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 - Helmerich & Payne, Inc.: 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 - Helmerich & Payne, Inc.: 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…

We'll take our first question from Colin Davies of Bernstein. Your line is open. John W. Lindsay - Helmerich & Payne, Inc.: Colin?

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

Hi. Good morning. John W. Lindsay - Helmerich & Payne, Inc.: Good morning, Kurt. Juan Pablo Tardio - Helmerich & Payne, Inc.: Good morning. John W. Lindsay - Helmerich & Payne, Inc.: Good morning, Kurt.

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 - Helmerich & Payne, Inc.: 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.

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 - Helmerich & Payne, Inc.: 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.

Our next question is from John Daniel from Simmons & Company. Your line is open. John Daniel - Simmons & Company: 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 - Helmerich & Payne, Inc.: 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 - Simmons & Company: Got it. Okay. Thank you. Very helpful. Juan Pablo Tardio - Helmerich & Payne, Inc.: Welcome. John Daniel - Simmons & Company: And the guidance for international, it refers to adjusted…

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

Hey. Good morning, guys. John W. Lindsay - Helmerich & Payne, Inc.: Morning, Matt.

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 - Helmerich & Payne, Inc.: 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,…

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 - Helmerich & Payne, Inc.: 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…

Got it. Thanks, guys. Really appreciate it. Thank you. John W. Lindsay - Helmerich & Payne, Inc.: Thank you. Juan Pablo Tardio - Helmerich & Payne, Inc.: Thank you.

Our next question is from Marc Bianchi of Cowen. Your line is open. Marc Bianchi - Cowen & Co. LLC: 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 - Helmerich & Payne, Inc.: 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…

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

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 - Helmerich & Payne, Inc.: 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?

Yes. John W. Lindsay - Helmerich & Payne, Inc.: 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.

No. Great. That is very helpful. Thank you for the commentary there. I appreciate it. That does it for my questions. John W. Lindsay - Helmerich & Payne, Inc.: Okay. Thank you, Rob.

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

Yes. Good morning. John W. Lindsay - Helmerich & Payne, Inc.: Morning, Scott. Juan Pablo Tardio - Helmerich & Payne, Inc.: Morning.

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 - Helmerich & Payne, Inc.: 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?

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 - Helmerich & Payne, Inc.: 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.

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 - Helmerich & Payne, Inc.: 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 - Helmerich & Payne, Inc.: That's correct. John W. Lindsay - Helmerich & Payne, Inc.: 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.

Well, it seems reasonable. Appreciate it. Thank you. John W. Lindsay - Helmerich & Payne, Inc.: All right, Scott. Thank you.

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

Hi. Good morning. John W. Lindsay - Helmerich & Payne, Inc.: Morning, Sean.

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 - Helmerich & Payne, Inc.: 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.

Okay. Juan Pablo Tardio - Helmerich & Payne, Inc.: 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 - Helmerich & Payne, Inc.: Yeah. I think... Juan Pablo Tardio - Helmerich & Payne, Inc.: ...and the return on that. John W. Lindsay - Helmerich & Payne, Inc.: 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.

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 - Helmerich & Payne, Inc.: 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.

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

At this time, I'd be happy to return the conference back over to Mr. John Lindsay for any concluding remarks. John W. Lindsay - Helmerich & Payne, Inc.: 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.

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.