Good day, everyone, and welcome to the Fiscal Fourth Quarter 2019 Earnings Conference Call. All participants are in a listen-only mode. Later, you will have a chance to ask questions during the Q&A. Please note, today’s call will be recorded, and I will be standing by if you should need any assistance. It is now my pleasure to turn the program over to Dave Wilson, Director of Investor Relations. Please go ahead, sir.

Thank you, Miranda, and welcome everyone to Helmerich & Payne’s conference call and webcast for the fourth quarter and fiscal year ended 2019. With us today are John Lindsay, President and CEO; and Mark Smith, Vice President and CFO. Both John and Mark will be sharing some comments with us after which we'll open the call for questions. Before we begin our prepared remarks, I'll remind everyone that this call will include forward-looking statements as defined under the securities laws. Such statements are based on current information and management's expectations as of this date and are not guarantees of future performance. Forward-looking statements involve certain risks, uncertainties and assumptions that are difficult to predict. As such, our actual outcomes and results could differ materially. You can learn more about these risks in our annual report on Form 10-K, our quarterly reports on Form 10-Q and our other SEC filings. You should not place any undue reliance on forward-looking statements, and we undertake no obligation to publicly update these forward-looking statements. We will also be making references to certain non-GAAP financial measures such as segment operating income and operating statistics. You will find the GAAP reconciliation comments and calculations in yesterday's press release. With all that said, I'll turn the call over to John Lindsay.

Thank you, Dave, and good morning everyone. The Wall Street Journal had two salient articles about the energy business this week. Both underscored the copious amount of energy supplies that exist worldwide and the Catch-22 this has created for the industry, our industry, the industry, most responsible for this economic bounty. Today, oil and gas companies are suffering from a curse of abundance, and according to the journal articles, we're still deep in the woods in terms of supplies and pricing. One article points out that energy has been the only negative sector in the S&P 500 over the past 12 months and that energy indices have declined by more than 40% during the year. This is an odd place to find ourselves as an industry, particularly after delivering so much value to the economy over the last decade. The U.S. is no longer energy dependent. Our country is exporting energy again. Energy supplies and pricing remain key determinants of national security and the health of our economy, and while we may be considered an ugly duckling in Wall Street indices, only the energy industry can say with complete confidence that all other industries depend on us for their continued prosperity. Think about everything that abundant and low-cost energy enables across the globe. H&P is very proud to play a role in this progress and to have pioneered rigs and technologies that have enabled safer, faster, and better drilling than anyone could have ever imagined even 10 years ago. I'm going to cover three main topics today: first is U.S. land activity and pricing; second is discussing updates and outlook for H&P Technology segment; and third, I will talk about our International segment. I'll begin with U.S. Land. The company continued to perform efficiently this past quarter despite a sizable…

Thanks, John. Today, I will review our fiscal fourth quarter and full year 2019 operating results, provide guidance for the first quarter and full fiscal year 2020 and comment on our financial position. Let us start with highlights for the recently completed fourth quarter and fiscal year ended September 30, 2019. The Company generated quarterly revenues of $649 million versus $688 million in the previous quarter, totaling $2.8 billion for fiscal 2019 versus $2.5 billion in fiscal 2018. The quarterly decrease in revenue sequentially is primarily due to the expected decline in the average number of rigs working in the U.S. Land segment. Direct operating costs decreased to $432 million for the fourth quarter versus $445 million for the previous quarter in correlation with the decline in our activity. General and administrative expenses totaled $50 million for the fourth quarter and $194 million for the full fiscal year, consistent with our previous guidance on the July call. Because our pre-tax income came in lower than we expected, we recognized a tax benefit for the quarter of $13 million as we had over accumulated our tax provision during the first nine months of fiscal 2019, relative to our actual year-end results. To summarize this quarter's results, Helmerich & Payne earned $0.37 per diluted share, including the aforementioned tax benefits of approximately $0.12 per share versus a loss of $1.42 in the previous quarter. Activity this quarter came in below our expectations with highlights by segment as follows. One, U.S. Land costs were adversely impacted by a one-time legal settlement. Further, the rig count exited the quarter at the low end of our guidance range. Two, International earnings were affected by foreign exchange losses in Argentina as well as higher than expected start-up costs for our first international super-spec rig. Three, offshore…

[Operator Instructions]. And we'll take our first question of the today from Kurt Hallead with RBC. Please go ahead. Your line is open.

Appreciate the update, the insights and the outlook there, John and Mark. So John, for you, just in the context of your discussion about a stabilization in demand for rigs, the one thing that kind of grabbed my attention specifically was your commentary about an expectation on kind of a consistent level of activity throughout 2020 that could kind of replicate maybe the kind of second half averages of '19. Do you get a sense in your conversations with the client base John and what kind of underlying commodity price is that dictated by?

As you know, Kurt, the -- our customers in general haven't -- in a large scale way, haven't reported their budgets for 2020. So, we're making a couple of assumptions here, obviously. I do think that for the customers that we have heard from, it sounds like a very similar price deck to last year, $50 per barrel to $55 per barrel as they are setting their budgets. And so, I think that's the best estimate that we have right now. I do think, again, based on what we're seeing is that our rig count should flatten out, hopefully improve through the rest of this fiscal year. If you just look at average activity levels for 2019 and then you contrast it with where we're estimating the exit level of activity would be for this year going into next year, it appears that there could be an opportunity for picking some additional rigs at the beginning of the year. It's so hard to tell right now, and again customers in a large scale way have to set their budgets. So, we're just making an assumption on that for the most part.

And then, just in the context of just looking at the International cash margin, right. So first half of the year, the cash margin was roughly about $12,000 a day, obviously, dropped down to where it is here in the fiscal fourth quarter. As you get out and you get these rigs up and running, is it possible that at some point during 2020 that the average cash margin could get back to where it was during the first half of '19 or do we have to rethink that and kind of reset the baseline on International cash margins with these new contracts and the contract rollovers moving forward.

Kurt, thanks for the question. Yes, the four contracts, the LOIs we have, which are turning in the contracts are accretive certainly to our margins, and some of the items we've experienced this quarter are transitory. So, yes, we do expect those to return.

And do you think can they get back to first half of '19 levels?

It just really depends on the rollovers and our ability to redeploy them, but that's the plan.

Thank you. And we'll go next to Sean Meakim with JPMorgan. Please go ahead.

So, in the lower 48, low to mid-20s rates per day for both term and spot work, I think, is what you said in the prepared comments. Can you maybe just talk about the mix of spot versus term work and how that's been changing in recent months, and then your outlook for both your customers' appetite for term as well as yours at current levels going into next year?

Sean, thanks for the question. We've been able to -- interestingly, we entered this calendar year at about 60% term coverage, and we're here today at 65% plus term coverage on the fleet; and as I mentioned, we're going to -- we already have booked for the full fiscal year 90 some odd rigs on term. We like that future certainty of cash flow and plan to keep a mix and a balance, and that mix has not changed for us through the year. The target is to keep it there.

Also, your comments on technology adoption, I think, are well taken, particularly in the current environment. So given maybe timing is a bit out of your control to some degree, but could you give us a sense of what type of revenue base for HPT is required to get that business up to operating profitability.

Sean, I might start with just by reemphasizing. I think one of the advantages to enhancing adoption is success. Obviously, we've had quite a few rigs that have been released, both our rigs and competitor rigs that had -- have had the technology deployed. So that's hurt us on the activity side. I think one of the reasons why I wanted to talk about what customers are liking is they like the consistency, they like the predictable performance that automation can provide. While it is a challenge on the change management perspective, they see -- they're beginning to see kind of a light at the end of the tunnel so to speak. So, I do think that there's opportunities to continue to grow the autonomous platform. Do you want to...

And it's really -- as John was just alluding to, it's about the number of deployments we have. It's about how many customers and rigs we have signed up for software-as-a-service, because individually, each of the product offerings are very high margin. They're simply due to their nature of software-as-a-service businesses. So, once we can get a critical mass of units in production, we're very excited about the accretive possibilities of HPT.

So is there -- are there any other benchmarks around how to size that critical mass you can offer for us?

Not yet. Too early.

Thank you. And we'll go next to Tommy Moll with Stephens Inc. Please go ahead.

Wanted to start on leading-edge day rates for super-specs. It sounds like we're still in the low to mid-20s range which I think is likely more disciplined than what a lot of folks had feared going into earnings season. So, I was hoping you could comment on H&P's continued commitment to remain disciplined there on pricing, and then also something that might help clear up some of the confusion among investors, I think, is the difference in the all-in rate versus the base rate where there are a lot of different components that build up to the number that you actually report. So, anything you could do to help us understand the difference in those two data points would also be helpful? Thank you.

Sure, Tommy. I'll start with -- we like to look at the value proposition that we're providing our customer and our focus is there. We really believe strongly that it's a win-win situation for us and our customer because if you look at the results, what you see are improving well cycle times, you see improving cost of wells for customers. Those cost savings are not a function of drilling providers lowering the rates. The cost savings are a function of better productivity. And then, as we begin to layer on additional technologies, there's going to be even greater -- greater savings. So, I think it really comes down to as you think about how hard the rigs are working and the value that we're providing, we really can't afford to come off of pricing. And again, it's one of those situations you continue to hear me talk about partnerships with customers and that's really a big part of that.

I'll just add Tommy to that, that our average rig revenue per day range that I mentioned for our expectation on top of that are the FlexServices I mentioned and those range everything from trucking to casing running tools, rental equipment, extra personnel, other adders and those can vary from $1,000 to $2,000 per day depending on the basin, the customer, the rig itself. So that is what you add on top of the low to mid-20s spot rate to get to the average revenue per day.

And then to shift to CapEx, you've identified the budget for next year, which is at the midpoint, slightly lower than what we had previously expected. So good to see continued capital discipline there. You also broke out the piece of the overall budget allocated for maintenance CapEx and obviously, there is a big range there, but does that expectation for maintenance contemplate a U.S. rig count flat, up or down versus where you think you'll end this first fiscal quarter.

Tommy I'll let you do the math and extrapolate full-year guidance.

We can tell you what we hope for, does that -- we hope it’s up.

The upper end of the range? Okay.

Well, we -- that's what we hope, but again that's -- I think you, like, Mark said, you have to do the math on it, but depends on what oil prices are. There's a lot of -- as you know, there's a lot of variability. It's hard look out just one quarter, much less a full year.

Well, maybe I could ask it a different way or a related question. To the extent you do see opportunities to add rigs next year, will there be any headwind on your cost line as those rigs go back to work.

Not, as much as if we were reactivating for example. We are activating a lot long idled rigs or rigs that we had upgraded to super-spec because as I mentioned on the call the fact is, we have 50 plus super-spec rigs currently idled and those are reasonably idle. So they're hot to warm in most all cases and would require a little additional cost to get back into the field on one hand. On the other hand, we certainly would have personnel costs related to re-hiring and training et cetera.

[Operator Instructions]. We'll take our next question from Marc Bianchi with Cowen. Please go ahead.

I guess just quickly on the spot market or kind of leading edge market commentary, you guys have been disciplined. You're talking about stability in the rig count. Would you anticipate that kind of the -- going forward now, you sort of see stability in that leading edge rate in the low to mid-20s? Is that how you would characterize it?

Well, Marc, it's hard to say. We obviously have pricing pressure which isn't unusual in our industry almost regardless of what the market is, but obviously an improving outlook makes it a little less challenging. And again, I think, for the most part, the drilling peers have maintained discipline. We haven't seen a lot of irrational pricing, particularly with larger players. So, I think in general, our goal would be to keep it in the range where we are. That's our goal. It's hard to say for sure. How it ends up turning out, we can tell you what we're trying to accomplish, and again, we continue to focus very, very much on the value proposition that we're providing and whether that's providing different type contracts related to performance-type contracts where you're setting KPIs for your performance. Again, that's a true win-win and we're up for that all day long.

Okay, thanks for that John. In terms of HPT, I just wanted to ask on the -- in the fiscal fourth, Mark, you mentioned the $8.9 million of benefit there. Is that -- was that benefit in gross profit? I'm just trying to think about what kind of the run rate gross profit margin is to work off of the revenue guidance that you gave in here for fiscal first?

Yes, it -- I mean, it -- netted all cost zero basically.

So the delta would just be at the $8.9 million back to the…

Thank you. We'll go next to Taylor Zurcher with Tudor Pickering & Holt. Please go ahead.

John you talked again about the new pricing models that you're exploring and it sounds like the performance-based model is the one that's having the most success thus far. Could you maybe frame for us how many rigs are utilizing that pricing model today? And then, with the results thus far, I mean, is the revenue per day you're generating with that sort of pricing model accretive to what you might generate in the spot market today.

I believe that the performance pricing has been accretive to what we would see in the spot market. My preference is not to talk about the numbers in terms of numbers of contracts that we have, but we have continued to see improvements in that. The numbers are higher this quarter than they were last quarter, but in general -- again, it's a true win-win because it puts skin in the game as if there isn't skin in the game already, but it does put additional skin in the game. So we're all in on that type of pricing model.

And then one question on capital allocation. Obviously, the dividend's still the priority moving forward. But this quarter, you did purchase, I think, about 1 million shares. Maybe you have some extra cash in the balance sheet moving forward and if the stock prices is still in and around current levels today, should we expect you guys to continue to whittle away at share repurchases over the next few months or few quarters?

We have a -- Taylor, we have a standing authorization to buy back 4 million shares per annum. Having said that, we have repurchased shares in the past, but not on a frequent basis at all. Based on the opportunity set or what to do with cash at the time and the amount of cash accretion we were -- we were experiencing in Q4, we felt the share repurchase was a prudent decision. It also serves to mitigate some of the dilutive effects of various stock related awards.

Thank you. And we'll go next to Scott Gruber with Citigroup. Please go ahead.

Can you update us on how many FlexRigs have walking systems today and do they still cost -- I think it was about $5 million per when we talked kind of this time last year. Is that still around the right cost or has that come down some?

From a -- I'll start off, Scott. From a cost perspective of the walking rigs with the higher end number they were to actually upgrade Flex3 to walking was about $9 million, whereas the skidding upgrade was $3 million. The cost to convert however, from skidding to walking is around $7 million is what we're projecting. So the delta there being the PSI and the third mud pump. Today in our fleet, we have -- and to the first part of your question, today, in our fleet, we have about 40 walking rigs.

So just to be clear when you guys say the budget, there is 11% to 15% skidding to walking conversions, that's the $7 million you're targeting associated with those conversions?

Yes. Otherwise, $4 million to $6 million for the year is the number you're trying to get to I think?

Yes. Got you. I mean, overall, are you seeing customers pay a premium for the walking FlexRigs over the skidding rigs or we just generally helping the appeal of the rigs to customers and adding utilization?

We have, Scott. We've had a -- we've seen a consistent more mid-20s type pricing. We've also had skid rigs at mid-20, but the average hasn't been mid-20 and I would say the average for the walking rigs have been closer to mid-20s. And in general, we've had two-year term contracts with those as well. Two-year to three-year, some cases, three-year term contracts.

And I'll just add to that we will require a term contract to do such a conversion.

Is it safe to say that the walking rigs are at the high end of the spot range and it's skidding rigs are towards the low end? Is that fair?

Yes. But we don't have that many that are on spot, most of them are termed up.

Thank you. And we'll go next to Thomas Curran with B. Riley FBR. Please go ahead.

John or Mark, when it comes to the new performance-based contracting model you've been experimenting with, what percentage of performance-based wells drilled or revenue generated to date has resulted in higher revenue per day than the day rate you otherwise would have earned under the traditional model or if it's a better measure of a higher average daily margin, whichever it is you think we should be focusing on to determine the efficacy of the new model?

Yes, I don't have a percentage top of my head, but I do know that the margins and the revenues are generally higher than what we would see in the spot market type of contract.

Could you give us an idea of average order of magnitude or sort of the greatest premium you've been able to realize thus far?

Yes. Our preference would be, we would rather not for competitive reasons, but again I think it's -- I think it's a great contract design. As I said earlier, we've got -- we've -- both parties have skin in the game and we're trying to provide a win-win.

Okay, but it sounds like you're definitely capturing that greater value you're delivering than you otherwise would have been and that's encouraging. Then for AutoSlide, I know there was an expectation that you have -- a first commercial deployment in the Delaware by the end of last quarter calendar 3Q. Would you please update us on that Delaware portion and then speak to which basins are most likely to be numbers six and seven and whichever order they might occur.

As far -- I don't -- I'm trying to think we're six and seven or -- and I don't recall where those are, but Delaware is just right around the corner. It's actually been on queued up for several months, but it really comes down to having the right customer, the right partnership as I've mentioned on several of the calls. The change management side of the equation is as important as anything that we're doing. The technology piece is really the easy part. It's the workflow changes and change management. So I think we will have the Delaware in this quarter if I'm not mistaken, we'll have our first round going there.

Which will be the fifth basin.

Yes, that will be the fifth basin.

And then just one more for me on AutoSlide. How many different unique customers have commercial used it thus far?

I think we're at five that we've been working with.

Thank you. And we can go next to Chase Mulvehill with Bank of America. Please go ahead.

Thanks for squeezing me in. So I guess, real quick -- I may have missed this, but did you disclose the average day rate for your term contracts for fiscal year 2020.

I don't know...

I'm sorry, could you say that again.

No. Yes, maybe I was working up. So, yes, so the -- looking to see if you disclosed the average revenue per day for U.S. Land business for the term contracts for fiscal year 2020. Typically, you give us that on the earnings calls.

I did. I said that they're earning the current average day rates.

Okay, got it. Current average day rates, okay. Can you clarify that for us? The current meaning of which you gave for the quarter for 4Q or for 3Q or for calendar 4Q?

Yes. It’s that low to mid-20 day rate. So if you take the question we had earlier about the average rig revenue per day, back of the FlexServices and you're right at that day rate.

Yes, I guess, I'll just take it offline, that's fine because there’s a big difference between low-to-mid. So, all right. I guess, from the day rate side, you've talked about some dayrate pressure. It seems like maybe some of the rig declines are slowing. Have you -- have day rates start going down at this point for the super-spec rigs?

As we said, we've been very fortunate to have pretty firm consistency in our low-mid, 20-day rates. So, yeah, we're pretty fortunate in that spot and term contracts seem to be at about the same level.

Yes, I was taking more leading edge. If I'm hearing you right, day rates -- leading edge day rates are flattened out and then stop going down if I heard you correctly.

I would say that.

Yes on the leading edge, I would agree with that.

I wanted a real quick one. Argentina, could you talk about what you expect in Argentina as we roll into 2020? I think you've got some contracts that rollover. How are negotiations going with those and should we expect those to kind of continue into 2020?

We do have, as I mentioned, the first two IPF rigs that were dispatched to Argentina five years ago are rolling off in this fiscal first quarter. And the rest will roll off through fiscal '20 and we have been in active discussions to put those rigs back to work with IOCs and other E&Ps in the Vaca Muerta. As John mentioned, we're sort of -- and I think I might have reiterated as well, we're sort of waiting for the dust to settle from the recent election cycle and -- but are pretty buoyed by a recent trip to the country and visiting with prospects and are still pretty bullish on the long-term prospects of the Vaca Muerta for Argentina and also for Helmerich & Payne.

Thank you. And at this time, I'd like to return the floor back to Mr. John Lindsay for any additional comments.

Okay. Thank you, Miranda. I'd like to close out the call today by reinforcing H&P has a track record of generating strong cash flow and maintaining a strong balance sheet in an industry where that is rare. This strength, along with our great team of employees put the company in a competitive position to address the challenges and opportunities that lay before us. We're going to continue to partner with customers to achieve mutual long-term success. So thank you again for your interest in H&P and have a great day.

Thank you. This will conclude today’s program. Thank you again for your participation. You may now disconnect and have wonderful days.