Helmerich & Payne, Inc.
Q3 2017 Earnings Call Transcript

Published: 27 Jul 2017

[Operator:]

Good day, everyone, and welcome to today's Helmerich & Payne's Third Fiscal Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, you will have the opportunity to ask questions during the question-and-answer session. Please note, this call may be recorded. I'll be standing by if you should need any assistance. It is now my pleasure to turn the conference over to Mr. David Hardie, Manager of Investor Relations.

[David Hardie:]

Thank you, Leo. And welcome everyone to Helmerich & Payne's conference call and webcast corresponding to the third quarter of fiscal 2017. With us today are John Lindsay, President and CEO; and Juan Pablo Tardio, Vice President and CFO. John and Juan Pablo will be sharing some comments with us, after which we will 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 will also be making reference to certain non-GAAP financial measures such as segment operating income and operating statistics. You may find the GAAP reconciliation comments and calculations in today's press release. I'll now turn the call over to John.

[John W. Lindsay:]

Thank you, Dave. Good morning, everyone, and thank you again for joining us on our third fiscal quarter earnings call. We are confident about the opportunities ahead for the company, yet mindful that perennial uncertainty surrounding oil prices remains a threat to growth and drilling demand going forward. All things considered, we are pleased with the progress made during the quarter and we continue to reap the benefits of our integrated business models and the competencies the company has developed over a decade of designing, building, and now upgrading AC drive FlexRigs. Additional demand for super-spec FlexRigs remains in spite of the negative oil price action experienced this quarter. H&P is responding with upgrades to our existing AC fleet, as we are perhaps the only contractor with the right AC rig fleet capacity to grow substantially without requiring a large investment in new rigs. Despite choppiness in the market created by oil prices, H&P is successfully growing market share and continuing to build its brand. Our people remain the driving force of our success and the company continues to place extensive focus on organizational effectiveness and equipping all of our employees to deliver excellence for the customer. Technology will continue to play a pivotal role in the company's future success with analytics, big data and machine learning being significant areas of opportunity for the industry. On June 2, 2017, the company closed on the acquisition of MOTIVE Drilling Technologies. MOTIVE has developed a Bit Guidance System that utilizes cognitive computing to improve directional drilling, decision automation and optimization. MOTIVE is a technology company with 14 U.S. patents issued, and has been leveraging and refining these technologies commercially on the rig floor for several years using lessons learned from other industrial and military applications. MOTIVE is a leader in this space and to-date their system has been used to drill over 3 million feet of horizontal hole across all of the major U.S. shale plays and in Canada. MOTIVE technology is important, because there's a wide variance in directional drilling performance. Directional drillers are struggling to keep pace with increased drilling speeds, while delivering the accuracy required to place a wellbore in the desired sweet spot to maximize production. Training and the standardization of directional drilling approaches to complex problems is required to meet this challenge, particularly as horizontal wells grow in lateral length and complexity. Technology, like the MOTIVE team has developed, is making predictable and repeatable well manufacturing a reality for complex, unconventional horizontal well programs. The Bit Guidance System isn't a downhole tool. It's a software solutions and, therefore, H&P isn't competing in the directional drilling business. Another advantage that we believe exists for MOTIVE's Bit Guidance System is that it was initially incubated within an oil and gas operator, aimed at solving problems from an E&P company perspective, rather than that of the service provider. We found this to be precisely aligned with the core purpose of our company. What's more? They have built a significant amount of flexibility into their approach to allow their Bit Guidance System to adjust to priorities that can be customized across customers and regions. MOTIVE technology has been shown to produce higher quality wellbores and, more accurately, placement of the bits and the target reservoirs; and as a result, enables more production for our customers. Aligned with H&P's lower total well cost value proposition, MOTIVE technology drives decisions according to total well economics. This is unique and ultimately what matters to the customer. MOTIVE will continue to be deployed on FlexRigs and non-H&P rigs with a variety of directional drillers and tool providers. H&P strives to be a leader in new technology, and we believe the future digital oil field will be fueled by technologies like MOTIVE. Strategic technology acquisitions like this add to our advanced rig fleet and sizable operating capacity, sharpen our service offering and enable the company to maintain its leadership position in the market. Our intention is to build on these and other strengths to successfully grow in the U.S. land market. We've maintained an industry-leading cadence for upgrades, which has allowed us to increase our active fleet by 98 rigs during the fiscal year, 86 of which were super-spec upgrades. During the fiscal year, our upgrade cadence for super-spec rigs averaged approximately 8 rigs per month and today we have a total of 140 super-spec rigs in the U.S. land fleet. With customer-sponsored contracts, we are continuing to upgrade standard Flex3s with skid systems, including the 7,500 psi mud systems, third mud pump, fourth engine and setback increase where needed. Recall that we also built a prototype Flex3 with walking capability earlier this year. That rig has been active since May and has performed like we would expect our best-in-class Flex3s to perform. We are planning to equip at least four additional Flex3 rigs with walking systems and three are already committed to customers. The investment to add the walking system, including the new substructure design and other features, is approximately $5 million with a total upgrade investment between $7 million to $8 million. These upgrade investments include 7,500 psi mud system, a third mud pump, fourth engine and a higher horsepower top drive. Let me add some additional clarity here. All of the Flex3s we used for walking rigs were existing base design Flex3s, which did not have any skid system or other upgrades included. Our Flex3s with skid systems remain in very high demand, with approximately 100 contracted today, and those units are essentially at full utilization, and we continue to have demand for those systems. Having a uniform fleet of FlexRig3s, FlexRig4s and Flex5s enables us to provide a family of solutions for our customer, a fleet design to adapt to the future technology needs in the market and the capacity to deliver the right rig for their project. Before I hand the call over to Juan Pablo it's worthy of mentioning again that the efforts undertaken over the past couple of years to enhance organizational effectiveness are paying significant dividends. We've demonstrated the ability to achieve operational scalability, maintain a strong balance sheet and enhance a healthy environment throughout the organization. This is particularly apparent in our ability to respond to demand and add value to the customer. We had an opportunity to witness the value proposition firsthand last week when the leadership team and I made one of our quarterly rig visits. We visited several FlexRig3s, FlexRig4s, and FlexRig5s. All were working in the Colorado operation and they were all in world-class condition. Our customers were not only pleased with the rigs, but also with the morale, the service attitude and the performance of our people. This was another reminder, an example, that without the effort of our people, the great field results we have achieved during this fiscal year wouldn't have been possible. And I'll now turn the call over to Juan Pablo.

[Juan Pablo Tardio:]

Thank you, John, and good morning, everyone. I will expand on some of the announced information on each of our three drilling segments, followed by some comments on corporate-level details. On our U.S. Land Drilling segment, first let me highlight some of the details related to our growth in activity during the last three months. Since the last earnings call on April 27, 2017, we have put 17 FlexRigs back to work. The Permian led the way with 10 rigs, followed by two each in the Niobrara and SCOOP and STACK plays, and one each in the Eagle Ford, Piceance and Utica. From a FlexRig model perspective, 16 of the 17 were FlexRig3s and one was a FlexRig4. Of these 17 rigs, 9 had super-spec-level upgrades. We have also added seven new customers since the last call as a result of the performance our folks are delivering. Our three most active basins today are the Permian, the SCOOP and STACK play, and the Eagle Ford. The Permian remains our most active operation with 91 rigs contracted, compared to 85 rigs during the 2014 peak. We have 45 idle FlexRigs in the area, 26 of which have 1,500-horsepower drawworks rating. We're very pleased with our leading position in the Permian and expect to have additional opportunities to grow our active fleet in this area. In the SCOOP and STACK and Eagle Ford today, we have 31 and 26 rigs contracted, coming off a low of 15 and 16 contracted rigs, respectively. As for the overall U.S. Land segment results corresponding to the third fiscal quarter, we exited the period with 190 contracted rigs and had an increase of approximately 26% in total quarterly revenue days. The increasing proportion of rigs priced on the recent market conditions drove a 2% decline in adjusted average rig revenue per day to $21,676 in the quarter. As expected, the average rig expense per day decreased by about 9% to $14,256, mostly driven by a lower number of activated rigs generating upfront expenses as compared to the prior quarter. Looking ahead at the fourth quarter of fiscal 2017, we expect a sequential increase of 3% to 5% in quarterly revenue days. Given the slowdown in activity driven by lower commodity prices, however, it would not be surprising to see our quarter exit activity level be flat to down, as compared to our activity level of 190 rigs at the beginning of the quarter. Keep in mind that even in a flat rig count environment, it is normal to have some rigs released while others go back to work, depending on several factors, including the type of rig required and the rig site location. Given the increasing proportion of active rigs priced under recent market conditions, we expect the adjusted average rig revenue per day to decline to roughly $21,000 and perhaps slightly over that level. We do expect the average spot pricing level for FlexRigs to continue to increase during the quarter. We continue to deliver great value to our customers with our differentiated offering. Helping the customer to lower their total well cost is at the heart of H&P's value proposition, where savings can readily be achieved through drilling productivity gains and performance and reliability, as well as through a higher quality wellbore. The average rig expense per day level is expected to significantly decrease to roughly $13,700, as rig startup expenses sequentially have a much lower level of impact on the total average during the fourth fiscal quarter. Expenses corresponding to our remaining stacked AC drive FlexRigs represent approximately 3% to 4% of the mentioned average rig expense estimate of $13,700 per day. Another important consideration is that about half of our 189 contracted rigs today are under term contracts. And roughly half of those rigs under term contracts were priced during strong markets before the 2014 downturn. The remaining rigs under term contract, approximately 50, were priced during the downturn and have a remaining average duration of less than one year. As a result, the expected average rig margin per day for all of our rigs already under term contracts in this segment during the fourth quarter is roughly $11,500. Given the changing mix of term contracts that are currently in the backlog, the expected annual rig margin per day averages for fiscal 2018, fiscal 2019 and fiscal 2020 corresponding to these term contracts are roughly $13,000, $14,500 and $15,500 respectively. No early termination notices for rigs in this segment have been received since last summer. But given prior notifications, we expect to generate approximately $5 million during the fourth fiscal quarter and approximately $15 million during several quarters thereafter in early termination revenues. Let me now transition to our offshore operations. The number of quarterly revenue days decreased by approximately 8% and we exited the third fiscal quarter with six contracted rigs. We expected one of the six rigs to stack during the third quarter, but the rig is now scheduled to demobilize during the fourth fiscal quarter. The average rig margin per day increased sequentially by about 6% to $11,503. Management contracts contributed approximately $4 million to operating income. As we look at the fourth quarter of fiscal 2017, quarterly revenue days are expected to decrease by approximately 10%, exiting the quarter with five contracted rigs, one of which is expected to remain under standby-type day rate. Average rig margin per day is expected to increase to approximately $12,500. Moving on to our international land operations. Excluding retroactive adjustments related to the impact of the previously announced withdrawal by a customer of an early termination notice for five rigs under long-term contracts in Argentina, the average rig margin per day in the segment was $8,978 and the number of quarterly revenue days was 1,183 or an average of 13 contracted rigs, including the 10 rigs under term contracts in Argentina, 2 in Colombia and 1 in Bahrain. As we look at the fourth quarter of fiscal 2017, adjusted quarterly revenue days are expected to be essentially flat, with 13 contracted rigs during the quarter. The average rig margin per day is expected to be approximately $7,500. The sequential decline is primarily driven by the expiration of a long-term contract in Colombia, which is expected to continue to work at a lower day rate that reflects current market conditions. Let me now comment on corporate-level details. First, we were very pleased to be in position to pursue the acquisition of MOTIVE Drilling Technologies. As John mentioned, we believe that this small acquisition will allow us to create additional value for the customer, while at the same time take advantage of the scale of our FlexRig platform, which is the most capable and standardized fleet in the business. Given that MOTIVE's near-term impact to H&P's revenue and expenses is expected to be immaterial, MOTIVE's results will at this time not be reported as a separate segment. Second, given the strength of our balance sheet and backlog, and the company's flexibility to adjust capital expenditures as a function of market conditions, we remain well-positioned to sustain regular dividend levels during the foreseeable future. Although it may be choppy, we do expect a continued recovery in the business during the next few years. Nevertheless, if market conditions were to deteriorate toward an expectation of a prolonged down-cycle, we will do our best to describe potential changes to our approach to the dividend before implementing such changes. As mentioned in the past, it is unlikely that the company would issue additional debt with the sole purpose of sustaining or increasing current dividend levels. To be clear, that is not to say that the company would not take advantage of its balance sheet strength in the future, as it has in the past, to potentially issue additional debt for the purpose of pursuing attractive business opportunities. Lastly, the effective income tax rate on the estimated loss for the fourth quarter of fiscal 2017 is expected to be around 32%. As mentioned in the past, this expected rate is lower than the statutory rate, primarily due to foreign jurisdictions where tax benefits associated with operating losses remain uncertain. Let me now turn the call back to John.

[John W. Lindsay:]

Thank you, Juan Pablo. Juan Pablo gave you a preview of our expectations for the fourth quarter. With the uncertainty in the supply-demand outlook, we are anticipating that oil prices will remain range-bound in the mid-to-high 40s through calendar 2017. We believe in that oil price environment we still have the potential to improve day rates and capture market shares, even with a flat rig count scenario, because of our efficiencies, our high-grade opportunities and significant value to customers. We have grown market share from 15% at the peak in 2014 to approximately 20% market share today. We remain confident about the future for H&P, as our competitive advantages remain in our people, performance, technology, reliability and uniform FlexRig fleet. And now, we'll open the call for questions.

[Operator:]

We'll take our first question from Colin Davies of Bernstein. Your line is open.

[John W. Lindsay:]

Colin?

[Operator:]

Mr. Davies, your line is open . We'll move next to Kurt Hallead of RBC. Your line is open.

[Kurt Hallead:]

Hi. Good morning.

[John W. Lindsay:]

Good morning, Kurt.

[Juan Pablo Tardio:]

Good morning.

[John W. Lindsay:]

Good morning, Kurt.

[Kurt Hallead:]

Hey. Yeah. Very interesting times and indeed that's for sure. So, John, wanted to maybe come back around to some of the commentaries that you've already made regarding the ability to increase your market share to potentially increase rate. And if you can, maybe expand upon the types of value propositions that you're able to deliver in a lower oil price environment. And how that might compare to the value proposition that H&P was able to initially deliver when they introduced the FlexRigs to the market over 10 years ago?

[John W. Lindsay:]

Okay. Kurt, thank you. I think, maybe to frame it up in one perspective is if you look at the ongoing rig count that we have right now, I don't know if it's 950, 970 depending on whose rig count service you look at. And you look at the number of rigs that are drilling horizontal and directional wells. And again, to keep in mind that that complexity of the well continues to increase. About 630 of the rigs that are drilling those wells are AC drive and about half of those are super-spec. And then there's another 250 or 260 or so SCR and mechanical rigs that are drilling those same longer lateral and more complex wells. I'm assuming maybe they're not as complex. But I think when you consider that those rigs – that base rig design is a 1960s, 1970 design and technology, you have to believe that we're going to continue to see a trend towards more AC drive technology. So, that speaks to a strong reason why we believe that we're going to continue to see high-grade opportunities. We're going to be able to high-grade on some of those rigs and even some of maybe lower performing AC rigs. I mean, Kurt, really at the end of the day, the customer doesn't really care about whether the rig is AC drive or SCR. What he cares about is performance. And I think, over time, as customers see the value proposition, which really it exists today like it exist five years ago, which is, if we can deliver the well in fewer days, the customer can pay a higher day rate and actually save money on the well. And so I think that value proposition holds today just like it held 5 years ago and 10 years ago. The difference now is that well complexity is much greater, which I think even expands the opportunities set forth.

[Kurt Hallead:]

That's great. That's great explanation. Thanks. And maybe I've got a follow-up for Juan Pablo. Appreciate you kind of spelling out how you guys look at your capital structure and allocate the capital and think about the dividend vis-à-vis the debt dynamic. And again, I was just wondering, Juan Pablo, if you might be able to provide a little bit more insight as to why you may not be, I don't know, comfortable or as willing to tap into some of the debt markets to maintain the dividend vis-à-vis tapping into, say, the debt markets to explore some M&A.

[Juan Pablo Tardio:]

Sure, Kurt. I'll be glad to expand on that. I think that as the company reviews its capital allocation strategy and what we've done over the years, we've proven to be very prudent in that regard and always looking for opportunities to return cash to shareholders. Over the years, of course, we've increased our dividend levels with the expectation that we could sustain those levels. But those assumptions were based on a cyclical business that would allow us to, with the benefit of our backlog and with the benefit of our flexibility in terms of CapEx, sustain very high dividend levels through the cycles. However, if that assumption changes at some point and we see, as I mentioned, a prolonged down-cycle where opportunities to invest new cash in the business are scarce or are not there, then we will make sure that we manage that cash as responsibly as we can and not return more cash potentially than what the business can generate in that type of soft environment. So, in that type of very soft environment in the future, we would most probably look at adjusting our approach to the dividend. However, as I mentioned, we do expect an improvement in the business. We do expect the cyclical nature of our industry to continue. And so, from that perspective and as far as we can see today, we are in great position to continue to sustain the dividend. We don't expect changes to our debt level. We are very pleased with how our EBITDA levels and our revenue levels have been improving. And we don't expect, again, given what we can see in the foreseeable future, that our cash levels will come down in a very significant level as we move forward. So we were just trying to make sure that everybody understood that what our perspective would be regarding borrowing additional funds if we were to go into the described very soft scenario, and hopefully, that is helpful for everybody.

[Operator:]

Our next question is from John Daniel from Simmons & Company. Your line is open.

[John Daniel:]

Hey. Thanks for putting me in. Couple for you, Juan Pablo. Just first one would be, you cited a bunch of different contracted cash margins by year I think, and I'm moving very slow today, didn't fully catch what you said, or if you could just refresh that commentary, would be helpful.

[Juan Pablo Tardio:]

Sure. So you've probably seen our backlog, as we've reported it over time, and it's a multi-year backlog. And given that we have the term contracts for new builds that were negotiated before the downturn now combined with term contracts that were priced during the downturn, it creates a little fluctuation that we wanted to provide a little more granularity for. So let me give you a little bit more information and then expand on or repeat what I mentioned. On our U.S. Land segment for fiscal 2018, we expect an average of a little over 53 rigs that are already under term contract that is, the number for fiscal 2019 is a little under 20 rigs, and the number for fiscal 2020 is a little over 7 rigs, on average contracted during those years. And what we've provided as an additional reference is the expected average rig margin per day for those rigs during those years that are already under contract. And those numbers for fiscal 2018 are $13,000 approximately, for fiscal 2019 are $14,500 and for fiscal 2020 are $15,500.

[John Daniel:]

Got it. Okay. Thank you. Very helpful.

[Juan Pablo Tardio:]

Welcome.

[John Daniel:]

And the guidance for international, it refers to adjusted quarterly revenue days. Will there be any other incremental contribution for international from those five contracted rigs in terms of revenue days? I'm just trying to understand the adjusted concept.

[Juan Pablo Tardio:]

Those five contracts are generating revenue days and will continue to generate revenue days, given that the customer withdrew that early termination notice. So, all 10 contracted rigs that we've been referring to in Argentina will continue to generate revenue days during the following quarter, including those 5. Does that address your question?

[John Daniel:]

...you could have an incremental financial contribution from those other rigs, is that fair, like you did this quarter, sort of a bump, right?

[Juan Pablo Tardio:]

Well, what we did for this quarter...

[John Daniel:]

Yeah.

[Juan Pablo Tardio:]

...for the third fiscal quarter is we provided the adjusted level of activity, excluding retroactive adjustment. So the 13 rigs on average that were reflected as active in the adjusted numbers...

[John Daniel:]

Yeah.

[Juan Pablo Tardio:]

...include the 5 rigs that you are referring to. So 13 rigs active on average in the third fiscal quarter and an expectation of the same 13 rigs being active during the fourth fiscal quarter.

[John Daniel:]

Okay. All right. Got it. And then just last one for me. You would care to take a guess at what bare bones CapEx might be next year, if you were to basically materially reduce rig upgrades?

[John W. Lindsay:]

Well, John, as you know, we haven't discussed that. I mean you clarified it without a lot of upgrades what was our beginning CapEx for last year – for 2017, for this year, I'm sorry.

[Juan Pablo Tardio:]

We started at $200 million and we had a CapEx level of $257 million, I believe, for fiscal 2017. And then we started this year with an expectation...

[John W. Lindsay:]

2016.

[Juan Pablo Tardio:]

Thank you. Pardon me, fiscal 2016. We started this year with an estimate of $200 million and that has increased, given the upgrading opportunity that we've had.

[John W. Lindsay:]

Yeah.

[Juan Pablo Tardio:]

So I think to say in a bare bones, as John described it, I think those were reasonable ranges.

[John Daniel:]

Yeah. I'm only asking because then people worry about the dividend if you decided, hey, we just kind of ramped down our CapEx. Just from a modeling prospective, where could you take it at all for a short period of time?

[Juan Pablo Tardio:]

I think what we provided are reasonable references. The maintenance CapEx level that we've been commenting on related to our fiscal 2017 CapEx estimates is roughly around $100 million. So, that's another reference for your consideration.

[John Daniel:]

That's very helpful. Thanks, guys.

[John W. Lindsay:]

All right, John. Thanks.

[Operator:]

Our next question is from Matthew Johnston of Nomura. Your line is open.

[Matthew Johnston:]

Hey. Good morning, guys.

[John W. Lindsay:]

Morning, Matt.

[Matthew Johnston:]

So, John, I just wanted to ask a question on your comment about being able to still push day rates higher even if the rig count is flat. I'm curious, what do you think the day rate trajectory looks like in a declining rig count environment. Maybe not a precipitous fall, but if we were to lose a 100 to 150 rigs in the U.S. land market over the next few quarters, do you think you could still push day rates higher just because of the natural high-grading that still needs to take place within the fleet or is it more flattish? Or do you just lose all pricing power once the rig count starts to fall?

[John W. Lindsay:]

I think, Matt, that's a great question. And obviously, we're making some assumptions. I think a part of your assumption is related to the lower end of the spectrum in terms of the fleet. I mean, it is a bifurcated fleet. The customer behaviors that we have seen are customers want more, not less, and they want higher performing rigs. And so I think, in that sort of an environment, if you had a 100- or 150-rig pullback and it was on the lower end of the spectrum, and I don't see customers pulling back away from the performance that they need. I mean, the reality of it is with the performance that we're providing and the cost of the well, it's a very, very low number. And so, again, our hope is that there's enough value proposition there to be able to just to support some pricing increases. I mean, let's face it, the pricing that we have today for the value that we're providing is on the low end of the spectrum. So, that's kind of our belief. As well as the upgrades that we're making allow us to push pricing. We're not making these investments without some sort of a return. Now we may not have a term contract, but we do have an expectation the rig is going to have a higher day rate and the rig is going to work. We're not going to upgrade a rig and go out and drill one well. We also have seen, when we do see churn, I mean I think that's the other thing to keep in mind, and we actually saw this as an industry in 2013. If you remember, when oil prices pulled back, the rig count remained relatively flat, up and down during the course of the year. And what we saw were significant high grades and, of course, the pricing, day rates were already pushed up to very high levels at that point. So, that portion of the equation is different. But I think that's kind of our belief. We're going to continue to upgrade rigs as long as we have what we think is a decent rate of return and we can get a higher margin. And if we don't see that then we most likely won't be upgrading additional rigs until we see that sort of demand and that sort of pricing.

[Matthew Johnston:]

Got it. I appreciate all that insight. It's helpful. And then maybe just one quick follow-up on the OpEx side. Definitely good to see the outlook for next quarter and the U.S. Land segment fall below $14,000 per day. As we look out over the next few quarters and into next year, do we need to see your rig count move higher before we think about OpEx per day moving lower? Or is there some room in a flat rig count environment for you to kind of grind a little bit closer to that $13,000-a-day level?

[Juan Pablo Tardio:]

That is a great question. I think that, as we've mentioned in the past, there have been two key contributors to the higher level of expense per day number that we've been seeing over the last several quarters. And the first one relates to upfront expenses on reactivating rigs and that, obviously, in a flatter environment would come down significantly, as we're expecting for the fourth fiscal quarter. The other consideration relates to the stacked rigs that we have. And we have close to 160 AC drive FlexRigs that remain stacked, and those rigs have a small dollar number per day related to being stacked. And these are basically made up of property taxes, insurance, other minor maintenance security expenses, et cetera. And so, as we said during our comments, I think 3% to 4% of the $13,700 expectation relate to those stacked expenses. And so, as you said, if we were to see a much higher level of activity or a higher level of activity, that would decline potentially significantly and allow us room to be closer to $13,000. But, at this point, we're very pleased to have seen the reductions that we have and to expect continued improvements. The other piece of the equation is what happens to labor, what happens to maintenance and supplies going forward. We don't expect significant changes on those items. But, of course, the market will tell whether we can achieve that. We've been very pleased with the significant improvements in terms of our ability to manage the supply chain. That has provided some room for improvement that has fortunately been able to offset some of the additional expenditures of having higher horsepower and higher expenses related to the rigs with greater capabilities that we have out there.

[John W. Lindsay:]

Yeah. Matt, I might agree with what Juan Pablo said, and I might just chip in. And he just touched on it a little bit, and you may have heard us say this before, but rigs are working harder today than they ever have. And so you're going through more expendables. The fact that we can get our costs in the levels that we have and even close to previous cycles is pretty amazing. Our supply chain effort in a lot of ways has improved. But I think it also speaks to the question earlier related to day rates. I mean, the rigs are working hard. The rigs are delivering great value. Customers are taking advantage of that. It's great for them and for their wellbore. But the fact is we're having to spend more money on these rigs. So I think that's another element that supports a pricing improvement to cover those costs.

[Matthew Johnston:]

Got it. Thanks, guys. Really appreciate it. Thank you.

[John W. Lindsay:]

Thank you.

[Juan Pablo Tardio:]

Thank you.

[Operator:]

Our next question is from Marc Bianchi of Cowen. Your line is open.

[Marc Bianchi:]

Thank you. Hey. I wanted to take a step back and think maybe a little bit more strategically or ask how you're thinking strategically. It seems to be that perhaps the U.S. market is in a mature phase or perhaps entering a mature phase where there's not a lot of new build opportunity. Sure there's some upgrade, you're going to participate in that. But just as you think kind of longer term, you guys were ahead of the curve on the AC new build phase that occurred in the U.S. Maybe the next area of opportunity for efficiency gains is international. So, given the balance sheet, given the capability that you have there, how does that play into the thoughts around capital allocation, perhaps expanding more aggressively internationally at this point?

[John W. Lindsay:]

Well, Marc, I think there's definitely some opportunities international. We've seen those over time. I mean, we all know a lot of the challenges associated with growing international. So we do have an effort focused on international and figuring out how we're going to compete more effectively internationally. Obviously, international has been challenged as well. But I think, to your point about maybe being less mature on some of the efficiency improvements, I would agree with you. That's the reason why we have FlexRigs working in Argentina and the way that we do, because those rigs deliver great value. So I think there's an opportunity. But I think in terms of technology just in general, and I think it starts in the U.S., and just our ability to continue to innovate to be able to drive higher levels of performance with technology additions. I think MOTIVE is an example of that. There's software solutions, there's data solutions, there's machine learning. There's still a lot of things we can do as it relates to reliability and improving that and kind of helping our people deliver the wells more efficiently, do it safer, and do it in a more reliable fashion. So I think there's still opportunities for investment from that perspective as well.

[Marc Bianchi:]

Sure. I suppose, if you were to look more aggressively at the international market than you are right now, would it be more likely a new build opportunity for you or are there M&A opportunities that you're tracking that seem interesting?

[John W. Lindsay:]

Most of the M&A opportunities that you see internationally are pretty old assets. And even if there are some newer assets, it's also coupled with a lot of older assets as well. I think for us, we would not need to build – for instance, if it were a FlexRig application, a Flex3, Flex4 or Flex5, which we have Flex3s and Flex4s of course working internationally, we can expand with the existing fleet that we have on the ground here. Juan Pablo talked about the availability that we have here where we have that same scalability internationally. I think the exception would be, if you were looking at a different design or a higher horsepower offering or some other new build opportunity, which I don't know if there's any out there right now, maybe some of the larger 3,000-horsepower rigs would be an opportunity. But I think, right now, at least with the rig counts that we have, the industry is going to be pretty hard-pressed to get into a new build mode, because I think new-build economics, just the pricing that's required is a long way from where we need to be.

[Marc Bianchi:]

Sure. That makes sense, John. Thanks a lot. I'll turn it back.

[John W. Lindsay:]

All right, Marc. Thank you.

[Operator:]

We'll take our next question from Rob MacKenzie of IBERIA Capital. Your line is open.

[Rob J. MacKenzie:]

Thank you, guys. John, my question is kind of a follow-up on the last one, if I may. There have been some out in the industry that have been arguing for potentially larger rigs to work on multi-well pads in the U.S. that can handle longer laterals, all the hydraulics and stuff associated with that. Do you see the demand for that, the argument for that? And if so, does your argument about the efficiency of modern rigs today, wouldn't that apply to a potential new build that can drill on a multi-well pad more effectively?

[John W. Lindsay:]

Well, there are some significantly deeper wells that we have been drilling. Actually, in our press release, on the second bullet or the third – I think it's the third page, we recently drilled a 27,750-foot well, had a lateral of almost 20,000 feet. And we did that with the FlexRig5. We've had FlexRig3s that have drilled 25,000-foot measured depth wells. So I think it's the perspective that you're looking at it from. If you're looking at it from a contractor who has a much smaller fleet or a lesser capacity fleet, then I think that is what their response will have to be in many cases, is they're going to have to build new or they're going to have to have a significant upgrade of some sort. These types of wells don't – these aren't 2,000 or 3,000 horsepower requirement jobs. Most of the capacity is related to the setback and related to the hydraulics, and the top drive horsepower. Does that answer your question?

[Rob J. MacKenzie:]

Yes.

[John W. Lindsay:]

There are some really super laterals out there. Most of those are gas plays. This was a gas play, not an oil play. Not all – in fact, I think, very few of the acreage positions in the oil basins would provide for this level of extended reach work. I think we're seeing some 10,000 and 12,000 feet, but I don't know that we've seen anything like this in most of the more active plays.

[Rob J. MacKenzie:]

No. Great. That is very helpful. Thank you for the commentary there. I appreciate it. That does it for my questions.

[John W. Lindsay:]

Okay. Thank you, Rob.

[Operator:]

Our next question is from Scott Gruber, Citigroup. Your line is open.

[Scott A. Gruber:]

Yes. Good morning.

[John W. Lindsay:]

Morning, Scott.

[Juan Pablo Tardio:]

Morning.

[Scott A. Gruber:]

John, you made a strong case earlier on the ability to increase the penetration of AC rigs even in a flat market. If we just think about the super-spec class, a competitor of yours on an earlier call quoted 465 super-spec rigs in existence today, if I caught their number correctly. And that would be relative to about 800 shale rigs running according to Baker, which does suggest obviously that there's a long runway to push these super-spec units into the market. I'm wondering where we hit saturation. Not every well needs a super-spec rig. How should we think about that? How do you guys think about it?

[John W. Lindsay:]

Well, it's a great question and I know a lot of people are wondering about that. I think, at least our internal studies and results, we think we're more in the low-300 range of super-spec rigs and maybe 325 to 350 super-spec rigs rather than the 465 super-spec rigs. I would be interested to see that report just to see how those rigs are broken out. And you're talking about not super-spec capable, but already upgraded to super-spec, is that what you're saying?

[Scott A. Gruber:]

That's correct. And I'd have to go back and check. They may have quoted 365. I was trying to just check it before I mentioned it and couldn't do so.

[John W. Lindsay:]

Yeah. So I think the way we do see it though is that there's about 600 to 650 rigs we think are capable of being upgraded to super-spec capacity. And so, a little over half of those are upgraded today. And so I think in an 800-rig count environment with only 600 or so super-spec capable rigs, that's a pretty tight market. I mean, I just see customers today that would never even had an AC rig running, much less an upgraded rig with the kind of capacity that we're talking about today. Some smaller players, even some midsize to even some larger players today that previously weren't focused on AC drive technology, they see it today. They understand the value proposition. We've attracted over 20- some-odd customers over the last 9 months, 12 months or so. So it's got some traction. And so I think we're going to continue to see that adoption going forward.

[Scott A. Gruber:]

Is there a well footage where you start to see the demand from clients shifts strongly towards super-spec? Is there a way we can demarcate it by footage?

[John W. Lindsay:]

There's a lot of – I wish it were that easy because there are so many variables. But one of the things we have seen is, when a lateral length reaches around 7,500 to 8,000 feet, in some basins, not in all basins, but in some basins that's where we've began to kind of max out on the limitation of the 5,000 psi kind of the standard mud pump system. In some cases, the top drives that are in use, the pressure ratings. There's various things like that that we've seen, but it's not a hard and fast rule by any stretch. But I think at least the latest – Dave, correct me if I'm wrong, the latest data, the average lateral is still just around 7,000 feet.

[David Hardie:]

That's correct.

[John W. Lindsay:]

And so, if you look at it on an average basis, we still have a ways to go to push that. But there are a lot of operators out there, obviously, that are drilling 8,000-, 12,000-, even 15,000-foot laterals, which is far and away above the average. So, as you see that average being pushed to 8,000, to 9000 feet, then I think in that stage you'll begin to see even more requirements for the super-spec-type rigs. At least that's the assumption that we're making. We're having to make some assumptions because we just don't have the entire data set in order to make that decision.

[Scott A. Gruber:]

Well, it seems reasonable. Appreciate it. Thank you.

[John W. Lindsay:]

All right, Scott. Thank you.

[Operator:]

Our next question is from Sean Meakim of JPMorgan. Your line is open.

[Sean C. Meakim:]

Hi. Good morning.

[John W. Lindsay:]

Morning, Sean.

[Sean C. Meakim:]

So, just to stick on the upgrade topic, can you maybe give us a sense of how the paybacks look on the walking systems? And maybe when you have to do that entire package, say, $7 million, $8 million, just curious if it's been maybe a three- to four-year range. And then what type of contracts were you able to put against those upgrades?

[John W. Lindsay:]

We've had a range on the contracts – I don't remember – it seems like they were 18 months to two year on a couple of the contracts. The very first rig is in the spot market. These are low-20s type day rate. So it's going to be a function of what assumption you make on what the length of the activity for those rigs. We think we're going to get a return, really haven't cranked through all the numbers on that, Sean.

[Sean C. Meakim:]

Okay.

[Juan Pablo Tardio:]

Yeah. But its' going to be similar to what we've attained in the past, very attractive returns from a ROIC perspective during the terms of the contract. And then if we make an assumption that those rigs continue to work at similar day rates, I think it is fair to assume that paybacks will also be similar to what we've seen in new builds in the past, if you take into account the incremental investment on those rigs...

[John W. Lindsay:]

Yeah. I think...

[Juan Pablo Tardio:]

...and the return on that.

[John W. Lindsay:]

Sean, the other thing to keep in mind is the demand for those rigs. I mean, we're trying to create demand for that. Most of the demand has been in the Northeast, and some of these in the gas plays, Utica as well as the Marcellus. There hasn't been as much demand for that in the oil basins, particularly in the Permian and the Eagle Ford. So we're going to see how that plays out. Again, we're not going to build those rigs on spec per se. We're just expecting that the business is going to come our way. We're going to see how that works. But, again, the good news for us is we have four out of the five committed at this time, and we'll continue to watch that. We continue to have demand for Flex3s with skid systems and upgrade packages. That continues to go on as well. So, again, it kind of goes back to that family of solutions opportunity. We can fit the rig to meet the customers' needs.

[Sean C. Meakim:]

Right. No, that's very helpful. And so then it's interesting, one of your competitors announced today that they're going to upgrade some 1000-horsepower rigs to 1,500 super-spec status, costs about $8 million, similar paybacks to what you just mentioned I think. So now we're going through the trouble of reworking the substructure, et cetera. These are things that I think a year or so ago, and talking to folks in the industry, that seem to be a bit more of a challenge. Isn't there some risk that maybe this super-spec capable capacity market is a bit bigger than what was laid out here?

[John W. Lindsay:]

So, that's kind of the million-dollar question, isn't it? I mean, how big a market is it? I'm not certain exactly how to get our arms around that. I mean obviously, our customers, at least the intent seems to be to drill longer laterals. And so I think in that environment, it makes sense. A high quality rig that delivers a lot of value, meaning saves days, is safe and is reliable with great people, is worth a lot of money. And so I think, when you look at it from that perspective and the total well cost, it makes sense that there's some additional upgrade capacity out there. At least that's what we've seen. But, again, we're not going to continue to build or upgrade rigs without their being a market and some sort of commitment or expectation that we're going to get a good return on our investment.

[Sean C. Meakim:]

Fair enough. Okay. Thank you for the time, guys.

[Operator:]

At this time, I'd be happy to return the conference back over to Mr. John Lindsay for any concluding remarks.

[John W. Lindsay:]

Okay. Thank you, Leo. I just want to reemphasize and kind of close out that we're confident about the opportunities ahead. We see our sales as being positioned well with the largest fleet of AC rigs in the industry. And we believe that our capability and our technology positions us with the fleet design to meet the future needs in the market. We want to thank each of you again for joining us on the call today, and have a great day. Thank you.

[Operator:]

Thank you. This does conclude today's third fiscal quarter earnings conference call. You may now disconnect your lines. And everyone have a great day.