Helmerich & Payne, Inc. (HP) Q2 2019 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to today's Fiscal Second Quarter 2019 Earnings Conference Call for Helmerich & Payne. [Operator Instructions] Please note this call is being recorded. It is now my pleasure to turn today's program over to Dave Wilson, Director of Investor Relations. Please go ahead.

Thank you, Priscilla, and welcome everyone to Helmerich & Payne's conference call and webcast for the second quarter of fiscal year 2019. With us today are John Lindsay, President and CEO; and Mark Smith, Vice President and CFO. John and Mark will be sharing some comments with us, after which we will 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, and we undertake no obligation to publicly update these forward-looking statements. We will also make reference to certain non-GAAP financial measures, such as segment operating income and operating statistics. You'll find the GAAP reconciliation comments and calculations in yesterday's press release. With that said, I will turn the call over to John Lindsay.

Thank you, Dave, and good morning, everyone. From the outset, this quarter was challenged with industry uncertainty, so I'm pleased to report that the company not only stayed on target and delivered sequentially improved net income, but also achieved 2 significant milestones. Concern over crude oil prices persisted from the prior quarter, which softened demand for incremental super-spec rigs, however, H&P completed the planned upgrade already in the pipeline. With those rigs, we added significant term backlog at attractive rates and margins, and our total number of super-spec FlexRigs increased to 230 at quarter end, representing more than 40% of the industry's U.S. super-spec capacity. Our current U.S. rig count is approximately 220 FlexRigs. Considering the trends we're seeing in rig releases, the higher levels of churn across certain basins and the current demand, we believe the company's rig count will bottom out early during this third fiscal quarter and FlexRigs super-spec utilization will remain in the 90%-plus range. Importantly, this level of utilization should be supportive of the current pricing environment. Another factor that is supporting super-spec pricing is the top 5 U.S. land drillers own approximately 80% of the active super-spec fleet. With the industry super-spec fleet already over 90% utilized, this degree of supply concentration also promotes a sturdier pricing environment going forward. The oil price for WTI is up over 40% since the beginning of the calendar year. In past cycles, this kind of price action would bring on higher activity, yet today, we are seeing a more tempered response and even reductions in activity by some in the industry. Clearly, customer behavior is changing and the movement is towards prioritization of cash flows and less focus on growth. This returns-focused approach has put additional emphasis on disciplined spending and determining where value can be added to improve performance and long-term cash flow. Principles that are focused on returns resonate with H&P and are aligned with our goal to deliver performance to both the customer and the shareholder. We believe we're exceptionally positioned in this kind of environment with the right hardware, a FlexRig fleet that is an industry leader in drilling unconventional wells; and with the right software, a digital technology platform focused on wellbore quality and placement that when deployed on a rig, are proven to improve well economics. Further, these principles align with our own capital allocation policy, part of which includes returning cash to shareholders through our dividend for the last 60 years and with an increasing dividend over the past 47 years. On our January call, we said our customers had a mix of outlooks regarding CapEx. They were up, down and flat. We also expected our customers would be setting their 2019 budgets within expectations of $50 to $55 WTI. We compared the public company and majors' announced CapEx budgets for 2019 compared to 2018 and found the total budgeted CapEx is only down approximately 5% year-over-year. This supports the view we expressed on our January call that the rig count reduction would likely be less than 100 horizontal rigs. And thus far, the rig count is down approximately 70 rigs. Further to that, H&P's top 25 customers, which represents about 80% of our working rigs, reduced their CapEx budgets by an aggregate of approximately 4% for 2019. Even with the current price of approximately $65 a barrel, we're reticent to expect that the overall industry rig count will do more than remain flat through the rest of this quarter. Of course, there is the caveat and I would like this to be true, oil prices remain strong, and we experience less oil price volatility and the rig count improves in the back half of 2019. We know at least one public E&P, who has indexed their capital allocation strategy, including CapEx to align with price of WTI. If that practice is more common than we know, and if the private E&Ps would take advantage of higher oil prices, perhaps we'll have better rig activity than flat in the second half of 2019. With a trend toward multi-well pads, the industry has ushered in the need for additional manufacturing-type requirements. It isn't sufficient to only drill wells fast and efficiently anymore, but it's also important to have a higher quality, reliability and more accurately placed wellbore. Industry studies have documented that wellbores with less tortuosity produce more oil and more accurately placed wellbores produce fewer parent-child well interference issues. Both of these factors are important to consider as customers want and need to do more with less. I will touch on this more in a minute when discussing our new H&P Technologies segment. So let me begin with our first milestone achieved during the quarter. We have a commitment to send our first super-spec FlexRig overseas. We have long believed H&P's growing leadership position in the U.S. unconventional basins would lead to further international opportunities to deploy our U.S. super-spec FlexRigs, our FlexApps and our H&P technology software solutions, including AutoSlide and deploy those overseas. That has come to fruition as we signed a letter of intent to deploy our first super-spec FlexRig from the U.S. land fleet to Argentina later this quarter. We're excited about this opportunity and not only what it portends for H&P's Latin American business, but other international locations as well. Now let us shift our focus to the H&P Technologies segment and the second significant milestone. During the second fiscal quarter, H&P commercialized its drilling automation technology, AutoSlide. We believe AutoSlide is the next evolutionary step in drilling automation that is scalable on FlexRigs as a result of our uniform FlexRig operating system. Our software-based offerings from our H&P Technologies segment, with Motive and MagVar, along with our FlexApps, which are designed for FlexRigs to enhance downhole tool life and drilling performance. As I mentioned earlier, as customers continue to push the envelope on manufacturing drilling, the benefits of H&P Technologies have a meaningful impact on well economics by improving production dynamics and lowering the risk of wellbore interference, thereby bolstering financial returns through the life of the well. We are committed to partnering with our customers to unlock these benefits that autonomous drilling technologies can provide. Another important differentiation of our technology offerings involves not only the technology platform but also the business model we have developed. Our strategy is unique. Most of our digital technology and software is designed and available on all rigs, not just H&P FlexRigs. This is an important distinction because it allows our customers to utilize the software and data sets across their entire fleet of contracted rigs. So before turning the call over to Mark, I want to close with recognizing that the company achieved excellent operational results and several technical accomplishments during the quarter. Our ability to adapt and respond to uncertain market conditions while securing new opportunities for long-term success is paramount. These achievements aren't possible without the efforts of our people working as a team to deliver on our goals and by forming strong partnerships with our customers. These efforts exemplify H&P's commitment to excellence. And now, I'll turn the call over to Mark.

Thanks, John. Today, I will review our fiscal second quarter 2019 operating results, provide guidance for the third quarter, update full fiscal year 2019 guidance as appropriate and comment on our financial position. Let's start with highlights for the recently completed second quarter. The company generated quarterly revenues of 200 -- $721 million versus $741 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 segment as expected. Total direct operating costs incurred were $443 million for the second quarter versus $489 million for the previous quarter. The decrease is primarily attributable to lower-than-expected daily operating costs in U.S. Land and to the $18 million effect of a onetime legal settlement in the first fiscal quarter. They were operating costs experienced were in both regular daily operating maintenance and supplies as well as in rig reactivation costs. General and administrative expenses totaled $44 million for the second quarter. This is below the run rate for our full year guidance due to the timing of certain company projects, but our full year guidance for G&A has not changed. Our effective income tax rate from continuing operations was approximately 26% for the second fiscal quarter, which was in line with our annual expected rate and includes incremental state and foreign taxes as well as the U.S. statutory rate. Summarizing the overall results of this quarter, H&P earned $0.55 per diluted share versus $0.17 in the previous quarter. Second quarter earnings per share was negatively impacted by a net $0.01 per share of selective -- select items as highlighted in our press release. Absent the select items, adjusted diluted earnings per share were $0.56 in the second quarter versus an adjusted $0.42 during the first fiscal quarter. Capital expenditures for the second quarter of fiscal 2019 were $134 million, so when combined with Q1 CapEx, we have expended approximately 65% of our full year CapEx guidance as revised last quarter. This lines up with our guidance that fiscal 2019 CapEx would be front-loaded. Turning to our 4 segments, beginning with the U.S. Land segment. We exited the second fiscal quarter with 226 contracted rigs, which was a decrease of approximately 1% in the number of active rigs quarter-to-quarter. H&P maintained over 20% U.S. Land market share from quarter-to-quarter. I will discuss this in more detail in a moment, but we anticipate that our rig count will approach a current cycle bottom in the third fiscal quarter and our super-spec rig class will maintain an average utilization level of approximately 90%. H&P has leading market share in the top 3 U.S. basins, 24% in the Permian, 39% in the Eagle Ford and 26% in the SCOOP/STACK. Our activity levels in each are 114, 39 and 25 rigs contracted, respectively. Despite slowing market conditions in the second fiscal quarter, we were able to maintain pricing in a tight super-spec market space. Our average rig revenue per day, excluding early termination revenue, increased to $25,624 for the quarter in line with our guidance. Included here is the increasing customer adoption of our FlexApp offerings that are approximately $300 per day per rig in revenues across the fleet, up from $250 last quarter. The average adjusted rig expense per day decreased to $14,195. This is below our previously guided range due to lower-than-expected maintenance and supply expenses and lower reactivation cost. Looking ahead to the third quarter of fiscal 2019 for U.S. Land. While putting second fiscal quarter upgrades to work under term contracts, we also experienced a number of late quarter rig releases. We are currently seeing net rig releases moderate, which will result in the sequential decrease of approximately 4% to 6% in the quarterly number of revenue days. This translates to an average rig count of approximately 220 rigs during the third quarter, which is approximately where we are as of today's call. To reiterate my previous comment, we expect super-spec utilization to remain in the 90% range during the third quarter. Compared to the second quarter, at $25,624 per day, we expect the adjusted average rig revenue per day to be flat within a range of $25,500 to $26,000. Our average day rate in both the spot and term market is in the low to mid-20s range and leading edge super-spec FlexRig pricing is in the mid-20s. The normalized average rig expense per day directly related to rigs working in the U.S. Land segment remains constant at $13,700 per day. This per day figure excludes the impact of expenses directly related to inactive rigs, the idling of released rigs and the upfront reactivation expenses related to rigs that have been idle for a significant amount of time. Including these 3 costs, the average rig expense per day is expected to be in a range of $14,250 to $14,750 for the third quarter. Note that with the reduced number of upgrades beginning in this quarter, upfront reactivation expenses will continue to come down while moving the average rig expense per day toward the normalized expense per day number of $13,700 through time. However, note that the third quarter will still see reactivation expenses from upgrades that commenced toward the end of the second quarter. We had an average of 149 active rigs under term contracts during the second quarter. And today, that number is 142 rigs or about 65% of our 220 working rigs. We expect to have an average of 137 rigs under term contract in the fiscal third quarter and 124 rigs in the fourth quarter earning the current average day rates. For the 79 rigs that remain under term contract in fiscal 2020, the associated day rate is approximately $250 per day higher than today's average. We received $1.2 million in early termination revenue in the second quarter and have only experienced a couple of early terminations during this calendar year. The remaining terms on these cancellations were not material to our overall revenues. Regarding our international land segment, the number of quarterly revenue days decreased 11% in the second fiscal quarter, in line with our guidance and due primarily to 2 rigs stacking in Colombia early in the quarter as expected. The adjusted average rig margin per day in the segment increased by $1,679 to $11,861 in the second fiscal quarter. The increase was primarily due to higher-than-expected rig margins, which were offset by fewer working rigs in Colombia. As we look toward the third quarter of fiscal 2019 for international, quarterly revenue days are expected to be flat to down slightly with an average third quarter rig count of approximately 17 active rigs in the segment. The average rig margin is expected to decrease slightly to between $9,000 to $10,000 per day during the third fiscal quarter due to only one active rig in Colombia absorbing that country's overhead costs. As John mentioned earlier, we are expecting to send our first international super-spec rig to Argentina. This rig is expected to commence operations with an international E&P customer midway through the fourth fiscal quarter under a term agreement that will be accretive to our average international margins. In addition, just this week, we also signed separately an LOI to reactivate a Flex 4 in the country of Bahrain, increasing to 2 Flex 4s in that country. Turning to our Offshore Operations segment, we continued with 6 active rigs during the second fiscal quarter, but a second rig moved to standby rate, which negatively impacted revenues for the quarter. The average rig margin per day decreased sequentially due to the lower standby rate being in effect for most of the quarter as well as higher self-insurance expenses. As we look toward the third quarter of fiscal 2019 for the offshore segment, we currently have the 6 of 8 rigs contracted. The average margin per day is expected to increase to a range of $9,500 to $10,500 during the third quarter as 2 rigs are anticipated to move from the standby rates to full operating rates. Now looking at H&P Technologies segment. As John mentioned, AutoSlide is now commercial, and our plans are to methodically roll it out to our active basins. Timing and rate of adoption of new technology is hard to predict at an early juncture, but we believe AutoSlide provides a unique path toward differentiated pricing models for drilling services that are inclusive of wellbore quality and placement services. From a historical day rate perspective, the potential margin accretion of this software service begins at the anecdotal market day rate for a directional driller of approximately $2,000 per day. Added to this would be an amount reflecting the value add to our customers for consistent, repeatable quality. As previously guided, we are on a path toward autonomous drilling, and we are continuing to make significant research and development investments, which we believe will result in new services and increased market share over time. Now let me look forward on corporate items for the remainder of the fiscal year. Our current revenue backlog for the U.S. Land fleet for rigs under term contracts, which we define as rig contracts with original fixed terms of at least 6 months and that contain early termination provisions, is approximately $1.4 billion. Capital expenditures for the full fiscal year 2019 are expected to remain in the revised range we guided to in January, which was $500 million to $530 million. As a reminder, capital investment in our fleet is comprised of 3 distinct buckets. Bucket 1 contains capital expenditures to upgrade and convert FlexRigs to super-spec capacity. Much of this first bucket was front-loaded in the first 2 fiscal quarters with a total of approximately 5 walking rig upgrades planned for the remainder of the fiscal year, which are backed by term contracts. The second bucket consist of FlexRig capital maintenance, which typically ranges between $750,000 to $1 million per active rig per year. The third bucket of 2019 CapEx is comprised of 2 items: one, fiscal year 2019 catch-up on bulk spare equipment purchases to support the increased scale of our super-spec fleet over the last 2 years; and two, higher capital rig reactivation cost due to the average idle time of a reactivated rig being close to 4 years of stacking. Our CapEx range includes incremental expenditures to send the aforementioned super-spec rig to Argentina, while leaving our overall CapEx range unchanged. We expect to see reduced maintenance CapEx given our current rig activity levels, and these, along with expenditures for certain bulk purchases, will correlate closely with our operating rig counts. Despite the Q2 timing results, our general and administrative expenses for the full 2019 fiscal year are expected to be roughly flat from 2018 to approximately $200 million in total. G&A will somewhat fluctuate from quarter-to-quarter due to the timing of various company initiatives. In addition to the U.S. statutory rate, we continue to incur incremental state and foreign income taxes, and we are still projecting our annual effective tax rate to be in the range of 26% to 30%. And now looking at our financial position. Helmerich & Payne had cash and short-term investments of approximately $270 million at March 31, 2019. Including our expanded and extended revolving credit facility availability, our liquidity was approximately $1 billion. Our debt to capital at quarter end was approximately 10%, the lowest amongst our peer group. We have no debt maturing until 2025. Our balance sheet strength, liquidity level and term contract backlog provide H&P the flexibility to adapt to market conditions, take advantage of attractive opportunities and maintain our long practice of returning capital to shareholders through our dividend. As we look ahead into the planning horizon, we are confident in the future potential cash flow generation of our fleet. Using our cash flow from operations this second quarter of approximately $200 million as a simple planning proxy, we could generate $800 million of annual run rate cash flow from a 220 active U.S. Land rig count, together with our 23 current active international and offshore rigs. Assuming only maintenance CapEx of the annual midpoint guidance of $875,000 per active rig, our CapEx annual run rate would be approximately $210 million. The remaining cash flow in this static simple run rate example, $590 million, would be available for our longstanding dividend and other capital allocation opportunities. That concludes our prepared comments for the second fiscal quarter. Let me now turn the call over to Priscilla for questions.

[Operator Instructions] And we'll take our first question today from Jud Bailey with Wells Fargo.

My first question, I think is, Mark, wanted to follow up on one -- some of your comments on operating cost per day. I think you indicated you still expect to ultimately get to kind of normalized level of around $13,700. Is that a level that we should anticipate or can start to think about for the September or the December quarter? Is -- do you have a line of sight to that's something that makes sense based on the slowdown in reactivation super-spec upgrades?

Well, thanks for the call and question. As we look at it, there's a breakdown currently of about $400 per day for upfront reactivation expenses. So I would assume, Jud, that, that is the part that you can start actively modeling downward in your slower cadence. However, we still have about $330 per day related to the inactive rig count that we have idle as well as because 2 idle rigs that we've experienced recently. So that bucket is a little bit harder to determine a direct line of sight to.

Okay, all right. Well, that's helpful, though. My follow-up I think is part for John. Could you maybe talk a little more about AutoSlide? And now that you're commercializing it, maybe talk a little bit about what you're hearing from customers? And how quickly the roll out may be there? And how quickly you think you may get more systems out in the field?

Okay, Jud. The -- it's very hard at this stage to judge the speed of the roll out. As Mark mentioned in his prepared remarks, we have a design in terms of rolling it out to various basins, and we started with Midland, and we're going -- we're in the Eagle Ford now as we said, and then in a couple of months our intent is to deploy into the SCOOP/STACK play, but our intent is to have AutoSlide in all of the basins. And so as you think about what we're doing in the automation phase, we're actually using machine learning and the Motive algorithm in the FlexRig operating system. So these -- the great news is these algorithms continue to learn and learn the basin, kind of, the specific differences and/or challenges that each basin may provide. And so again, there'll be more to come on it. We're working for 4 customers now: 3 in Midland; and 1 in Eagle Ford. And again, we're excited about the performance thus far, and again, this is the automation of the sliding function when drilling a horizontal well. So that's kind of the overview.

We'll take our next question today from Tommy Moll with Stephens Inc.

I wanted to follow up with one AutoSlide question. You mentioned in the prepared remarks a comparison to $2,000 a day for a directional driller. How should we think about being able to capture the full value that you're going to deliver to customers with AutoSlide? And is a day rate framework, the right way for us to think about it? Or is there an alternative strategy to go-to-market here with AutoSlide?

Yes, I think, Tommy, we're definitely not looking at a commercialization model that's based on a day rate. Mark was simply using that as just kind of an idea of part of the value proposition that a customer can see right off the bat, because AutoSlide does allow for the elimination of the directional driller on the rig site. Now we have directional drillers that are off site that are watching the wells real time. But it enables you -- as you think about some of the industry themes over the last 2 or 3 years, and one is automation, one is more of a demanning, being less reliant on having as many people on a rig site. And so I think it's one of those steps that allows that to happen. Part of the process of the roll out of AutoSlide and another reason for taking -- maybe taking a little slower than what we would normally take it. One of the things that's important is to understand the value proposition. And if you go back to the early days of the FlexRig and, of course, we were building -- we started off with building 2 rigs a month with the first Flex 3s that we rolled out. But there was a, definitely an adoption phase and our industry has a tendency to adopt, kind of, at a slower pace. But again, as you think about major themes that we've seen as an industry over the last couple of years, there's definitely a desire and a need to utilize digital technology, to utilize higher levels of technology and looking at demanning. So that's really the opportunity. So we have to jointly work on this value proposition with the customer. Again, there's the automation piece, but there's also the tortuosity -- less tortuosity, which delivers on things like better downhole tool life. It require -- it allows downhole tools to last longer, which means we're tripping fewer times, which means we're lowering risk at the rig site. And then again, I had mentioned in my remarks that -- I mean, there are some industry studies out there that are saying that the less tortuous wellbore has the potential for higher oil production. So those are big deals and every customer is going to be different, every situation is going to be different. So that's kind of the outlier. It's all about us figuring out ways to deliver higher levels of value for our customers. And of course, we're making significant investments, not only dollar-wise, but management time, structure, standing up H&P Technologies, all of those sorts of things are, I think, are very important in the success of the product. So again, it's all about customer value. And I think when the customer see the value, which we've seen a lot at this point, we think they're going to be in a position to want to pay for that performance.

And as a follow-up, I wanted to switch gears and talk about the international opportunity. You called out the LOI to send a super-spec to Argentina. Can you give us anything there just in terms of the back story? How long conversations had been going on? Anything anecdotal you could share, given this is a pretty important update to have your first deployment internationally? And then going forward, how big of an opportunity do you see? You mentioned in the prepared remarks that it not only involves the rig, but also technology potentially over time. So whether you answer that specific to Argentina or more just generally about the opportunity to export some of your capability, it would be helpful.

Sure. Thanks, Tommy. Well on the super-spec, again, as a reminder, we've -- we have, I think, 12 or 13 Flex 3s in Argentina now. They aren't super-spec and they have not been upgraded to super-spec. Again, one of the advantages that we have is the ability to upgrade those to super-specs. So this is the first, fully upgraded super-spec rig coming out of -- the FlexRig that's going down to Argentina. Again, it's a great opportunity. It's something we've been working on for, I don't even know the timing, probably over the last couple of months. I think there's additional opportunity for us to send more of the FlexRig super-spec capacity that's in the U.S. to Argentina, specifically, and also into other countries over time. And then obviously, there's the opportunity to upgrade existing rigs on the ground to super-spec capacity. So I think that's a great position for us. It's -- depending on what the market does here in the U.S., we've got additional opportunities outside of the U.S. As far as H&P Technologies, specifically, Motive and MagVar, both of those technologies are applicable to international markets, both on FlexRigs, as we've said, as well as on other rigs that our customers are contracting. And I think there's a lot of interest associated with both. And so I would expect, in the coming quarters, that we'll be able to talk more about that and be able to demonstrate some of the traction, some of the adoption that we've seen with these other technologies. We've -- I think, we may have mentioned in the past that there's always the opportunity to have the technology pull the rig through as one potential, but definitely there is interest, both in the Middle East and in South America for our technology offerings.

And we'll take our next question today from Scott Gruber with Citigroup.

A question on the extra cost in U.S. Land. Just ballpark, what is the cost to idle rig relative to the cost to reactivate? I know it will differ on a rig-by-rig basis but in a ballpark what is the delta between those 2?

Well the -- I think I might have mentioned in my prepared remarks the -- that the reactivation cost can be about -- from an OpEx perspective about $1 million to $1.5 million. It's really going to depend on the particular rig, so the idling cost is substantially less than that. So that's why the range of those buckets for reactivation cost versus idling costs have a delta. So we will, again, see regression of the reactivation cost through time that will mirror the slowdown in the cadence of upgrades. The idling cost should come off a little bit in that bucket just because we're seeing here early in the third quarter the leveling of the fleet count and that we will continue to incur the static idling cost for rigs that have long been inactive.

Scott, I may add a little bit more color on that as well and just so we're clear. Those reactivation costs that Mark mentioned are related to rigs that have been idle for a very long period of time. If you look at the reactivation of the most recently idled rigs, those reactivation costs are very, very low. And in fact, even the idling expense is very low because as compared to what we saw in '14 and '15, '16 time frame, when we were idling the rigs then, we took great care to do a lot because we realized those rigs weren't going to go back to work in a couple of weeks or a couple of months. So the rigs that we've idled recently, we fully believe are going to go back to work in near term. In fact a lot of them have. We've continued to have this ongoing churn, which is common even in the strongest of markets. The churn level is higher today obviously than it was, say, 4, 5 months ago. But we still have rigs that have idled recently, a lot of those -- some of those have gone back to work, it's just a continual churn. So I just wanted to make certain that you recognize that the most recently idled rigs to reactivate is a very, very low cost.

I appreciate the color. And then, I think, Mark, you called out $330 a day of cost for the inactive rigs. So if we're just, call it flat on the rig count and everything normalizes, should we be thinking closer to $14,000 as the normal daily rig cost of $13,700 plus the $300 in change?

It'll be a little less than that Scott, because the $330 is a combination of the inactive legacy fleet, if you will, and the cost to idle rigs that have recently been idled. And it's those costs of, say, $200,000 or so per day when we've been idling rigs in this calendar year that will come off with this moderation that we've experienced. So -- and we always see some churn, but the -- it'll -- we're going to be reducing, but it will -- it's going to -- what the ultimate number is, it's just going to be up to the market.

Okay. And then one on CapEx. I appreciate the additional color on where your maintenance stands given your current activity set. In the second half of the year, it looks like you'll spend $180 million, $190 million or about $90 million, $95 million per quarter. Again, ballpark, is that a good run rate to think about for fiscal 2020, assuming no major swings in rig count? Or would it be lower than that, given where your maintenance level stands?

I think it would be lower than that. If you think about the 3 buckets I mentioned in the prepared remarks, if you just assume that we were in a -- as a planning proxy, again, flat rig count next year and you eliminated the upgrade bucket for this illustrative example, you also would essentially remove the bulk catch-up bucket as well. So a long way to say you get down to just the regular maintenance on the active rig count, and that is really how if -- that's really how I think about modeling the next year.

And we'll take our next question today from Kurt Hallead with RBC.

So I think, John, what I think I'd like to maybe focus on a bit is the dynamics around the new technology, the AutoSlide, the applications and algorithms and the new business model and just want to -- want just to be clear as well on that dynamic. So the new segment you have is the Technology segment. So first and foremost, all of the AutoSlide and algorithms and apps and everything else, that's going to be housed within that new Technology segment, and I say that mainly because you're going to differentiate the revenue generation for that business vis-à-vis just adding a day rate for that. Am I understanding that correctly? Like all of that technology-driven business will be in that specific segment, it's not going to be layered into a day rate?

Kurt, on the FlexApps, the FlexApps are an IDC rather than HPT segment, but they are not day work type applications. We're not pricing those generally in that sort of a fashion. We're generally pricing them in a different type of a business model. The rest of the AutoSlide and Motive and MagVar, those are in HPT. In our industry, it's hard to -- it's been hard to not go down the day rate model. I think it's something that's kind of a legacy piece. And again, our effort is to develop different sorts of pricing models. We've been successful in doing that in some cases, and in other cases, it is in a day -- more of a day work type or a performance type of model, if you will. So that's the separation.

Okay. That's helpful. So you spoke about working with the customer base in defining and understanding the value proposition of what AutoSlide and the FlexApps are going to bring to the table. Obviously this is a discussion that you guys should be very comfortable with ever since the advent of the HP FlexRig into the marketplace you've been able to demonstrate that value prop. How do you find these discussions going with the customer base and then kind of what have you been learning as you've been having these discussions around how the E&Ps kind of view this new technology dynamic?

I think for the most part, our customers have been very embracing. I mean, I think, using an example of -- we've got -- I think, MagVar is on close to 300 rigs today and close to 100 for -- on H&P. Motive is still -- just still under 30 rigs, but the Motive challenges are much different than MagVar, as an example. But I think, in general, they've been very embracing. It's not a question of if the technology works or if the technology adds value. It's -- there's a certain element of change management that is always a challenge when you're introducing new technologies regardless of the industry, and again, our industry has some of those challenges. But in general, I think they're very embracing. We have a lot of interest, particularly on automation and being able to drive another level of reliability for our customers. As I said in my remarks, it is -- it's not effective enough today to only drill a very fast well. There's other elements of that and there's reliability and there's less tortuosity and there's better placement, and so I think that's really important.

That's great. Maybe I'll follow-up, talk about maybe the super-spec rig dynamics. I know you guys always provide pretty good information around how -- what you think the market size is and how many rigs are out there that are currently super-spec capability. And how many rings could potentially be upgraded? Could you give us a quick snapshot on that again?

I think, if you use our strictest definition that we've utilized, I think, there's around 520 super-spec rigs, with another 150 using that strictest definition that could be upgraded, and I think maybe half of those are actually working today. And then if you expand the definition, and if you look at, again, what we've said over time is look at what rigs are actually working and what their size might be, there are some either larger hook load or larger horsepower drawworks that have been outfitted to some of the super-spec capacity. And I think that's another 100 -- maybe 120 rigs or so that are active in the market today. And so that gives you, what, 650 or so that are active. I think it's also important when we have this conversation that we also mention that there's still about 230 legacy rigs, mostly SCR, but even some mechanical rigs that have been upgraded in some capacity or another to do some of this more challenging horizontal work. And those rigs are out there working today. Obviously, much fewer SCR rigs working today than what we saw in 2014. There's, I don't know what the right number is, probably 600 or 700 rigs that are gone. So I think there's a real opportunity to deliver a much higher level of value proposition to customers and continue to disrupt that legacy rig fleet business. And I fully expect that, that's going to continue to happen over the coming years. And particularly, I think in an environment like we see today, where customers aren't growing their fleets in a large-scale way, they're looking at their rigs and they're looking at them very closely quarterly and having quarterly performance reviews and determining who's performing and who's not. And in those situations, I think, you'll find where the AC drive and specifically, FlexRig's going to take some additional market share.

And just to add to that, John, as we said earlier, we have 230 super-spec rigs ourselves here at H&P, and currently we have another 47 that are available for upgrade, 8 of those are working. So we still have -- certainly still have added capacity within our fleet.

And we'll go next today to Sean Meakim with JP Morgan.

I was hoping you could just maybe clarify the cadence of upgrades for fiscal '19. Just to make sure we have the numbers straight. I think we have 14 that were completed in fiscal 1Q, I think 9 in the second quarter and I think there were at least up to about 2 or 3 more in the current quarter, but earlier in your comments maybe you said there was 5 more for the year. So I just wanted to make sure that those 5, or maybe that the 2 or 3 is probably inclusive of the 5? So it sounds like we're talking about something like 28 rigs. I think the budget is set around $180 million, so maybe $6.5 million per. That seems to kind of fit with your prior guidance of walking versus skid system. Does that all seem to fit properly?

Sean, yes, it does. Your math is spot on.

All right. It's not always the case, so I appreciate that. And then just on international, just to get a bit more of a clarification. Could you maybe give us a little more detail in what's driving the lower active international rig count quarter-over-quarter and the margin compression? Is it more as rig moves or maybe some mix shift within the rigs that are working? Just wanted to get a little more understanding there, if we could.

In the call in January, we had provided some guidance that we expected the Colombia market to contract a bit. We really see that market more directly correlating to the oil price movements. For this quarter upcoming that we're giving guidance for, we do not see any revisions back, even with the oil price trajectory that we've seen recently, but stay tuned.

Got it. Okay, fair enough. And one last piece on the international. We talked a little bit about the Argentina contract and then the Flex 4 going to Bahrain. How do think about rest of the world, ex-Argentina, appetite for incremental rigs that could be deployed internationally? And then long term the appetite for super-spec rigs in some of these other markets?

We'll -- I'll just make an introductory comment or 2 here. As it relates to the unconventional play as we've talked about and John specifically talked about on previous calls, we've had tremendous success in Argentina that mirrors the success we've had in U.S. Land. We certainly aim to be a part of that continuing story there. And next, we really look for unconventionals to be moved to the Arabian Peninsula. So several different countries in the Middle East, and I think on the January call, we even mentioned some of the inbound inquiries we've had there. And those are -- those inquiries are for AC rigs, in particular. Just an exemplary of that is this Flex 4 LOI that we have in Bahrain that we've just done this week. But in Argentina, the super-spec going there, our first super-spec to deploy internationally is really exciting because it talks about how the unconventional play in the Vaca Muerta is actually getting more complex and laterals are getting longer. So the need for the super-spec will come into play more through the development in those fields.

Yes. I would just add, Sean, and of course, we've seen this as an opportunity for a long time and we've prefaced it by saying, when we see unconventionals, more horizontal wells internationally and when you get to the point where there's a need for more of a manufacturing type process then H&P has the rigs and the capacity and the solutions really, to deliver in that situation. So really -- that's really, I think, what has to happen is we've got to see those types of programs develop like what we've seen in Argentina, and I think that begins to open up the opportunities for us.

And we'll go next today to Brad Handler with Jefferies.

I guess I just have one question related to Argentina and it's more just if you can help us think about. Things aren't as good in Argentina as they were very recently, right? Inflation is clearly creeping up as a risk and the IMF, sounds like, it's got to get involved and whatever. How -- can you help us think about risks as it relates to your business? I think your contacts are all dollar-denominated, so that's good, but what about just labor destruction or other factors that we may have to think about if Argentina, unfortunately, goes the wrong way?

I'll start off, Brad. As it relates to the contracts, you're correct. The contracts are tied to the U.S. dollar. They're technically paid in pesos that can -- literally there's the same day in billing and payments, so we can covert right back to U.S. dollars. So from a revenue perspective, the U.S. dollar is the way to think about it. From an in-country cost perspective, we have a mix. We have several of our inputs, pieces of equipment, et cetera, will have some U.S. dollar denomination. We also have some component of ex-pat personnel, which are tied to the U.S. dollar. And then locally, costs and expenses are in the peso and offset each other. So that is kind of the high level. So in other words we have been pretty well shielded from the hyperinflationary position there at H&P and continue to look to keep that state. As it relates to the labor market, I'll let John comment.

Yes, Brad, we -- there are challenges at times with the labor unions in Argentina, but our experience in Vaca Muerta have been very positive, I think, particularly as compared to other areas that we've worked in Argentina in the further south. I think, in general, though, it kind of comes back to this general overarching theme that you've heard us come back to many, many times and that is working internationally has a whole another level of challenges and risks that we, at least up to this point in time, haven't faced in the U.S. It's one of the reasons why we've grown our fleet in the way that we have and made the investments that we've made in U.S. Land. And we haven't been able to grow as much internationally and it's because we haven't been able to get term contracts. You can't make the returns that you would really like to make because of the risk associated with it. So it's one of the those things that we've come to get used to. And yes, there's a lot of questions in Argentina. The upcoming election is -- obviously is one and we'll see how that turns out.

And this does conclude our Q&A session for today. I will turn the call back to John Lindsay for any closing remarks.

Okay. Well, thank you. I appreciate everyone's attendance today and being interested in H&P. Again, thanks to all of our employees that work hard every day to contribute to the H&P way, so thank you very much. Have a great day.

This does conclude today's program. Thank you for your participation. You may disconnect at any time.