Helmerich & Payne, Inc. (HP) Q1 2019 Earnings Report, Transcript and Summary

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

Thank you, Priscilla, and welcome everyone to Helmerich & Payne's conference call and webcast for the first quarter of fiscal 2019. With us today are John Lindsay, President and CEO; and Mark Smith, Vice President and CFO. John and Mark will be sharing some comments with us, after which, we'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 undue reliance on forward-looking statements and we undertake no obligation to publicly update these 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 yesterday's press release. With that said, I'll now turn the call over to John Lindsay.

Thank you, Dave, and good morning everyone and thank you again for joining us on our first fiscal quarter earnings call. The Company delivered sequentially improved operational results in the face of falling crude oil prices, which decreased by more than 30% during the quarter. Still customer demand for super-spec rigs continued during the first fiscal quarter and H&P responded by upgrading and converting 14 additional rigs to super-spec capacity. This brought our total number of super-spec FlexRigs to 221 at calendar year-end. Today our activity stands at 238 rigs in US land, with 213 super-spec rigs active. Predictably, demand for additional super-spec rigs this first calendar quarter has softened largely due to oil price uncertainty, as well as customers' objectives to keep spending within cash flow in the coming year. The fourth quarter decline in commodity prices was a cogent reminder of the capital-intensive and cyclical nature of our business. And with that outlook, we reduced CapEx by more than 20%, or $150 million. We believe that oil prices will remain volatile and that price swings will occur over shorter durations of time. Just look at today's WTI price for instance. It's up 20% to 25% from a low price in December of around $44 a barrel. We have more than 70 customers split roughly 50-50 between public and private E&Ps. However, about 80% of our active rigs are working for publicly traded E&P companies. Discussions with several customers regarding CapEx outlook indicates a mix of increasing, decreasing and flat spending budgets. However the consistent theme is discipline, principally keeping 2019 spending within cash flow. Typically, we also see a few customers that seek opportunity and advantage by riding the fence, keeping one foot on the gas pedal and the other foot on the brake. Mark will discuss the details of our activity outlook in his prepared remarks, but with the improvement in oil prices here recently, we are seeing the pace of releases slowing. We believe an oil price above $50 a barrel WTI will continue to temper rig releases and during the past few weeks, we have noticed an increase in customers inquiring about rig availability. If we see oil prices stabilize at today's ranges, or even slightly above current levels, we would expect to see several FlexRigs reactivated in the March and April timeframe. Several recent industry-wide predictions indicate a drop in overall US land rig count of 100 to 200 rigs over the first half of 2019. If oil prices remain above $50 a barrel, our extrapolated view on the industry rig count is that fewer than 100 rigs will drop in the horizontal rig market, but as we've also learned, history can be a pretty fickle indicator when it comes to predicting future rig counts. Rig pricing is a hot topic and with our super-spec FlexRigs fleet forecasted to be around 90% utilization, we expect today's pricing to remain firm in the mid-$20,000 day range. Value pricing is one element of our contracting strategy, but we also have approximately 64% of our active fleet today under term contracts, up from 50% term coverage a year ago and the average term is slightly over one year. Shale-ready rigs are in the greatest demand and that is where our market share is concentrated. The value we provide is currently priced at a reasonable level and we have formed partnerships with many of our customers that enable additional levels of value creation. There's little doubt that well complexity will continue to increase and this should drive demand towards the top-performing and safest super-spec rigs that deliver the best value and reliability at the well-site. The Company's large offering of highly capable super-spec FlexRigs and the associated FlexApp technologies provide enhanced wellbore quality and downhole tool reliability. FlexApps are becoming essential tools as drilling in the most prolific U.S. basins continue to increase in complexity. These performance advantages become even more imperative in a softer cycle. Now, switching geographies for a moment, our international segment is seeing some positive indication of potential growth in both the Middle East and Argentina. We have super-spec FlexRig availability in the US, and are ready to mobilize assets to these markets should financially attractive and scalable opportunities arise to do so. The FlexRig is ideally suited for long horizontal wells and when coupled with our FlexApps, these offerings could add significant value for our international customers as unconventional plays gain momentum. The newly created H&P Technology segment, which encompasses H&P's digital technology and software based subsidiaries, Motive and MagVar also saw increased demand during the quarter. Individually or combined with the FlexRig, our wellbore quality and placement technologies greatly enhance the economic potential of a well and adds significant value to our customers and their stakeholders. We are seeing early adopters that are excited about the next level of innovation related to automation. However, there is substantial inertia in the industry to overcome that resistance to technological change, as well as some roles changing at the rig site. In some respect, this is no different from the push back we saw in the early stages of the FlexRig, both from customers and competitors. The new FlexRig technology over 10 years ago was disruptive in the industry and the adoption was slower than we liked at the time, but embracing the benefits of that technology became inevitable. H&P's drilling automation technology, AutoSlide, continues to gain momentum and interest from customers. I'm going to share a direct quote from one of our customers that's experiencing beta testing for AutoSlide today. And the quote was, “Recently, we had two rigs sitting side-by-side and drilling the curve in the same target zone, in the same area and the machine, AutoSlide, actually beat the man, the directional driller. So it shows there is a future for this and it's coming. It is already here and it's just getting better.” This is a great example of the technology working and a customer being very satisfied and ready to convert his fleet to AutoSlide. As I mentioned earlier, Motive technology and AutoSlide technology is disruptive on the rig from a personnel basis and the adoption rate is slower than some would expect. I say this to stress the importance of being patient. Technology adoption is coming and I believe we can improve adoption rates by improving our change management tools and training. And we'll have more to come on this in the future. Another opportunity for positive change is in new pricing models. Since our last call in November, we've received a lot of questions and feedback related to our new pricing models. Our new commercialization and pricing approach is one centered on value creation and shared gains. Partnering for innovation and value is where our pricing model is different from others in the market. We've reached out to our loyal customers who value performance to work with us on new business models that will ensure long-term benefits for both parties and ongoing performance improvement in our industry. We are investing more time in listening and collaborating with customers on how to improve well performance through unique value applications and technologies. I believe our customers are seeing the value we provide through a different lens, it's beyond just day rate, our customers recognize and appreciate that you get what you pay for. Before turning the call over to Mark, we believe there are excellent opportunities ahead as the Company's ability to plan, adapt and respond in a near term volatile market is one of the cornerstones of our long-term success. H&P has responded in order to better position itself for the future. We, of course, can't do that without having quality people that are willing to represent the H&P brand day in and day out. And despite industry conditions, the primary focus remains constant at H&P, to partner with our customers and add value through our people, our FlexRig fleet and our technologies. And now, I'll turn the call over to Mark.

Thanks John. Today, I will review our fiscal first quarter 2019 operating results, provide guidance for the second quarter, update full fiscal year guidance as appropriate, and comment on our financial position. Let's start with highlights for the recently completed first quarter. The Company generated quarterly revenues of $741 million versus $697 million in the previous quarter. The quarterly increase in revenue is primarily due to increases in both the number of revenue days and in the average quarterly revenue per day in the U.S. land segment. Total direct operating costs incurred were $489 million for the first quarter versus $449 million for the previous quarter. The increase is primarily attributable to 10 additional rigs working in US land and to a $21 million onetime legal settlement of which $18 million affected the first fiscal quarter. General and administrative expenses totaled $55 million for the first quarter. This is above the run rate for our full year guidance due in large part to costs associated with our bond exchange. Our effective income tax rate from continuing operations is also differed from the annual expected rate in Q1 predominantly due to a discrete income tax adjustment in Q1. Summarizing the overall results of this quarter, H&P earned $0.17 per diluted share versus $0.02 in the previous quarter. First quarter income per share was adversely impacted by net $0.25 per share of select items as highlighted in our press release. The two largest of these select items were: first a non-cash loss recognized on our legacy equity investments in two oil fields service companies which resulted from the adoption of an accounting standard update; and second, the settlement of an outstanding legal matter. Absent these items, adjusted diluted earnings per share were $0.42 in the first quarter versus an adjusted $0.19 during the fourth fiscal quarter. Capital expenditures for the first quarter of fiscal 2019 were $196 million, in line with our previous guidance that fiscal 2019 CapEx would be partly front loaded. Turning to our four segments, beginning with US land segment. We exited the first fiscal quarter with 244 contracted rigs, which is an increase of approximately 5% in the number of active rigs quarter-to-quarter and equates to an approximate 22% US land market share. I will discuss in more detail in a moment, but we do expect rig count to moderately decline in the second fiscal quarter, with our super-spec class maintaining a mid-90% utilization level. First fiscal quarter conditions continued to allow pricing improvements and excluding early termination revenue, our average rig revenue per day increased to $251,56 for the first quarter. The average rig expense per day increased to $15,433, due in large part to the aforementioned $21 million settlement of a legal matter, which resulted in the $18 million charge in Q1, or approximately $821 per day. Absent this charge, adjusted average rig expense per day was $14,622 which is towards the low end of our previously guided range. Looking ahead to the second quarter of fiscal 2019 for US land, as we have previously stated, we are putting first and second fiscal quarter upgrades to work under term contracts, but simultaneously some spot rigs have also been released. We expect the net result will be a sequential decrease of approximately 3% to 5% in the quarterly number of revenue days, which translates to an average rig count of approximately 234 rigs during the second quarter. Per my previous comment, we expect super-spec utilization to be in the mid-90 percentile range. Compared to the first quarter at $25,150 per day, we expect the adjusted average rate revenue per day to increase to a range from $25,500 to $26,000. The expected increase is driven in part by the rollover of term contracts at higher rates. We are also experiencing the beginnings of customer adoption of our FlexApp offerings, which are approaching $250 per day in revenues across the fleet. The normalized average rig expense per day directly related to rigs working in the US land segment remains constant at $13,700 per day. This per day figure excludes the impact of expenses directly related to inactive rigs, the idling of released rigs and the upfront reactivation expenses related to rigs that have been idle for a significant amount of time. In accordance with prior guidance, the mid-point of the average rate expense per day is expected to be in a range now $14,700 to $15,100 for the second quarter, as we start up our contracted fiscal Q2 upgrades and incur expenses to stack released rigs. Note that as we reduce upgrades in the future quarters, upfront reactivation expenses will also come down, moving the average rig expense per day towards a normalized expense per day number of $13,700 over time. We had an average of 149 active rigs under term contracts during the first quarter, and today, that number is 152, or about 64% of our 238 working rigs, as John had mentioned. We expect to continue to have an average of 149 rigs under term contract in the fiscal second quarter, earning an average margin of $11,500 per day. For the average of the 131 rigs we will have remaining under term contract for the rest of 2019, we expect average margins to be roughly $12,000. For the 67 rigs that currently remain under term contract at fiscal 2020 the associated margin is $12,500. We received $2.4 million in early termination revenue in the first quarter, which marked an end to our previously early terminated contracts. We are still assessing the early termination revenue impact from recent cancellations. Turning to our offshore operations segment, we continued with six active rigs during the first fiscal quarter. However, as mentioned on our November call, one rig underwent approximately a 30 days of planned maintenance during the quarter, which reduced offshore revenue days by approximately 5%. The average rig margin per day decreased sequentially due to that same rig maintenance project. As we look towards the second quarter of fiscal '19 for the offshore segment, we have six of the eight offshore rigs contracted. Quarterly revenue days are expected to increase by 3% sequentially due to the completion of that aforementioned maintenance project, but there will be some offset by the lower number of days in the quarter. The average margin per day is expected to decline to a range of $6,000 to $7,000 during the second quarter as one rig is anticipated to be on standby rig for a period of time. Regarding our international land segment, the average rig margin per day in this segment increased by $4,213 to $12,871 in the first quarter. The increase was due primarily to two items: one, the absence of one-time cost incurred in the prior quarter to wind down Ecuadorian operations; and two, the recognition of a prior early termination payment pursuant to contractual terms. As we look towards the second quarter of fiscal '19 for international, quarterly revenue days are expected to decrease approximately 10% as activity in Colombia softened with the recent decline in oil prices. We expect an average second quarter rig count of 17 to 18 active rigs in this segment. Excluding the impact of early termination payments the average rig margin is expected to increase slightly to between $10,500 and $11,500 per day during the second quarter due to contractual price increases associated with certain rigs. Now looking at our H&P Technologies segment. As John mentioned, our new H&P Technologies segment primarily consists of our recently acquired Motive and MagVar businesses. In addition, we are making significant research and development investments, which we believe will result in these services gain increased market share over time. AutoSlide is a near-term example of a commercial offering. While we think adoption and penetration in the market will take some time, we are optimistic about the differentiation this can provide as well as the potential margin accretion of this service and others that will follow. Now, let me look forward on corporate items for the remainder of the fiscal year. At fiscal year-end, our revenue backlog from our US land fleet was roughly $1.1 billion for rigs under term contract, which we define as rig contracts with original fixed terms of at least six months and that contain our early termination provisions. Our current revenue backlog for the US land fleet as of today's call is approximately $1.6 billion, which represents an increase of roughly $500 million since September 30. Capital expenditures for the full fiscal 2019 year are expected to decrease from previous guidance by $150 million, to a range between $500 million to $530 million, based on market expectations today as opposed to the initial budget planning environment at the beginning of this fiscal year. As a reminder capital investment in our fleet is comprised of three distinct buckets. Bucket one contains capital expenditures to upgrade and convert FlexRig's to super-spec capacity, and is now estimated to range between $175 million to $185 million. Much of this first bucket was front loaded in the first and second fiscal quarters. The second bucket consists of FlexRig capital maintenance and is now estimated to range between $165 million and $200 million. Capital maintenance typically averages between $750,000 to $1 million per active rig. The third bucket of 2019 CapEx is comprised of two items; one, fiscal year 2019 catch up on bulk spare equipment purchases to support the increased scale of our super-spec fleet over the last two years; and two, higher capital rig activation cost due to the average idle time of a reactivated rig being closed to for years of stacking. This third bucket collectively will now range from $135 million to $170 million. As John mentioned, our revised CapEx plan is in response to the moderation in demand resulting from the recent decline in commodity price levels. H&P works closely with our supply chain partners to be responsive to market conditions with respect to our upgrade opportunities. Reactivation CapEx is dependent on the upgrade cadence. Ending maintenance expenditures and certain bulk quantities will be correlated to our operating rig counts. Despite the Q1 results, our general and administrative expenses for the full 2019 fiscal year are still expected to be flat from 2018, at approximately $200 million in total. In addition to the US statutory rate, we incur incremental state and foreign income taxes and we are now projecting our annual effective tax rate to be in the range of 26% to 30%. Now, looking at our financial position, Helmerich & Payne had cash and short-term investments of approximately $269 million at December 31, 2018. Including our expanded and extended revolving credit facility availability, our liquidity was approximately $980 million. In our revised fiscal 2019 plan, we will consume a small portion of our cash on hand. Since the November call, we exchanged our outstanding bonds from our H&P Drilling subsidiary to the parent H&P incorporated level as part of a corporate restructuring that more closely aligns our entity structure with our operating segments. Both Moody's and Standard & Poor's moved their applicable credit ratings to the parent level and affirmed our investment grade ratings. Our debt-to-capital at quarter end was between 10% and 11%, the best-in-class measurement amongst our peer group. We have no debt maturity until 2025. Our balance sheet strength, liquidity level and term contract backlog provides H&P the flexibility to adapt to market conditions and maintain our long practice of returning capital to shareholders through our dividend. That concludes our prepared comments for the first fiscal quarter 2019. Let me now turn the call over to Priscilla for questions.

[Operator Instructions] And will take a first question today from Tommy Moll with Stephens. Your line is open.

So, John, I wanted to start on the Technologies segment that you created during the quarter. Leadership in technology has been core to the H&P value proposition for a long, long time, but can you walk us through the strategy to go ahead and formalize this segment? And then, on AutoSlide, you mentioned the plan to commercialize in the Midland Basin over the next few months. Could you give us some details on the ramp phase there and then, longer term, how big of an opportunity you see?

Sure. You're right. We've had a long track record of innovation and utilizing technology to deliver higher levels of value for our customers. FlexRig was an example of that. With the H&P Technologies segment, it's primarily focused on digital and software technology solutions. And there are some service elements to that as well, but it's primarily, like I said, a digital and software technology. And all of those are focused on delivering solutions that drive higher levels of value for our customers. And typically, a little bit different type of technology than what we would typically deliver with FlexRigs and with our traditional offering. So, as we look at using Motive and MagVar as an example of wellbore quality and wellbore placement, but we also want H&P Technologies to focus on delivering those types of capabilities not only on FlexRigs, but we also want to make certain that those technologies are also able to be used on other rig platforms that allows our customers to utilize that single database, if you will, of information using Motive and MagVar as an example. There will be other innovations and technology development in the future. We've got a technology roadmap that we continue to work on and develop. We won't be talking about those today, but all of those things are really directed towards delivering another level of value to the customer. And I think in some respects, like I said in my prepared remarks, Motive and MagVar are - Motive particularly, is disruptive at the rig site because it changes the role at the rig a little bit. But I think at the end of the day, it's the right thing to do in this direction that we need to be heading. As far as AutoSlide, we continue to have good results. We're still working with two customers on AutoSlide. We're working on, I want to say, four or five rigs today. And again, that's an autonomous sliding algorithm and essentially, where we've fully automated that sliding component when we're directional drilling and that's both in the vertical, drilling the curve and the lateral. We still haven't reached full commercialization, but we believe that will happen in the next-month or so, in the next-month or two. We're seeing a lot of - again, a lot of good things that's going on with that. And again, I think it's a great opportunity for us ultimately to get to a more fully autonomous drilling platform.

And if I could ask one follow-up. Just in terms of the potential to differentiate in the volatile macro-environment we've experienced in recent weeks and months, you mentioned in the release yesterday that H&P package across both rigs and related technology continues to grow in importance as drilling becomes more and more complex. On that point and if the last downturn proved anything, it was that customers increasingly wanted best-in-class execution and tech. So while we're nowhere near downturn today, the market certainly has taken a breather and I wondered if you could describe how that may present an opportunity for you guys to once again differentiate versus peers as customers squint closer and closer at cost efficiencies and service quality? And to put a even finer point on it, does it at all change - does the current environment at all change the commercial strategy for the H&P Technology portfolio? Thanks.

Sure, Tommy. Well, there's no doubt that we're continuing to have a lot of traction with our FlexApps, so those Flex applications that we're deploying on the FlexRig digital platform and those are primarily focused on downhole and really allows downhole tools to last longer. It's lowering risk for customers and lowering risk for our employees because we have downhole tools are lasting longer so we're tripping less also. Obviously, the performance is enhanced. So I think we're going to continue to see more adoption around the FlexApps. There is no doubt in a softer market and as we described in our prepared remarks, a really higher volatility market related to oil prices, it's interesting because when you look back in 2012 and 2013, we experienced some similar soft spots if you will. They weren't full blown downturns, they were just a softening in the market. And what we saw in that time was an opportunity for customers to high-grade their fleets and what you saw were a lot of the legacy fleet that continued to get displaced by higher-end AC rig technology both FlexRigs and competitor rigs. I think in today's market with the types of wells that are being drilled, longer laterals, more complex, a lot on the line in terms of drilling these wells, you're going to continue to see the super-spec category of rigs, super-spec FlexRigs and other super-spec rigs high-grading the lower end of the AC food chain and continue to see legacy rigs that are going to get replaced. So there's no doubt that in markets like this, it allows customers an opportunity to look at their fleet and decide how they want to segment their fleet. In some cases, rig counts aren't going to pull back, as I said, with some of our customers. The rig counts are going to remain the same, but they are going to high-grade their fleet and I think that's a great opportunity and that's one of the things that softer markets give us an opportunity to perform.

And we’ll take our next question from Kurt Hallead with RBC Capital Markets.

Thanks for all that color and your perspectives on the market dynamics. I'm curious though and my expectation might've been that even with a flat to a modestly declining rig count environment and a potential shift in spend by E&P companies, if there's going to be a shift in spend towards frac versus drilling, that E&Ps could still do more for their dollar by keeping super-spec rigs active or effectively not seeing a decline in super-spec rig activity. So I don't know maybe we can start there and give me your perspectives on your discussions with the E&Ps and if they're looking about dropping rigs why would they even think about dropping a super-spec rig at this point?

I think the first thing to begin with, because it's a great question and I think one of the things you have to - that we all have to recognize is that there's always a certain amount of churn in our rig count. So, we're constantly getting rigs released and in even the strongest of markets because customers are making decisions spending within cash flow or look for whatever reasons are and you're going to see a certain amount of churn. Now, clearly we've seen more churn in the last couple of months and we have rigs that have been released and we haven't had customers to pick those rigs up on. But when you start looking at how quickly oil prices have moved from 70s, down to low 40s, and now somewhere back in the low 50s again, I think what that causes is some rigs are going to be released because some customers again have a certain budget related to the cash flows they are generating. I think in general as you think about the - which is obviously very important, the pricing element, fundamentally, we still have a very strong market, even though there is some super-spec availability, the super-spec utilization of our fleet today is mid-90%s even with additional releases that are coming over the next couple of weeks, we're still at 90% utilization. So pricing we believe is going to remain strong and we think again there's going to be some additional pullback in activity, but with a strong value proposition, with a strong utilization of the super-spec fleet and with as hard as we've all worked to get pricing to the levels that they are today, again, I think fundamentally pricing is going to remain firm. I think in addition to that, Kurt, I think the rig releases are a result of an expectation in some cases that oil was going to be much lower than where it is today. And so again I think it's an opportunity for us as industry participants to figure out how we're going to work in this more volatile oil price environment. I don't think anybody wants to do the stop and start mentality, where your land rig is down, you're picking Rick's back up. So, I think, there's going to have to be some balance in there. But as I said earlier, I think in this softer market, it gives customers an opportunity once the dust settles on, where they think the oil prices are going, or their budgets are going to be and I think it's an opportunity for them to high -grade their fleets.

So, in the context of the current market environment, maybe how things might have shifted over the course of the past-month or so, are you getting a sense more broadly or getting some unsolicited feedback from your customer base that there's some drillers out there that have panicked a little bit and offering a larger discount on pricing than really needs to be done at this point?

Kurt, I think there's always - in the market there's always a certain amount of rumors and there's usually someone who won't maintain a certain level of discipline or panic. Honestly, the rumors that we hear, most of those are related to much smaller drilling contractors and the lower end of the fleet profile, is the feedback that we've gotten. I don't get an impression that the larger peers with the higher specification rigs are doing that. Again, let's go back to what I began with, which - on the pricing, which is fundamentally, there's no reason for pricing to drop today with the utilization of mid-90%s, and we think it's going to go utilization of 90%. Historically speaking, when you see a utilization of a segment in our rig fleet at 75% to 80%, you begin to get pricing power. So I just don't think that that's going to be the case and the fact is, we don't have any way to verify some of the pricing because we don't provide rigs in that lower end of the legacy rig fleet.

We'll move next to Brad Handler with Jefferies. Your line is open.

Can you tell us about the upgrade cadence in the second quarter, and the visibility you have for the third quarter, please?

And you're talking second fiscal quarter?

Fiscal yes.

Well, as we said on our last call, our expectation, our outlook, if the demand was there, we would upgrade approximately 12 rigs a quarter in Q1 and Q2, and we actually upgraded 14 in Q1. We estimate that we'll upgrade eight in Q2. As Mark described with our reduction in CapEx what we expect now is, and this is with an asterisk, assuming on the demand side if the demand is there for additional upgrades in Q3 and Q4 or just in Q3, we have the capacity to do four to six more upgrades. And again, it's just going to be a function of whether we get the demand from the customer base for that.

Just to add, Brad, that's four to six for the fiscal third and fourth quarters combined and that would be skewed towards the walking rig capability.

Okay. So 14 plus eight plus five is where your heads at today in terms of the total upgrades for the year?

That's right.

Now, let's see, so in your comments yesterday, you allowed - I recognize how hard this is by the way, or well, I probably don't even appreciate how hard it is, but I recognize it. But you said you might exit as low as 223 rigs operating. It sounds like you were - that's not your best guess though, right, the 234, I haven't done the math right, the 234 that you just said seems to suggest that you think it hangs in better than that?

Yes. Brad, I think the way to - you're right. It's not easy to predict the future, and what we have are a lot of data points. And by the way, this is all again underlined by we have an expectation that oil is going to remain in the low 50s, and if that's the case, I would agree with you. I don't think we're going to reach that lower end of the spectrum, but you have to give that range because you don't know for sure what commodity price is going to do. As I said in my prepared remarks, we're seeing less - we're seeing fewer releases and we're having customers asking about rig availability in March and April and startup plans for March and April. So, in that environment, we would think that we're going to be on the higher end of the spectrum, but I think it's our responsibility to give you that range. If oil doesn't - if oil isn't as strong as what we're thinking right now, than we've got you give you some of that downside range, but our bet would be on the higher end of the expectation.

And I appreciate that. And I guess maybe just sort of one more for me, maybe a little more about the customer conversation. With a lot of the customer conversation in January, did it sound something like, we don't know, come back in a month, and we'll probably have a much better sense of what we doing? Or was it more definitive than that, but somewhat more negative and little bit more positive or sanguine? I'm just curious maybe about the level of - just we have no idea, we are still working on our budget versus it's forming and this is what it looks like?

I think it's really a mix. As I've said, again, in the prepared remarks, some are going to increase, some are going to decrease and some are going to remain flat. Clearly, there's still in the formative stages of putting budgets together. Again I think as you look at E&P commentary in general, everyone is struggling with the same thing, which is, what are oil prices going to be, and just how volatile can they be, so how do we base our budget? I think there ultimate ends up being some real-time element to this budgeting process. I've seen some customers that have talked about well of oils $50 to $55, this is our range of $55 to $60, all the way up to $70 to $75. I think that makes a lot of sense right, because you've got to be able to flex up and flex back in order to respond to the market and still be able to spend within your cash flow. So I know it's not a direct answer, but I know there's a lot of solutions that are being formulated. The great news for us at H&P is that, we have a strong customer base. 80% of our rigs that are working today are working for publicly traded E&Ps that have strong balance sheet, that have good acreage positions. It's not that we're not interested in working for the privates, because we are and we do have a lot more rigs working for privates today than we ever have in the past, but the majority of the rigs that are actually working are with the larger public E&Ps.

We'll move next to Marc Bianchi with Cowen. Your line is open.

I guess just to follow-up on the last conversation about the exit rate and rig count. And if oil prices stabilize here, it seems like you could be bottoming HP in terms of your rig count on an average share in this quarter. Would you suspect that that's the case for the broader rig count, or do you think you're taking share?

Well, we know we've picked up some - a little bit of incremental share over the last month maybe. I do think that again different reports that you read a lot of the discussion on the rig releases that have been announced are on the legacy side of the fleet and a lot of the smaller E&Ps, and I think probably a lot of the smaller contractors. Historically, speaking I would think that, we're in a position to continue to capture market share because of the types of wells that are being drilled. And so we're making an assumption; one, that oil prices remain in the low 50s; and two, that customers continue to drill the more complex type wells, and now they have access to an idle super-spec FlexRig that just became idle, that can start up in a moment's notice and go back to work. So that would be our thought. Again back to running the numbers and trying to look at our number of rigs that have been re-leased and look at our market share and if in fact the pundits are right about 100 to 200, and I think we would pick up market share in that environment.

Well if the super-spec rate is firm as you're suggesting, you do have still I think some benefit of contract rolls, so rigs that are coming off, pricing that was maybe set a year ago or year and half ago, rolling to what I think is a higher level today. Mark or John, can you speak to what that should do to the margin assuming super-spec rates remain flat from here? How much of a tailwind is that over the next couple of quarters? Anyway you can give us some help on that would be great.

Sure, Mark, I think maybe we even mentioned in the prepared comments, the increase that we're expecting sequentially moving from the first to the second fiscal quarters does include rollover as you alluded to. It's really worth what's baked into the guidance we release yesterday in the press release. We just had coincidentally a couple of large customer contracts that were tied to a calendar year end and we're starting to benefit from that rollover in the current pricing environment.

So would you say that the sequential change that you've guided to here in the - for the second quarter is maybe higher than what we would see in subsequent quarters just because of that year end issue?

Yes. It's rollover $700 to $800 and it will level out there as we see in the clouded crystal ball as I like to say.

Right. Well one more then for your clouded crystal ball. On the OpEx side, you had mentioned eventually getting back to that 13.7. If activity is more flattish here than maybe prior expectations, is there any way you could put a timeline on getting there for us?

Not a definitive timeline, but as John said, if our read of the commodity price and customer sentiment is correct and we do in fact, have the bottom of the rig count, either occurring right now or just behind us, and we don't have necessarily an appreciable increase, we'll stay at the four to six rig cadence for the - in total, I should say, for the third and fourth fiscal quarters. So if you consider that, as John mentioned, we're going to have eight rigs coming out in the second quarter, the difference between our normalized rig expense per day and the average rig expense per day includes those things for - related to inactive rigs, idling released rigs and reactivating rigs. The reactivation bit has been the higher part of that differential and that will obviously come off more quickly. Again, if we're again towards the bottom, if you will, of the rig count, the idling of rigs will stop. So we'll simply be left with really a bit a few hundred dollars a day roughly really two legacy idle rig maintenance.

We will take our next question from Colin Davies with Bernstein. Your line is open.

I'd like to try and get a little bit more clarity and detail around this transition to the guide on rig counts at the end of this quarter. I mean if I look at the mid-point of the guidance, it looks like something like 16 net rigs coming off and if we've got eight rigs coming in from the upgrades, it looks like something like 24ish potentially effectively coming off contract or being dropped. In reference to the previous discussion, how much of that is existing super-spec's or Flex3s that haven't been upgraded or just other rigs?

75% are super-spec. Did you hear that Colin? Of the 24, about 75% are super-spec. As you can imagine, our largest fleet is our Flex3 super-spec fleet. So that would be - I don't think any - I don't think there's any 5s in there. I think they are all 3s that are all maybe one - so that are all Flex3s that were in the spot market. So, that's --

And it's the same rig that John was mentioning as we look through to the prospects of the sequential quarters, that's March and April interest that we can gauge into this. And further afield, those are - that gives an opportunity to consider scale our international opportunities to move rigs as John mentioned, so we are looking at several different things to concur.

So follows on actually to my next question. Just on international, I think, in the prepared remarks you referred to perhaps some encouraging signs, Middle East Argentine, but I think in the release Colombia was down. What are you hearing from customers and perhaps contrast that what you're hearing on budgets on the U.S. side versus perhaps what some people are saying is most stable budgets internationally? And perhaps run through the countries a little bit and tell us what you're seeing?

Well, the work - and you had mentioned Colombia, the work in Colombia is shorter-term work and we were a little surprised that the rigs were released. I think some of those rigs will go back to work in 2019. As far as the Argentina, Argentina really shouldn't be too much of a surprise, in that, we've got a nice footprint. I think we've got 35% of the horizontal market down there and there's continued opportunity. And we've heard a need for super-spec capacity in Argentina. And so, logically, with the capacity that we have on the ground with Flex3 super-spec then those are logical candidates. If you recall back in 2013, we sent 10 Flex3s with skid systems to Argentina, and those rigs were available because we had that soft pullback if you will come as a result of commodity prices. Middle East in general, I'm really not in the position to talk about specific countries, but in general what we've seen over, I would say, the last several weeks, maybe just in January, we've started to see some inquiries coming in related to opportunities, and still don't have a real good handle on the scale, but again I think; number one, it's encouraging; number two, it's an opportunity to place assets that have recently been idled in the U.S. These are unconventional - best we can tell, these are unconventional type opportunities, so has a nice fit with both our skill set as well as the rigs that we have in the fleet.

And will move next to Scott Gruber with Citigroup. Your line is open.

I just want to circle back on the outlook for the new Tech segment, since we have a new segment to model here. John, can you provide some color on how we should think about growth for the segment over the medium-term? If we think out, say, to the end of fiscal 2019, where could the top line rise to? I know, there's always uncertainties especially with new products, but some color there will be great even if you just want to provide a wide range of outcomes.

Scott, I think at this stage it's hard to give a financial type forecast. Again, we're in an adoption mode as you know. We continue to grow both Motive and MagVar, and then, we also have the commercialization of AutoSlide. And so, all of that great potential, but it is very hard to get your arms around what's the growth profile. Mark, do you have…

Well, yes, we do expect - it's still relatively small in relation to the overall Company, but it's reaching a level for materiality which is part of our considerations in this segment. We do expect the operating losses to narrow as these business technologies do begin to really get some traction as John discussed in his prepared comments. But with the pending commercialization of AutoSlide in the near term and for other competitive reasons, we are not going to give near projections at this time.

That's fine. I understand. Can you talk a little bit just about how we should think about, how the cost structure flexes with the revenue growth? I imagine the incremental should be pretty good, but I just don't have a clear picture on how you guys think about the R&D component and then how the more direct OpEx flexes with revenues?

For the Technologies segment specifically?

Yes.

Yes. It's very margin accretive, the software business essentially.

So we should be thinking very high incrementals, 50%, 60%, 70%?

Yes. Let's say, high incremental margins, but remember, we are still investing through R&D expense. So, through the near to medium term at a minimum those unit margins won't drop straight to the bottom line for the segment if you will, because you have R&D in the middle and the geography on the income statement.

And then I just noticed that the G&A expense is healthy. I know there's probably a big marketing effort around the Technologies, but any color in terms of that line within this segment? How will that trend?

That should be flat as we move forward. Yes, there have been some initial investments in getting the segment stood up, if you will, and combining the previously acquired companies over the trailing 18 months related to some of the - some cost around the acquisition, we have some amortizing cost and G&A but it should be flat. As we have said the company's overall G&A for this year is going to be flat compared to prior year, Technologies fits in that overall guidance.

And then one last one for me Mark. As I look at the reactivation and bulk spending budget - bucket of CapEx, obviously there is a big component there that's not ongoing. Obviously the CapEx related to the reactivation program will fade over time but as I think about that bucket specifically into 2020 there seems to be at least a portion that should be ongoing in terms of some of the larger items and maybe it's lumpy but just how do we think about that bucket beyond 2019 assuming some flattish level of rig reactivity?

I think it's really as we said a one-time catch-up. When we go from just over the course of a couple of years from an average of two pumps per rig with an average of 3, you go from an average of 18,000 feet of tubular complement to 22,000 feet in more per rig which sort of end of catch-up. Once you have that - once we have those component fixed assets and the systems then we put them through the regular overhaul in maintenance routine that gets to the $750,000 to $1 million per rig on an ongoing basis.

So there wasn't any pipe catch-up - pipe spending catch-up as you consumed inventory if this at all related to the step up in pipe for rig?

Step up, yes.

Thank you. And that is all the time what we have for Q&A today. I’ll turn the call back to John Lindsay for closing remarks.

Okay. Thank you, Priscilla. And again thanks to everyone for your interest in H&P, and a big thanks to all of our loyal and hard-working employees the company around the world for working safely, for focus on vehicle safety, and enabling our value proposition for our customers. So thank you again and everyone have a great day.

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