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Helmerich and Payne Inc
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Good day, everyone, and welcome to today's Helmerich & Payne's Third Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. Later you'll have the opportunity to ask questions during the question-and-answer session. Please note this call is being recorded. I'll be standing by, if you should need any assistance.
It is now my pleasure to turn the conference over to Mr. Dave Wilson, Director of Investor Relations. Please go ahead.
Thank you, Wendy, and welcome, everyone, to Helmerich & Payne's conference call and webcast corresponding to the third quarter of fiscal 2018. 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'll open the call for questions.
As usual and as defined by the U.S. Private Securities Litigation Reform Act of 1995, all forward-looking statements made during this call are based on current expectations and assumptions that are subject to risks and uncertainties as discussed in the company's Annual Report on Form 10-K and quarterly reports on Form 10-Q. The company's actual results may differ materially from those indicated or implied by such forward-looking statements.
We also will be making reference to certain non-GAAP financial measures such as segment operating income and operating statistics. You may find the GAAP reconciliation and comments and calculations in yesterday's press release.
With that said, I'll now turn the call over to John Lindsay.
Good morning, everyone. Thank you for joining us on the call this morning. I'm going to begin by welcoming Mark Smith to the H&P team. Today is, of course, his first conference call with H&P. So glad to have you onboard with us, Mark. And again, good morning, everyone.
The company achieved several operational highlights during the quarter in the midst of a supercharged market where we continue to see robust demand for additional super-spec FlexRigs and our industry-leading technology. The increase in dayrates speaks to the high value our teams are providing and the strong partnerships we continue to nurture with our customers.
There are four areas of discussion I want to focus on this morning. First is the pricing and market share success we've delivered. Our U.S. Land operations benefited from higher activity and pricing as we continue to capitalize on our superior position in the sold-out super-spec market. H&P's leading-edge spot pricing is approaching the mid $20,000 per day range and average stock pricing is nearing $22,000 per day.
In addition to our success in obtaining better dayrates in commercial terms, we have also been able to improve market share in both the overall rig count as well as the super-spec fleet where we believe we have approximately 42% market share today. Further, we have leading market share position in the top three most active basins in the U. S.
Looking forward and provided that the strong oil price environment persists, we believe we will maintain pricing power and would expect the average spot market pricing to close the gap with today's leading-edge pricing over the next few quarters. I'd like to take this time to give our account managers and our sales and marketing group a lot of credit for their efforts to improve pricing to better reflect the value proposition we provide customers. I want to thank each of you for your efforts.
My second area of focus this morning pertains to the super-spec outlook and the metrics that drives super-spec demand. We maintained the leadership position in the super-spec rig market. Throughout the first nine months of the fiscal year, we upgraded 38 FlexRigs to super-spec capacity, bringing the total to 191 super-spec FlexRigs in our U.S. Land fleet.
As I mentioned earlier, the market is tight for FlexRigs and we expect this trend to endure as more customers embrace the technologies that drive unconventional drilling economics. On the drilling side, the primary markers for well complexity in U.S. Land are the increased lateral length, multi-well pad drilling and tighter well spacing. The average lateral length today is slightly over 8,000 feet, which is a significant increase from 6,000 feet that we had in 2015.
The primary attraction of a super-spec rig are the benefits of the incremental performance capability it delivers and the positive impact that has on the cost and, therefore, the risk and economics of a project. A few of the performance factors include faster rig move time, mud pumping capacity, multi-well pad capability, setback capacity and just an overall more efficient drilling operation.
We plan to continue our current upgrade cadence, which has averaged 12 rigs per quarter. If the demand from customers remain strong enough to command a two-year term contract in mid 20s dayrates, we will maintain the cadence.
In addition to the Flex3s we have available for upgrade, we have also identified seven FlexRig4s that we can convert to FlexRig3 walking rigs with super-spec capacity at a similar investment to the FlexRig3 upgrade.
With all the super-spec FlexRig getting all the headlines, it's our people leveraging the technology and their attention to safety, customer service, process excellence and delivering value that differentiates the H&P brand from the others.
My third point today is on the strong market demand, but I also want to give you our perspective on the Permian transportation bottleneck that is causing concern in the industry. Oil prices have hovered in the mid-60s to low-70s during the quarter and we believe most E&P budgets in the current year reflect a $50 to $55 per barrel oil price. Therefore, we are optimistic that E&P spending in 2018 is not yet fully reflecting the potential increase in CapEx and rig count in 2019 and we are bullish on the prospects for continued momentum into the new year.
The Permian issue has clouded the near-term outlook somewhat, but H&P continues to experience strong demand and we are adding rigs accordingly. Our rig count in this basin today is at 114 rigs, up from 107 rigs at the end of the second fiscal quarter. And we continue to have customers committing to super-spec FlexRigs in calendar Q4 and Q1, in addition to a few standard service FlexRig3s and FlexRig4s. With the commitments we have in hand today, we could reach roughly 120 rigs in the Permian by fiscal year-end.
So we hear all of the looming concerns surrounding takeaway capacity in the Permian. Though we are seeing indications of a pullback and the strong oil price environment that we've experienced of late, we're also seeing improved rig activity in other plays as well.
So another part of the growth story for H&P is our strong footprint in each of these top four activity basins. We currently have 24% market share of active rigs in the Permian, 37% in the Eagle Ford, 25% in the SCOOP/STACK play and 14% in the Bakken.
We believe that budget dollars could shift from the Permian to other basins, if needed, with a plus $55 oil price. Higher crude oil prices have also positively impacted our International and Offshore businesses as additional rigs were contracted during the June quarter. We are actively pursuing opportunities in these segments and will hopefully begin to see additional growth in fiscal 2019, especially in Argentina with its unconventional resource plays.
My final point is an update on our technology subsidiaries and our continued advances in drilling automation. We are gratified to see increasing numbers of customers realizing the long-term value proposition and the services provided by our new technology subsidiaries – MOTIVE Drilling Technologies and Magnetic Variation Services, also known as MagVAR.
Driven by industry trends toward longer laterals and tighter well spacing, both companies are growing activity at impressive rates on both H&P FlexRigs and on other contractor rigs. These technologies are leading-edge, create additional opportunities to utilize our digital FlexRig platform and provide an important driver in the evolution of drilling automation.
As a compelling update to that evolution, we are currently delivering very promising results in our next stage of directional automation. Field trials are underway in the Permian Basin on several FlexRigs and it has successfully drilled multiple extended reach horizontal wells including all sections of the well, namely the vertical, the curve and lateral sections.
These drilling trials were accomplished autonomously over the majority of the drilling process of the well. Using proprietary algorithms enabled by combining our MOTIVE value-driven automation platform with our FlexRig digital control system, automated slides were accomplished with accuracy and performance that often exceeded those executed by the most experienced human directional drillers.
As the directional drillers remain an important part of the rig operation, these tools are enhancing the quality of the wellbore. Using the autonomous car analogy, this would be similar to level three out of five levels, where there is still a driver but he's not required to touch the steering wheel except in rare occasions. More to come on this, but we are pleased with the progress in these trials.
MOTIVE and MagVAR continue to lead their respective market segments with MOTIVE actively steering over 500 horizontal wells and over 7 million feet of guided footage and MagVAR is active on over 240 rigs and continuing to grow its leadership position in the survey correction market.
Before turning the call over to Mark, we achieved another milestone in addition to drilling automation. In June, we activated our first multiple-activity FlexRig and you may have seen that on Instagram or Facebook. The new multi-FlexRig design is easily distinguished by the rig actually having two derricks, also maybe called a mast, but in general I think people will refer to them as derricks. This rig is the first of its kind in onshore U.S. and it's another good example of our family of solutions that H&P is capable of offering to customers.
This particular project is the result of H&P collaborating with a longtime customer in pursuit of creating additional value to their well programs. Our engineering group did a fantastic job in listening to the customer, working with the customer and delivering on the vision.
The new prototype rig design is a combination of a FlexRig5 and a FlexRig4, allowing the customer to perform multiple functions safely, efficiently and simultaneously. We've had several inquiries about the multi-FlexRig and we will be analyzing reliability and performance over the next few quarters.
And now I'll turn the call over to Mark Smith.
Thanks, John. Today I will review our fiscal third quarter's operating results, provide guidance for the remainder of the fiscal year and comment on our financial position.
Let's start with highlights for the recently completed third quarter. The company generated quarterly revenues of $649 million versus $577 million in the previous quarter. The increase in revenue is primarily due to the increase in revenue days and average quarterly revenue per day in the U.S. Land segment. Operating costs correspondingly increased to $445 million for the third quarter versus $386 million for the previous Q.
General and administrative expenses totaled $52 million, higher than our prior guidance due primarily to additions to our employee counts and partially to nonrecurring professional fees.
Our income tax provision from continuing operations consists of discrete tax items that are approximately $9 million related to state and international jurisdictions where we operate.
Concluding this quarter's results, H&P incurred a diluted loss per share of $0.08 in the third quarter versus a loss of $0.12 in the previous quarter. Both quarters were adversely impacted by a $0.07 per share of selected items, as highlighted in our press release. Absent these items, the diluted loss per share for the quarter was $0.01 in Q3 versus a loss of $0.05 during the second fiscal quarter.
Now turning to our three segments, beginning with the U.S. Land segment. We exited the third fiscal quarter with 224 contracted rigs and had an increase of approximately 5% in the number of active rigs quarter-to-quarter. We continued to experience growth in activity from beginning to end of the quarter and expect a similar increase through the end of the fourth quarter of fiscal 2018. Since the last earnings call on April 26, our activity has increased by 11 rigs. The Permian once again led the way with a seven rig increase.
As John mentioned, H&P has leading market share in the top three U.S. basins – the Permian, the Eagle Ford and the SCOOP/STACK. Our activity levels in each are at 114, 37 and 33 rigs contracted, respectively. We have 43 idle FlexRigs in the Permian, 18 of which are upgradable to super-spec; 25 idle FlexRigs in the Eagle Ford, 21 of which are upgradable to super-spec; as well as 2 idle FlexRigs in the SCOOP/STACK, both of which are upgradable.
The favorable market conditions that John mentioned continue to allow pricing improvements. Excluding the early termination revenue, our average rig revenue per day increased to $23,400 for the quarter. The average rig expense per day increased to $14,934 due in part to the Permian wage increase mentioned in the previous quarter's earnings call and in part to higher pass-through costs and other one-time costs.
Now looking ahead at the fourth quarter of fiscal 2018 for U.S. Land, we expect a sequential increase of approximately 6% in the quarterly number of revenue days, representing an average rig count of approximately 230 rigs. Compared to the third quarter at $23,400 per day, we expect the adjusted average rig revenue per day to increase to approximately $24,000. The expected increase is driven by market dynamics as customers continue to contract for super-spec FlexRigs across numerous basins due to the differentiated value they deliver to our customers. We will, however, continue to see the rollover of legacy new-build term contracts partially offset these increases.
The average rig expense per day is expected to decrease to approximately $14,700, absent one-time costs that affected the current quarter and as our idle rig count continues to decline. The normalized average rig expense per day directly related to rigs working in the U.S. Land segment is approximately $13,700, an increase of $200 per day sequentially due in part to higher auxiliary expenses. This per day estimate excludes the impact of expenses directly related to inactive rigs and the upfront reactivation expenses related to rigs that have been idle for a significant amount of time.
Historically, the company has stated its normalized average rig expense per day as $13,000 and now that level is $13,700. It's very important to keep in perspective that the recent increase in this normalized operating cost is mostly margin neutral as it is comprised of costs that are passed through to the customer. Part of the higher normalized cost relates to the Permian wage increase, with most of the remaining relating to some of the auxiliary services our customers demand.
We had an average of 131 active rigs under term contracts during the third quarter. Today, 129 of our 227 contracted rigs are under term contracts and all but 26 were priced in the post downturn market. We expect to have an average of 126 rigs under term contract in the fiscal fourth quarter, earning an average margin of $10,500 per day. For the seven new rigs we already have under term contract in 2019, we expect to average margins to expand to approximately $11,500. For the 14 rigs under term contract in fiscal 2020, the associated margin is $14,100.
Turning to our Offshore Operations segment, we reactivated one platform rig during the third quarter, resulting into six rigs contracted at the end of the third quarter. The average rig margin per day decreased sequentially, which was driven primarily by higher than expected rig startup cost to put that sixth rig back to work.
As we look forward to the fourth quarter of fiscal 2018 for the Offshore segment, we currently have six of our eight offshore rigs active. While there are opportunities to put additional rigs to work over time, nothing is imminent at this time. The average rig margin per day is expected to increase to a more normalized level of approximately $13,000 during the fourth quarter versus the last few quarters.
Regarding our International Land segment, as expected, the number of quarterly revenue days increased sequentially in the third quarter by approximately 15% due to three rigs reactivating in the Colombian market. We expect to end the fourth quarter with 19 to 20 active rigs in this segment, including 15 in Argentina, 3 to 4 in Colombia and 1 in Bahrain. We believe our market share in the overall Argentina rig market is about 20% while our share of the unconventional drilling market there is much higher. Given our relative scale and strong footprint, we believe we are positioned to grow as the Argentina unconventional market continues to develop.
Now let me look forward on corporate items for the remainder of this fiscal year. Our CapEx investment strategy this fiscal year has resulted in increasing market share for H&P in the Permian and other U. S. basins. Our FlexRig upgrades enhance the capabilities and useful lives of our existing fleet and enable us to provide value and meet customer needs today and into the future.
Given H&P's increased level of contracted rigs and the opportunities we are seeing to upgrade FlexRigs to super-spec capacity, we have adjusted our capital expenditure estimate to be at the high end of our previous range of guidance at approximately $450 million. Note that approximately 40% of standard CapEx – of the estimated CapEx range is attributable to maintenance CapEx, including tubulars.
Depreciation is still expected to be approximately $550 million, plus an additional $35 million or so in abandonments that are primarily related to super-spec FlexRig upgrades. The total depreciation estimate is $585 million for the full fiscal 2018 year.
Our general and administrative expenses for the full year are expected to be approximately $200 million. We have significantly enhanced our technology and innovation capabilities with the acquisitions of MOTIVE and MagVAR. In addition, as John has mentioned in prior quarters, we have added expanded capabilities in Tulsa to support our growing rig fleets with the goal to reduce certain field expenses. Also note that when we built our original fiscal 2018 budget, our U.S. Land rig count was 190. And today it is 227 operating rigs and growing.
As we mentioned last quarter, the statutory U.S. federal income tax rate for our September 30, 2018 fiscal year-end is approximately 25%. In addition to the U.S. statutory rate we are expecting incremental state and foreign income taxes to impact our tax provisions.
Now looking at our financial position. Helmerich & Payne had cash on hand of approximately $306 million at June 30, 2018 and short-term investments of $44 million. Including our revolving credit facility availability, our liquidity was approximately $611 million. Our debt-to-capital at quarter-end was 10%, a best-in-class measurement amongst our peer group. We have no debt maturity until 2025.
Our opportunistic reinvestment in our FlexRig fleet serves to strengthen our asset base and position H&P for the continuing onshore and conventional up-cycle. Our goal is to increase market share while effectively utilizing our existing FlexRig asset base. Our balance sheet strength, liquidity level and term contract backlog provide H&P the flexibility to pursue that goal while simultaneously returning capital to shareholders through our very longstanding dividend. Therefore, our free cash flow generated from operations continues to be reinvested in the fleet and return to shareholders.
As we pursue our market share growth goal through existing FlexRig reactivations and upgrades that remain available to us, we will consume a portion of our cash on hand. We do not expect to have to utilize our revolving credit facility availability. Looking ahead in the planning horizon, this investment in our fleet coupled with the disciplined and centralized cost focus will yield expanding positive free cash flows.
That concludes our prepared comments for the third fiscal quarter. Now let me turn the call over to Wendy for questions.
And we will take our first question from Tommy Moll with Stephens, Inc. Please go ahead. Your line is open.
Good morning. Thanks for taking my questions.
Good morning, Tommy.
I wanted to follow up on your comment about the Flex4 upgrade potential. I think you called out seven Flex4s where you think there's a potential upgrade to super-spec with the capital investments and were in line with the Flex3 walking upgrades. Am I right that that's about the $8 million range under the two-year term and mid-20s provide efficient returns or with the basic parameters that the contract need to be more attractive?
Yeah. Tommy, that is, so it's a Flex4 that we're doing a conversion on. So we're converting the Flex4 to the Flex3 walking. And yes, that is ballpark $8 million. And our expectation would be that it's in line with how we've described these upgrades two-year term contracts and mid-20s pricing.
Great. And just as a follow-up, have you peeked at the remainder of the Flex4 fleet to think about how deep you could go in there for upgrades? Or was it just at first look you found seven, but could potentially go back later?
Yeah. I think we've kind of talked about this over time. We haven't spent a whole lot of time on this just simply because we haven't had the time and we've had, of course, all of the upgrades on the FlexRig3s. So, our engineering group did some work, came up with these seven. We haven't done any additional work on the others. There'll be more to come on that, but it's kind of hard to say what the timeline would be.
Fair enough. And then shifting to technology, your advantage there goes back a number of years with the original FlexRig capability. More recently, we've seen it with the acquisition of MOTIVE of MagVAR, which suggests now the curve is more in terms of data and automation. Can you update us on how those integrations are going? What anecdotes you're getting from customers? And do you see other kinds of technological capabilities you might want to add to the portfolio? Thanks.
You're welcome. Sure. The integration of both companies has been really good. It's been a strong integration. Really similar cultures, which is important I think to success. I think what really speaks to the success is, if you look at the rig count growth, MOTIVE is I think around 30 or so rigs and I think when we made the acquisition, we were probably at 10 or so.
So there is some adoption. As you know, in our business, technology adoption can be somewhat slow. But it's got some real upside, it's got some real opportunities. You heard us talk about wellbore quality and wellbore placement being more and more important. So MOTIVE plays a big role in that, as does MagVAR. And again, MagVAR has over 240 rigs that they're working on today. I want to say H&P is about a third of both the companies in terms of FlexRigs. So that's important.
And then to kind of highlight the automation piece, MOTIVE is playing a large role in that in working with the H&P team and getting, like I said, to kind of that level three automation, so we're excited about that as well. So I think both acquisitions have been strategic. Are there other opportunities out there? Obviously, we're always keeping our eyes open looking for other opportunities. The data side is an important side of the equation as well. So, yeah, we're feeling pretty good about it.
Great. Thank you. That's all for me.
Take care.
And we'll take our next question from Brad Handler with Jefferies. Please go ahead.
Thanks. Good morning, guys.
Good morning, Brad.
Good morning.
I guess, let's talk some numbers, please. So, with 126 rigs contracted versus the 106 that you talked about in mid-May, can you tell us a little about the term on those 20 rigs and some color on the rates as they may have compared with contracts earlier in the year?
Yes, Brad.
Okay. I was afraid for a minute I got cut off.
The average term of those is really about a year, I would say. And our rates, as John had alluded to in his prepared comments, are approaching mid-20s.
Presumably I think we're supposed to believe that they were higher than contracts made through, say, the first calendar quarter or even in April or something? I mean, have we seen progression through the course of the year?
We have, Brad. I think Mark's reference to one year is the average that's on those 120. The most recent contracts we're entering into are between one year and two year. If there are upgrades, we're requiring two years. So that's obviously a factor. The most recent term contracts we're entering into are higher than the average for those non-new-build term contracts.
Got it. Okay, thank you. And then, I guess, I'm going to ask for your perspective on some of the industry and the upgrade opportunities to super-spec. I'm actually just coming off a call where we've heard about one of your competitors taking 1,000 horsepower rigs and putting a fair amount of capital, I guess, it was about $15 million apiece to upgrade four rigs to super-spec capability. How much are you hearing that around the industry? And has it changed your perspective? I think if we rewind to your recent comments, we were still talking about roughly 100 rigs that you thought could be upgraded fairly easily to super-spec. Is that number growing now? Again, I reference one example from today and your own example, of course, from the Flex4s. But is that number starting to grow? And if so, have you tabulated it?
Brad, I don't know that that number is growing that much. And the reason why is because in our calculation, if you're using the pure super-spec definition that we use, we think there's around 450 that are running today that have been upgraded. There's another 200 or so that we think can be upgraded. We have I think around or close to half of those, maybe it's 40% now, and I think half of those 200 are working. So I think the question still remains, outside of the H&P fleet, which of those rigs that fit kind of the description are actually going to be able to be upgraded at a reasonable price.
And then to the rest of your question is, well, what about the 1,000 horsepower. So it's interesting that some contractors are taking I think the strategy of looking at some of the lower-end horsepower rigs and upgrading them to a higher capacity. And then others, some of those 1,500 horsepower rigs they may deem are just not economic to upgrade to put back into the marketplace. I'm not certain we have enough information right now. I still think – I think we've been pretty consistent in saying that the total upgradable fleet we thought was probably in the 600 to 700 range. In the pure kind of classic definition, like I said, is anywhere from 600 to 650 and then there's another 50 to 100 that are out there that I think are probably captured in the rigs that you're describing.
Got you. Got you. Okay.
Brad, I would just remind that the place we're in and the market here at Helmerich & Payne is a good place to be relative to the numbers you threw out. With essentially 75 FlexRig3s and the 7 FlexRig4 conversions John mentioned in his prepared comments, we have 82 that we can take to super-spec that cost us $8 million or less essentially depending on the type of multi-pad capability that we put on the vessel.
I understand that point, for sure, but thanks for pointing that out. Okay. Very good, guys. I'll turn it back. Thanks.
Thanks, Brad.
And we'll take our next question from Colin Davies with Bernstein. Please go ahead.
Thank you. Good morning.
Good morning, Colin.
Good morning. Just I'd like to talk a little bit more about this Permian issue. And obviously, it's very encouraging in the prepared remarks that you've got line of sight to increased activity in the next quarter and beyond as well. But as we think about this fundamentally temporary phenomenon in the play with the takeaway capacity issue, can you give some color as to sort of where does your line of sight or confidence in that outlook start to wither a little bit? I mean, are we talking middle of next year or beginning of next year or the end of next year?
Colin, I don't know that we have enough clear insight and to go out that far out into the future and which is why we try to keep our prepared remarks to the rest of this quarter, the rest of this calendar year, I even mentioned I think Q1 of 2019 and primarily the reason with Q1 – calendar Q1 of 2019. And the primary reason I mentioned that is because we have some customers that are committing to and contracting rigs, super-spec rigs that are taking upgrades in that first calendar quarter and in the Permian Basin.
So we haven't seen any behavior change from customers. Again, we think that today's activity is a function of a $50 to $55 oil price, not a $65 to low $70 oil price that we've actually been experiencing. So our customers have been very disciplined with their capital. They haven't adjusted their budgets upward. We think that there's a possibility that budgets could be adjusted upward and higher numbers of rigs working in 2019. How that all shakes out through the Permian bottleneck issue is really kind of hard to completely get your arms around, but really what we're speaking to are behaviors and commitments that customers are making.
That's very helpful. And just one follow-up, if I may. Perhaps related to that, when we think about the growth that you're starting to see around the super-spec demand, even within the Permian, can you give some color as to how much of that is, if you like, net growth and how much of it is displacement of perhaps rigs of non-super-spec category that those customers are now drilling, taking that programs and displacing with a super-spec rig?
I think it's probably a mix is probably the right answer. We do know that there are examples that will have a customer pick up a super-spec FlexRig with the intent of displacing a lower-performing rig. Sometimes that rig is an AC rig and sometimes that rig is an SCR rig. One thing to keep in mind, you may have heard us say before, I think there's still around 270 legacy rigs, SCR mechanical rigs that are drilling horizontal and directional wells today. When you start considering the lateral length trends, the well complexity trends, those older rigs are going to – I think it's going to be harder for them to continue to compete. So I think that the cycle remains – the upgrade cycle remains – I think that's going to continue to happen. But I do think it's a combination. I think both replacements and additional rigs are taking place.
That's very helpful. Is there any sense that that dynamic of demand displacement is higher in the Permian, given the Permian has just different maturity relative to some of the other basins?
I think there's some reasoning behind that. I don't have the facts to support it. But I think it does make sense because that basin has been in terms of years in the unconventional play, particularly the longer laterals, it's not as mature as, say, the Eagle Ford or the Bakken maybe, but I think there is potential there.
That's very helpful. Thank you. I'll turn it back.
All right, Colin. Thank you.
And we will take our next question from Kurt Hallead with RBC. Please go ahead.
Hey, good morning.
Good morning, Kurt.
Good morning.
Hey Mark. And welcome aboard, Mark.
Thank you. It's good to be here.
So, hey, John, obviously, I think you definitely peaked my interest in what you said about launching a dual-derrick land drilling rig. Obviously, the dual-derrick concept has been deployed on drillships primarily offshore. So it's kind of the first foray of that into the land drilling business. So maybe give us some context, John, if possible, to kind of get a sense as to what kind of adoption rate you might expect for the dual-derrick concept over time? And do you see it evolving potentially in the same way that the FlexRig evolved when Helmerich & Payne first launched that concept back in the early – in mid-2000s?
Kurt, I think it's very, very early in the game to try to really understand what kind of application it's going to have onshore. This is something that we've kind of talked about internal for a while. We had a customer that had a lot of interest in trying it and I think we kind of work together and help make that happen. I think there's still a lot of – again, the rig's just been out since mid-June, so there's still a lot of opportunity for learning. But when you start thinking about some of the advantages that – minimizing flat time, NPT, some of the economics and just some of the simultaneous operations that might be able to go on have some capability. But again, I think they're looking at as kind of multi-functionality, the rigs can work together, they can also work offline from one another.
So I think it is different than the Offshore model. There's probably some similarities, but I think there's also some additional capacity. Obviously, we're not limited by a footprint of the structure, of the ship, whether it's a drillship or whether it's a platform. We do have the ability to have those rigs work together and then also kind of independently. So it's got some features.
I think from an H&P perspective, it's a FlexRig5 and a FlexRig4. We obviously have the capability to do more of those – these types of rigs, these type of projects with the fleet that we have. But again, I think we're probably a couple of quarters in trying to figure out what that's going to look like. We thought it would make a lot of sense to get out and talk about it. Again, it hit Instagram and Facebook pretty hard, so we thought we'd at least get out there and talk about it a little bit.
Interesting. Interesting concept. Okay. That's great. So, I guess, my follow-up question would be along the lines of – outside the Permian, can you talk a little bit about what you're seeing in terms of potential rig demand? And I just wondered if you might be able to put that into context I think there's been some discussions that I've had with varying investors that say, okay, it's unlikely to see any increase or potential significant increase in drilling outside the Permian because E&P companies have pretty much bet the motherload on acreage in the Permian and don't have a whole lot to kind of go after outside the Permian. I just wondered if you could provide some perspective on that.
Yes, Kurt. Our rig count is up slightly in the Eagle Ford, a couple or two or three rigs. We got a couple rigs that went to work in SCOOP/STACK play. We've had some commitments in the Bakken, which are positive. Again, I think kind of the underlying theme here is that with budgets set with a $50 to $55 oil price environment and with budgets being reset towards the end of the year going into 2019. And if it is a $60 to $65 or $65 to $70 oil price environment outlook, I think you have to believe that you're going to see some additional activity in many of these basins that have oil production.
And again, the great news for H&P as part of the growth story is that we have rigs in those basins that are idle that can be upgraded to super-spec and then some that are idle that probably won't need to be upgraded to super-spec in some cases because that's part of what we see today. I think we still have 26 or 27 FlexRigs that are running today that aren't upgraded to super-spec and we have I think eight Flex4s that are running that, again, in a stronger oil price environment probably find their way into finding additional work. Because, again, if you think about that Flex4 rig competing against an SCR or a mechanical rig drilling a horizontal well, I like our chances to be able to compete in that sort of environment.
Got it. And if I just may close out with one additional follow-up on the operating cost side. I know, Mark, you went through and gave us a revision on kind of the normalizing operating cost around $13,700 per day. I just wondered if you guys can put that into a context as it relates to at what level or what number of working rigs would it take to get that operating cost to that normalized level? How should we think about that?
The $13,700 normalized is, I mean, we're there. The incremental cost or essentially the reactivation costs and the idling cost approximately $1,000 that get you from $13,700 to $14,700. So we think the $13,700 is a number where we will hold.
So that would assume no additional upgrades, you'd be kind of maxed out on what you could provide to the market. I guess, that's what I was trying to – I was just trying to kind of get that into – trying to figure out that concept. Is that right?
I don't know if I'm following that last part of your question, Kurt.
That's all right. That's all right. I'll follow up offline. That's fine.
Thank you.
I appreciate it. Thanks. Thank you, Mark.
Appreciate the call.
Thanks, Kurt.
And we'll go next to John Daniel with Simmons & Company. Please go ahead.
Guys, just a couple hopefully easier ones for me. John, can you just provide a bit more color on customer demand and ideally share with us what you perceive to be the mindset of the sort of customer sub-segments, private versus small cap versus large cap E&P players? I mean, I know it's a generalization, but any color would be appreciated.
John, I don't know that I have a clear differentiating view between one versus the other. I think clearly what the larger companies, the public companies, it's clear that they're having a high level of capital discipline and they've made their budgets, they're sticking to their budgets, they're being very thoughtful in their decisions and what they're doing.
I think what the smaller companies and you probably heard me say this over time is that one of the only good things about the downturn is it gives us an opportunity to work for customers that we previously never would have had an opportunity work for. So I think we have 70 customers today. We didn't have 70 customers when we had 300 rigs running in 2014. So we've expanded our customer base and we do have exposure. But I don't really have a sense for really anything other than that. Is there anything, Dave or Mark you can think of?
No, I think the new rigs that we've been putting to work this last quarter and some of the commitments we have, as John had alluded to, into the next couple of quarters, we still see a mix across various types of E&P clients. So no discernible differences I would say between the type of client.
Okay. Because there have been some speculation that as you get in the back half of the year, those that would be more likely to potentially release rigs would be the smaller, less well-capitalized customers, okay. Nice to know. It sounds like you're not seeing anything that would suggest that that basket of clientele is looking to drop rigs?
I sure don't think so. I mean, the fact of the matter is there's always a certain level of churn in the rig count. I think the reason that customers wouldn't begin to release rigs at the end of the year, particularly if they have a high performing rig and a super-spec rig is if you're going to then get back into the business in the first quarter of 2019. Now you're going to be in line and you're going to have to go contract a rig and then you're more than likely going to have to pull it out of STACK and you're going to have to go through the whole upgrade process.
So I find it a little challenging to consider that they would release a rig thinking that they're just going to turn around, pick it back up in a quarter or two because it just isn't going to – I don't believe it's going to work out that way. So I think most of the operators know that. I think if they've got a good rig, they've got a quality rig, I think they're going to hang on to it. I'd be surprised that they would release it. Now if it's not a high performing rig then you might as well roll the dice and see what you come back up with later.
Okay. And then just – thank you for that – last one for me and this is probably an off-the-wall comment or question. But do you guys still maintain operations in California? And if so, what's the outlook for that market?
John, we don't. We exited I think in 2015 – 2015 or 2016. We worked there for many, many years. We worked offshore. We had platform rigs offshore. We had a big land presence there, but it just – the environment, it's very, very challenging to work in from a personnel perspective. We have great people in California. As a matter of fact, when you go to our West Texas operation and you visit rigs, it's highly likely you're going to run into some of our employees that are still living in California and working for us in West Texas. They work on two and two schedule – two week on, two week off. Great employees, very, very good workforce. But it's not very business friendly, at least it wasn't friendly for the land contractors in California. So I really can't speak to what's going on out there.
Fair enough. I probably should have remembered, but forgot. Thank you, guys.
No, no problem. Thanks, John.
And we'll take our next question from Taylor Zurcher with Tudor, Pickering & Holt. Please go ahead.
Hey, guys. Thanks for squeezing me in.
Sure.
John, in the period from June 30 to today, your contracted rig count in U.S. Land has obviously moved higher, but it seems like there's been a slight mix shift from term contracted rigs, some of those rolling to spot. And so just curious if you think that's indicative of some customers trying to preserve some flexibility into year-end or perhaps just noise in the numbers or some underlying dynamic at play?
In terms of having more rigs under term contract?
In terms of having less rigs under term contract. If I look at June 30, you had 136 rigs and today, looks like 129. So just curious if that's just some noise or if you...?
Yeah, it's just a little bit of noise. I'm sure it mostly had to do with just a large number of rigs that rolled off during the quarter and we just didn't enter into as many rigs that were rolling off as we were entering into. That's really what the function was. So I think we went from 60% of our rigs term to 55% or 56%. I mean, it's very, very small change.
And some of those rolling off, I'll just add, were some of our older contracts that were actually entered into pre the downturn.
Okay. That's helpful. That makes sense. And then last question for me is on International. I mean, you've obviously added a few rigs over the past several months. As we look forward, you still have some idle rig capacity in Latin America. And specific to Argentina, just curious, I mean, it seems like that will be a hotspot moving forward or continue to be a hotspot moving forward, how you're viewing that market moving forward? And if we might see you guys move rigs from other regions in Latin America potentially to Argentina or even from the U.S.?
Well, I think there's an opportunity for us to continue to put rigs back to work in Colombia as well as in Argentina. And I think it is. I think there's a high likelihood or at least our hope would be is that we can continue to build on our strong market share in Argentina. We're in a great position there. We've got a nice customer base with YPF and other IOCs and NOCs there and hopefully we'll have an opportunity to do that. We have Flex3s here in the U.S. that we can move down there, both standard Flex3s as well as the opportunity to upgrade to super-spec, which I think that's what we're going to see. I think we're going to see more of a super-spec type offering required in Argentina because the laterals are starting to begin to trend longer. You're going to have a lot of the same opportunities that we've seen here in the U.S. So that would be our expectation. I think in our comments we had talked about 2019. As you know, if you pulled the trigger today, you're still going to – you're probably six month out before you can get the first rig in the country.
Got it. Thanks, guys. Appreciate it.
Okay. Thank you.
And we'll go next to Sean Meakim with JP Morgan. Please go ahead.
Thank you.
Hi Sean.
John, I wanted to ask about super-spec rigs either upgrades or those that can roll off contract. Just at this point, can you talk about your appetite for greater term versus higher rates as you're signing incremental contracts? And how you view your customers in terms of how they value that same trade off in terms of you're looking for lower price versus the optionality of shorter term? Just how do you characterize both sides of the table?
Well, I think we've got a balanced approach. I mean, we've talked about on the last call – last couple of calls, I guess, that we're in a position where as kind of the swing producer in the super-spec, we don't want to overbuild it, if at all possible, so we want to make certain the customer actually needs a super-spec and not just wants a super-spec and actually that's what we're seeing. We have high levels of demand. We also have high levels of usage. The customers that have super-spec are – 85% to 90% of the wells they're drilling are super-spec requirement type wells. So that's a good thing. So, at this stage of the cycle, we think two years and the mid-20s is a great place to be. And I think that would be our pricing model. For right now, that's our strategy right now. We're really not in a position to share anything past that. But I think that's a good place to be.
And how about customers?
In terms of their desire for?
Yeah, the similar tradeoff on their side, yes?
Yeah. I think most of the customers we're working for have multiple rigs running and they have their rigs staggered on term. And so I think it's a good balance on their part as well. The fact of the matter for us is, is that we're not going to put a super-spec rig out without a two-year term contract and attractive pricing. And if they need that sort of a rig and capability, they're obviously willing to pay that.
I think maybe another part of your question is they're thinking about this longer term, I don't get any feel that, oh my gosh, I'm really concerned if I got to lock into a two-year term contract. They've got a pretty long horizon. What they wouldn't want to do is, of course, lock every rig in their fleet up on two years. But to have a mix I don't think is not problematic at all.
Understood. That makes a lot of sense. Just, obviously, you've your hands full in the U.S. right now, but the International Land cycle maybe just getting some momentum here. We just discussed Argentina a little bit. But thinking about the rest of the world, is there appetite for you to at some point really scale up your International fleet or any markets that are – you think are particularly attractive to target in the next cycle here?
Well, you followed us a long time, you know we have the desire – we have the desire, we have the capability, we have the balance sheet to do it. We have skill sets to do it. It's just finding those right markets where you can get a reasonable rate of return for the capital that you are investing. And then also I think it's important when you're investing the kind of money that some of these projects require is that you do get a firm term take-or-pay type contract. Sometimes that's problematic internationally.
If we can get that then I think there is a high likelihood that H&P grows. That's why I think Argentina is probably the most logical place right now. I do think there's some opportunities in the near future in the Middle East. But again, I think those are 2019, 2020 type opportunities. We've got a long view on it. We've been working on this for a long time and want to continue to exploit those opportunities. But the fact of the matter is that the best area to invest your capital from a drilling contractor perspective for the last 10 years has been in the U.S. market and it's still a good place right now. And like you say, hopefully, there's opportunities internationally as well.
No doubt. That's very helpful. Thanks, John.
Thanks, Sean.
And this will conclude today's Q&A. I'll hand it back to our presenters for any closing remarks.
Okay, Wendy, thank you. So thanks, again, to all of you for participating on this third quarter earnings call. I'm going to close by thanking our folks for everything they do for the company, high levels of service attitude and this continued drive in pursuit of providing value for customers. Those consistent behaviors and the drive to satisfy the customer is a key component of what makes us the leader in the industry. I want to thank all of them and again thank you for participating today. Have a good day.
This does conclude today's call. Thank you again for your participation. You may disconnect.