the rig are changing, and in some cases, the role is being eliminated at the rig side and relocated to an offside command center. That kind of disruption requires strong change management from all parties involved. We are making progress with a handful of customers and we believe we're on the right path.
In closing, H&P remains well positioned with the largest fleet of super spec rigs and unmatched software solutions that provide improved wellbore quality and placement to deliver economic value. The oil field services industry is experiencing the effects of E&P company emphasis on discipline capital spending, and prioritization of cash flows with less focus on growth. While short-term, this may be painful for some this disciplined approach will lead to a healthier industry long-term.
Our strategy provides the financial and operational flexibility to adapt to the market. We have the capabilities required to be successful. The people, FlexRig fleet, software solutions, a strong term contract coverage, and the balance sheet to navigate through the short-term market uncertainty and position us well for the future. Our strategy delivers superior value for customers and shareholders providing all parties the opportunity to achieve mutual long-term success in this changing industry climate.
And now I'll turn the call over to Mark.
Thanks, John. Today, I will review our fiscal third quarter 2019 operating results, provide guidance for the fourth quarter, update full fiscal year 2019 guidance as appropriate and comment on our financial position.
Let's start with highlights for the recently completed third quarter. The company generated quarterly revenues $688 million versus $721 million in the previous quarter. The quarterly decrease in revenue is primarily due to a decrease in the average number of rigs working in the U.S. land segments as expected.
Total direct operating costs incurred were $445 million for the third quarter versus $443 million for the previous quarter. The increase is primarily is attributable to higher than expected self-insurance expenses in the U.S. land, despite the decrease in revenue days. Also contributing was a write down of certain inventories and materials and supplies which flowed through OpEx and was related to decommission and drilling equipment and spares which were on a separate line item in the income statement and which I will now describe in more detail.
During the third fiscal quarter a detailed assessment of our flex rig four asset group was performed. The end objective of this assessment was to maximize the utilization and enhance the margins of the domestic and international flex rig four asset groups. In June 2019, this assessment concluded that marketing a smaller fleet of these two asset groups will provide the most optimal economic outcome. As such we have downsized the number of domestic and international flex rig for drilling rigs marketed to customers from 71 rigs to 20 in the U.S. and from 10 rigs to 8 internationally.
Major components from the decommissioned rigs were added to capitals spares for our rig fleet, following this downsizing process a detailed study was then performed to identify the appropriate quantities of capital spares and drilling support equipment required to support the future operating needs of our ongoing rig fleet. This resulted in the write down of excess capital spares and drilling support equipment, resulting in a non-cash impairment of $224.3 million, which is roughly 5% of ending net PP&E.
General and administrative expenses totaled $47 million for the third quarter. This is below the run rate for our previous full year guidance. Our effective income tax rate for the quarter was approximately 17% due to certain discrete tax benefits and incremental foreign and state income taxes. The rate is below the federal statutory income tax rate of 21% as it is calculated on the pre-tax loss.
Summarizing the overall results of this quarter, H&P incurred a loss of $1.42 per diluted share, versus earning $0.55 in the previous quarter. Third quarter earnings per share were negatively impacted by net $1.82 per share select items as highlighted in our press release and including the aforementioned impairment.
Absent the select items adjusted diluted earnings per share were $0.40 in the third quarter versus an adjusted $0.56 during the second fiscal quarter.
Capital expenditures for the third quarter fiscal 2019 were $74 million, year to date fiscal 2019 we have extended $404 million or about 80% of the low end of our full year CapEx guidance.
Turning to our four segments beginning with U.S. Land Segment, we exited the third fiscal quarter with 214 contracted rigs which was a decrease of approximately 5% and the number of active rigs quarter end to quarter end. H&P maintained over 20% U.S. Land market share from quarter-to-quarter.
As John discussed, we expect to see some further reductions in active rigs in the fourth fiscal quarter. We expect our super-spec rig class to see an average utilization level in the mid 80 percentile range. Despite some softening market conditions during the third fiscal quarter pricing remained firm in the super-spec market space. Our average rig revenue per day excluding early termination revenue increased to $26,122 for the quarter slightly above our guidance.
Included here is the increasing customer adoption of our FlexApp offerings that are approximately $450 per day per rig revenues across the fleet, up from $300 last quarter. The average adjusted rig expense per day increased to $14,852. This is above our previously guided range primarily due to higher than expected self insurance expenses and the aforementioned inventory write-down.
Looking ahead to the fourth quarter of fiscal 2019 for U.S. Land, we exited the quarter with 214 rigs working, but have continued to see rig releases in this volatile oil market. Most of our customers have spent over 50% of their budgets during the first half of the calendar year. And they are now assessing plans for the remainder of the year.
We do expect the industry's rig count to eventually stabilize, once customer reach a run rate of spend that aligns with balancing their budgets. That said, we don't have an absolute visibility when that point will be reached. We are currently operating 207 rigs today in the U.S. with an expectation that we will exit the quarter with between 193 and 203 active rigs. This would result in a sequential decrease of approximately 5% to 6% in the quarterly number of revenue days, which translates to an average rig count of approximately 204 rigs during the fourth quarter.
Although, we have 45 FlexRigs that are upgradeable to super-spec our initial objective is to put these 34 idle super-spec rigs we currently have back to work as the market tightens and as opportunities to displace the legacy rigs continue to rise. Compared to the third quarter at 26,122 per day, we expect the adjusted average rig revenue per day to be within a range from 25,250 to 25,750. This range now excludes FlexApp whose revenues and associated margins will be transitioning to the H&P technologies segments in the fourth quarter.
And our average day rate in both the spot and term market remain in the low to mid-20s range and the leading edge super-spec FlexRig pricing remains in the mid-20s. The normalized average rig expense per day directly related to rigs working in the U.S. Land segments remains approximately 13,700 per day. The average rig expense per day is expected to be in a range of 14,350 to 14,850 for the fourth quarter.
Note that with a reduced number of upgrades upfront reactivation expenses have begun to come down. So this is being offset somewhat by the additional idling costs of recently released rigs. Decommissioning costs will also be incurred in the near-term for flexible rigs as previously discussed. We had an average of a 142 active rigs under term contracts during the third quarter. And today that number is 138 or about 67% of our 207 working rigs.
We expect to have an average of 138 rigs under term contract in the fiscal fourth quarter, earning the current average day rates. For the 88 rings that currently remain under term contracts through the end of fiscal 2020, the associated day rate is about $200 per day higher than today's average.
Regarding our international land segments, the number of quarterly revenue days decreased 3% in the third fiscal quarter slightly below our guidance due to an early termination of a rig in Q3 that will return to work in Q4. The adjusted average margin per day in this segment decreased by $3957 to $7904 in the third fiscal quarter. The decrease was primarily due to start up and reactivation calls for the rigs in Argentina and Bahrain.
As we look towards the fourth quarter of fiscal 2019 for international, quarterly revenue days are expected to increase slightly with an average fourth quarter rig count of approximately 17 to 18 active rigs in the segment. Our first international super spec flex rig is scheduled to commence operations in Argentina midway through this fourth quarter. The average rig margin is expected to be relatively flat in between $7500 to $8500 per day during the fourth quarter due to startup costs for the Argentine rigs. Additionally, we will experience non-operational times due to longer rig moves within Argentina in Q4.
Turning to our offshore operations segment, we continued with six active rigs during the third fiscal quarter and had a rig change from a standby rate to a working rate which positively impacted revenues in the quarter. The average rig margin per day increased sequentially due to the previously mentioned rate change being in effect for most of the quarter, as well as lower than expected self insurance expenses.
As we look toward the fourth quarter of fiscal 2019, for our offshore segment. We have six of eight offshore rigs contracted, the average rig margin per day is expected to be relatively flat in the range of $12,000 or $13,000 during the fourth quarter.
Now looking at our H&P Technology segment. As John mentioned, we will be moving flex apps to H&P technologies in the fourth quarter. These apps were developed on top of our flex rig operating system initially for us on our flex rigs. Two of our six apps are used in the auto slide offering. Customers have expressed interest in using these apps on non-H&P rigs in much the same way that the motive big guidance system and Magvar are deployed via software as a service.
We are just now commencing the process of determining how to make our software applications available on other rig operating systems. Combining all of our software solutions into HPT expands our service offerings to customers and focuses our research and development efforts on our technology roadmap as we continue to move toward automated drilling for the industry.
Beginning with this quarter's guidance, we are issuing a revenue guidance range for the next quarter for HPT consistent with our forward guidance in the drilling segments. We are expecting Q4 revenue for HPT to be between $17 million to $19 million inclusive of flex apps. Remember that HPT is not only a new segment, but also a new business model. And even with the ongoing successes that John mentioned earlier, in our industry widespread customer adoption is hard to predict with certainty.
Now, let me look forward on corporate items for the remainder of fiscal 2019. Our current revenue backlog for the U.S. land fleet for rigs under term contract which we define as rigs with contracts with original fixed terms of at least 6 months and they contain early termination provisions, there's approximately $1.4 billion.
Capital expenditures for the full fiscal 2019 are expected to come in at the low-end of our guided range from 500 million to 530 million. We have one to two remaining upgrades of FlexRigs to super-spec capacity in the fourth fiscal quarter. We are starting to see reduced maintenance CapEx given our current rig activity levels. Finally, the completion of some of our long lead both purchase items will round down on our fourth quarter CapEx.
Given our September 30th fiscal year-end, we have begun our annual budgeting process. Maintenance CapEx will correlate closely with our operating rig counts. FlexRig capital maintenance typically ranges from between 750,000 to 1 million per active rig per year. Our international and offshore rigs incur approximately 1 million to 1.25 million per active rig and annual maintenance CapEx.
This completed with today's rig count. Our budget would contemplate a total of approximately 230 rigs across all operating segments with a maintenance capital spend of roughly $230 million. Our first goal will be to redeploy idle super-spec rigs prior to conducting any upgrades. After adding in plan special projects and corporate expenditures, including information technology and infrastructure items.
Our total CapEx for fiscal 2020 excluding any upgrades or international growth opportunities will be below $300 million, which is more than 40% less than this current fiscal year. Depreciation for fiscal 2019 is expected to reduce to a total of approximately 550 million plus an additional 15 million or so and abandonments and accelerated depreciation that have been primarily related to super-spec FlexRig upgrades. The revised combined total is about 565 million less than previous guidance due to the previously mentioned impairment.
Our general and administrative expenses for the full fiscal 2019 year are now expected to come in just under our prior guidance of 200 million in total. Note this projection is less than our final 2018 G&A, when we ended the year with the U.S. planned rig count of a 190 rigs versus today 270 operating rigs. Versus today 207 operating rigs, sorry. We are now protecting our Q4 effective tax rate to be in the range of 28% to 32% in addition to the U.S. statutory rate that we incur incremental state and foreign income taxes.
And now looking at our financial position, Helmerich & Payne had cash and short-term investments of approximately $380 million at June 30th versus 270 million at March 31, 2019. We are in cash flow from operations of approximately 250 million in fiscal Q3. A portion of this increased cash flow was due to a working capital unlock related to both reduced activity and new initiatives to optimize working capital, as well as our discipline on capital expenditures. When adjusting for sequential quarter networking capital changes, our operating segments generated approximately $119 million in cash flow from operations in the third quarter.
After funding our Q3 CapEx of $74 million and paying our quarterly dividend of approximately 770, sorry, of approximately 77 million. We had roughly 40 million in cash accretion outside of networking capital changes. Our debt to capital at quarter end was about 11%. The continued best in class measurement amongst our peer group H&P has no debt maturing until 2025. Our balance sheet strength, liquidity level, and term contract backlogs provide H&P the flexibility to adapt to market conditions, take advantage of opportunities, and maintain our long practice of returning capital to shareholders through dividends.
That concludes our prepared comments for the third fiscal quarter. Let me now turn the call over to Tony for questions.
Great. Thank you. [Operator Instructions] We'll take our first question from Brad Handler with Jefferies. Please go ahead. Your line is open.
Thanks very much, good morning. And thanks as always, for the detail. I guess, I can't help but queue in a little bit John on your, you sniffed out a little bit of optimism for 2020 I guess or 2020 preparation. So maybe we could ask you to expand on that. The obviously that would sort of buck, what might be considered a normal seasonal trend of operators kind of backing off because of budget exhaustion. But I imagine you're thinking there is a guide path the guide path that they've already set to be more conservative with it. But again, if you could expand on that, please that would be helpful.
Sure. Well, I think, obviously, the feedback that we get from our customers, and of course, we like everyone, we digest all of the sell side commentary and try to keep up as much as we can with budget, the budgeting process. And I think we would all agree that, budgets were set in this $50 to $55 price range for ‘19. And more of the budget was spent more than 50% of budgets were spent in the first half of the year. And so you combine that with kind of the discussions that we're having with customers. And again, it's, we're not in the business of predicting what rig counts are, but that's kind of what we're seeing is towards the end of this quarter going into the next quarter, we see it feels like it's starting to kind of flatten out.
I think, again, depending on what the budgets are for 2020 what oil price scenario is used. But if you were to assume that it's a 50 to 55. Again, that more than likely is going to require an increase in rig activity, in order to do get to the number of wells that need to be, need to be drilled.
So that's kind of our view. And we backing it up a little bit with some of the customer conversations that we have. Obviously, we can't go into a lot of great detail there. But that's kind of our basis for our assumption.
Understood, understood, I guess I'll askyou to reach in even if it's, you can obviously swap away as you need to. But do you sense and this would obviously be akin to your customer strengths anyway. Do you sense that it continues to be IOC led, or at least very large E&P led in that respect, or is it even broader than that?
I don't think there's any doubt that there's some of the larger companies that have, have had budget capacity. But in terms of getting prepared, getting ready for 2020 calendar 2020. I think there's a wide range of customers that are looking at different opportunities. So I think it's more broad based than that.
That's encouraging obviously, if I may a shift and just maybe it's just an education thing. Mark, you talked about self insurance? I'm not exactly sure what to do with that, right? I mean, obviously, that's their choices that you make. And it just sounds like there were expenses incurred, that obviously, you don't generally have insurance for, but how volatile is that, should I be reading in that it just, there were incidents that needed to be addressed? And therefore, those are not considered to be sort of normal course of events? What do I do with that I guess?
Brad, thanks for the question. We have a large amount of retention that we managed internally before going to the insurance markets. And so there is some volatility, because as you alluded to, whenever any sort of incident arises, sometimes it's unpredictable as to the amount. And in addition, they can have a long duration in terms of eventual settlement. So you may know this through all three operating segments from quarter-to-quarter, we occasionally have adjustments, up and down related to our retention levels.
Fair enough, and so it's just, you obviously plan for that it was a little below your normal run rate expectations. Last quarter was obviously about it this quarter.
Again, it is hard to beyond a run rate we obviously work with an actuary to try to ascertain what that run rate should be, but actual events don't always unfold as planned.
And then I'll turn it back was it very concentrated the higher expenses was it very concentrated in one or two or three rigs? Is that how we might think of it?
No, it's really just with the scale that we have the number of rigs that we have operating in so many different regions of the country that, it can be lumpy.
Next, we'll move to Sean Meakim with JPMorgan. Please go ahead. Your line is open.
So John, first thing, how would you characterize the guy is that you gave for fiscal fourth quarter. So meaning, would you think that this is some of your fleet catching up with the rest of the lower 48 given your rigs have been fairly resilient. And the first half of the year you've taking share? As we've had more rigs come off, are you just kind of seeing a bit more of a catch up? Or what is the difference between the customer mix see if I can help us understand maybe how you're perceiving things differently than a few months ago?
As you know, looking at our data, I don't think we've lost any share if we have it's a very, very small amount. And I don't forecast necessarily losing any share going forward. Again, all we really have to face other than the public data is our internal communication with customer with customers. And again, keep in mind when I talk about churn, we have rigs released and rig often times before it ever hits the grass, re-contracted. And then of course, there are rigs that are coming out of the grass that have been re-contracted. And so there's just this consistent if you will of risk being released and going back to work. And this is just again, we try to give a broad range. Obviously, we gave a broad range for Q3, and we hit the bottom or just under the bottom of that range. Again, we've got a range here, it's just, it's just a function of where we're, we'll hit, again, our hope would be is it will hit in the middle, or will hit higher, but still got a long way to go in the quarter. I know, it's not a direct answer, but I sure don't see us losing any ground in any way. I think the super spec fleet is, is very well positioned. We've got very good performance going on, our people are doing an excellent job. So, I don't have any concerns there. I've mentioned in my prepared remarks related to the legacy rig fleet. I mean, those are those are real numbers. There are still, I mean, let's face it, there are still over 200, legacy rigs, drilling horizontal wells, and in some cases, they're drilling some of the more complex stuff. That's really a mismatch, it's a disconnect. And, we are seeing customers that are utilizing those type of rigs that are saying that they see an opportunity to improve.
At the same time, the smaller companies, with smaller rigs, maybe less capable rigs, are also doing everything they can to keep rigs running. So you know what that means? They're pushing the price envelope, but when you start talking value proposition, it's, the lower day rate just doesn't win the day.
Understood. And I appreciate that, that kind of leads to my other question. So far, you've elected to focus on value over volumes in this environment, right. And that's, that's been proven to be the right approach so far. But then as we get later in the year, and we see more rigs come off in the aggregate, and more of your peers are going to roll over decent sized portion of their contracts to, to new rates. At what point do you think that the market may force you to change how you approach that value over volume strategy?
Well, a couple of things. One would be, I don't know which rig, specifically you're talking about that are, that are rolling have already addressed but the legacy piece of it. But the value proposition is if rigs are delivering value, they're going to be hard pressed to be replaced by something that is given a $3000 or $4000 or $5000 a day discount, because all you have to do is save a couple of days, on a 15 to 20 day well. And you've more than paid back the discount on the, on the prices of the rig. So the fact of the matter is of the rigs that we've had released, and again, I addressed this in the prepared remarks it may not be clear, but 30 rigs that are released over 80% of those at the end of the budget, there was no negotiation, we could say, hey, tell you what, we'll give you the rig for free and they wouldn't have been able to keep the rig running.
And more than likely it was a rig that was a spot market rig regardless of if it was a top performer. If it's the end of this program, it's going, it's going down and there was no rig coming in replacing it at a lower rate. And so I suspect that we'll continue to see that but once you get to this level of rig count that probably a lot gets it to that kind of breakeven of spending, essentially 100% of your budget for 2019. Then our view and what we're hearing from customers is that they're going to maintain that rig count. They're not going to continue to release. So I hear what you're saying, the super spec utilization is still close to 90%. With the numbers that we're describing it, we would think it would be in the mid-80s, 85%, 86%. But again, the value proposition is what really wins the day.
Next we'll move to Tommy Moll with Stephens, Inc. Please go ahead. Your line is open.
John, I wanted to start on auto slide. Good to hear the progress rolling it out and additional basins with plans for one more this quarter. You did highlight the disruptive aspect of the technology and how that can present an extension of the timeline for customer adoption? But to unpack that a little bit. Could you update us on how many rigs are now running auto slide and then going forward without putting trying to put numbers around it but just speaking generally. Is this a situation, like you see with a lot of technologies where somewhere down the road, we hit a tipping point. And enough customers have tried it and talked to one another and had good results that maybe there's a meaningful inflection higher?
Yes. That's true. I think, I've mentioned it previously in that. We saw very similar type trend with flex rigs in the early days, it was tough letting early on. And once customers began to see the value, then there was a push. And so today, we're on five rigs in those four basins. We could be on more rigs today. But again, we're being very purposeful and the way that we're rolling this out. And our hope would be at least the plan right now would be to double that by the end of this fiscal, the fourth fiscal quarter.
As we continue to add a customer, and as we add additional rigs to current customers. So the rollout has been purposefully slow, because, again, we're doing something that's really never been done before. And a lot of what has to take place is proper change management, which means clear communications of the goals. And it's obviously very important that our customer has a clear vision of what they want to accomplish. And that's part of what I was addressing and again in my remarks. Where they want this reliability, they don't want to have a top 10%, 20%, 30% of their fleet, they want everybody to be performing on the drilling side in a similar fashion. And you can do that of course with automation.
And so that's I think what's really the driver and this idea of having capital certainty. So as an example, you don't have 5%, 6%, 7%, 8% of your well that lie on the curve in the wrong part of the zone, right? And then you got those challenges that costs you money. So there's lots of advantages on that. There's risk, less risk as far as landing, and there's less risk as it relates to using the example of tripping. We've seen examples where we're tripping less, so you have less exposure to employees, because you're tripping less. You're just you're drilling ahead.
So I agree. I think there, I think there will be a tipping point. It's kind of slow going right now. But we definitely have some very strong customer partnerships that are that are really working out very well right now.
Thanks, John. That's all very helpful. And shifting. Shifting gears. Mark, I wanted to circle back to a comment you made about decommissioning cost that we should anticipate for the flex fours. Is that something that's going to show up at some point in the daily operating costs in the model? And if you are able to comment maybe on timing or magnitude, I think it would help set everyone's expectations just for the OpEx. Although, we know in advance that it's coming.
Yes. Thanks for the question, Tommy. As you go from as you go from our normalized per today, figure of around 13.7, to the average expense says yes, in there you would see, I don't know roughly $100 per day, at least in this next fiscal quarter. There could be some trailing cost in the first fiscal quarter of 2020, just depends on we're still finalizing plans related to the exact, this is just another component tree on the decommissioning rigs. And, that'll also factory on the how much bleed over we have from quarter to quarter, but it should be nonetheless, transitory costs, and it totally winds down around the beginning of the calendar year.
Right. Thank you. That's all for me.
Great, thank you. Next, we'll move to Kurt Hallead with RBC. Please go ahead. Your line is open.
Hey, good morning, John. Mark, everybody. Thank you so much for the color commentary on what's going on the marketplace. Hey, John, just want to get a general sense, right. It sounds to me like the conversation you're having with the customer base. As indicated, is suggestive of, you have started to think about what you're going to need going into, going into 2020. The narrative also sounds very similar to what we've probably heard over the course of past 10 years in terms of the matter what the price point is on a less efficient rig. As you already mentioned, the value proposition for using, a super spec rig doesn't make sense in swapping. It seems like there's cost currents out there. So just want to really clarify, is the pricing pressure that you indicated? Is that solely coming at the lower end of the rig market? And secondarily, can you confirm that you haven't experienced any indications of some of your competitors starting to discount pricing on super spec rigs?
Well Kurt, as you know, you've been in this business for a long time. There's always a certain amount of pricing pressure that's going on but as well complexity as we have more complex wells, there's less of that, because they understand the value proposition.
There's no doubt that on the lower end of the spectrum. There's a lot of, what we would call in the past hand-to-hand combat, fighting in the trenches. That's some tough pricing going on. But I think in general, the bigger players have, at least from our perspective, have held and have had some pretty strong pricing discipline. I mean, there's always exceptions everybody is going to have an exception here or there. Depending on whether a rig's performing or not performing or whatever, various situations. But I think in general, it's been a pretty disciplined market.
Appreciate that, maybe as a follow-up to it. To me, that sounds like based on your commentary that we're headed for another kind of wave of early terminations, whether it be in U.S. or international markets. Can you comment on that?
We sure haven't had any. I think any early termination payments we've received have been legacy type. And they've been very small. Again, I mentioned earlier, a lot of the rigs that we've had released were spot market rigs that, they were top performing rigs but they weren't on term, and the customer had to get down to certain rig count. So I don't expect that we're going to see any early terminations. Again, we're hoping that we're getting close to this rig count dropping out, and then hopefully getting prepared for '20.
Great, thanks. And maybe just one last one for Mark, gave very specific and detailed guidance by segment. One thing that was left out that kind of begs the question, which is, can you give us some general sense of what HP Tech gross margins could be, in that, with that $17 million and $18 million of revenue that you provided?
I think, if you, Kurt, I was kind of break that into two buckets. If you look at the run rate, we've had the last couple of quarters of HPT. And the MOTIVE, MagVAR and new burgeoning auto slide products. You could extrapolate that portion of HPT, they continue to have the same margin. But if you add to that the FlexApp the migration into Q4, that's a very high margin software application. And so you're just going to need to blend those together.
And next we'll move to Chris Voie with Wells Fargo. Please go ahead. Your line is open.
Just a follow up in the last question a little bit. I see that the prior quarter was not restated. Can you give a figure of how much revenue or sorry margin per day came out of the quarter with switch reflects that into HPT?
In the third quarter, it was still in U.S. Land. We said that was about $450 per day in revenue and that's pretty much full margin revenue.
And then switching gears. Just curious I'd like your commentary on this but. It seems like higher efficiency is kicking in the Permian finally especially the Delaware to some extent. Do you view that as much of a factor in terms of the rig count trending bit lower than you previously expected?
I don't really have a sense of the efficiency gain that you're that you're mentioning.
It just seems like the cycle times are starting to move there compared to other basins, but.
Well, I'm sure, I know the Delaware has some challenges as an example that you don't have an Midland Basin cycle times are faster. We like we always do we figure it out. And, and so I wouldn't be surprised to see the improvement. The other reason for improvement in that basin will be that I'm sure there's a much higher percentage of AC drive super spec rigs working in there today than there were a year ago. And that will make a difference as well. But, we over time as an industry, our customers working together with service providers, we figure out how to how to drill those more effectively.
I think we have a lot more rigs working in the Delaware also. So that also helps to drive greater efficiencies.
Okay, that's helpful. Thank you. I'll turn it back.
All right. Thank you
Chris thanks and congratulations on your new responsibilities.
Thanks a lot.
And thank you. Next, we'll move to Scott Gruber with Citigroup. Please go ahead. Your line is open.
Yes. Good morning.
Good morning, Scott.
Mark, you highlighted the progress and overhead that you've made. But with rig count expectations for 2020 coming down here across the industry, are there additional overhead and support costs reduction opportunity that you're contemplating, is there an opportunity to get leaner and leverage technology more to reduce costs?
Well, I think, as I alluded to in the prepared comments, I think we're pretty well scaled in one respect, towards total support back office processes for the company. We've been able to leverage a bit to reduce G&A this year, even though we have as I mentioned, more rigs working then at this time last year. Nevertheless, there are various parts of the company that certainly can see some scaling up or down related to rig counts, one. Two, I mentioned our new initiatives to optimize working capital. And essentially, we implemented a world class ERP system just the last couple of years ago. And we are working on numerous process improvements, to really optimize that ERP system and automate many of our back office processes. And those have real business implications such as the working capital unlock we experienced this quarter with some recent, focused initiative.
And then I guess thirdly as it as it relates to our district offices and our country offices internationally. We have various expansion and contraction obviously in the direct support. Those offices related to the number of rigs working.So we're is something we're continuously tweaking as we move through time and react to the business.
Got it and then just on the CapEx side. You highlighted potential maintenance, here in fiscal '20 it's 230 given your rig count expectations, and overall fiscal ‘20 CapEx, likely coming in below 300. Can you provide some more color on the potential gap in between the low 200s and the high 200s what your other initiative are contemplated? And how quickly could you flex down towards the lower end if your volume expectations are hit, but very pleased there's some pressure on cash flow.
Firstly, let me mention that the 230 rig count I quoted was the rig count literally as of today across all segments. So we think that a rig count hopefully will be higher, that's going to be part of it to begin with. Through the rest of this summer and complete our budgeting and return to you in November with our guidance for next year, we'll fill in some of those holes. But we always have issues, we're looking at related to various improvements and our rig capabilities.
So we incur some special projects there and have historically year-over-year. And then also, as we continue to optimize and improve back office functions. We do encourage some IT spend and other corporate spend. And then we have legacy businesses, where we also have some CapEx spend such as our Tulsa real estate business, et cetera. So lots of potential variability, we're just at the beginning of the budgeting process. And we wanted to give some sort of indication related to that, in terms of rig count, because that maintenance CapEx is going to be the predominant part of fiscal 2020 CapEx, it will be directly correlated to that rig count.
And we'll next move to Marc Bianchi with Cowen. Please go ahead. Your line is open.
I wanted to switch over to international quickly to just get any update on the opportunity to deploy more super-spec rigs outside of the U.S. You have a couple that are going in Argentina now. Just wondering, if there's any new information to discuss on that front?
Sure Marc. I think Argentina, obviously we've got a strong position there. And have been encouraged that we've had these opportunities. And I think there are still opportunities to do more. Don't have anything signed up obviously yet. But I do think there's some opportunities to grow in Argentina. We continue to hear seems like there's a lot of momentum with IOCs that are looking to grow their further production there.
So I think overall, it seems pretty encouraging. As far as outside of Argentina, the Middle East obviously holds some great promise, I think for us in the future. It's just hard to see it. We don't have clear visibility into when that time it would be. We've generally kind of cast it by saying when we begin to see unconventional resource plays, more horizontal drilling and international markets, and obviously, that's a great place for us to take our technology and our capabilities. So outside of Argentina don't have any real clear sight into anything other.
John thanks for that. And last one, just for Mark. On the tax rate guidance, you provided here for the fourth quarter seems perhaps a little bit high from what might be a normalized rate. Can you just give us some commentary and how you think about that for 2020, fiscal 2020 and beyond?
Yes, Marc, it's little high in Q4 again to the big loss in the difference that we incur in this quarter. So to get back to more of a normalized year-to-date rate. And then it should drift back down, again for fiscal ’20 and be somewhere between 21% statutory rate and 30% just dependent on the state and foreign taxes and the jurisdictions and where we operate.
Thanks very much appreciated.
Thank you.
Thank you.
Thank you. And at this time, I'll turn the call back over to Mr. John Lindsay, please go ahead, sir.
Okay, Tony, thank you. And thank you everyone for participating on our third quarter earnings call. To reinforce we believe we're very well positioned we have the flexibility and have a solid strategy for this changing industry outlook. The value proposition of the super spec flex rig the value or digital technologies and automation capabilities. Obviously well bore quality, pricing reliability. And finally a strong track record of financial discipline strong dividend policy with the flexibility to respond to market opportunities. And then finally, I just want to thank all of our people for their focus on actively care for teamwork and working with our customers daily work and driving high levels of customer service. Thank you again and have a great day.
Thank you. This does conclude today's conference. You may disconnect and have a great day.