Helmerich and Payne Inc (HP) 2017 Q4 法說會逐字稿

Good day, everyone, and welcome to today's Helmerich & Payne's Fourth Quarter and Fiscal Year-End Earnings Conference Call. (Operator Instructions) Please note that this call may be recorded.

It is now my pleasure to turn the conference over to David Hardie, Manager of Investor Relations. Please go ahead.

Thank you, Chris, and welcome, everyone, to Helmerich & Payne's conference call and webcast corresponding to the fourth 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 up 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 Lindsay.

Thank you, Dave, and good morning, everyone, and thank you again for joining us on our fourth fiscal quarter earnings call.

Fiscal 2017 witnessed the largest ramp-up of U.S. land rig activity in the company's history, which more than doubled even in the face of oil price uncertainty and volatility. We began the fiscal year with 95 rigs contracted in U.S. land. And after reaching trough operating levels of 66 rigs in May of '16, we closed the year with 197 rigs, an increase of 102 FlexRigs, most of which were upgraded to super-spec capacity.

This achievement isn't possible without the advantage of having great people, a family of solutions and over 2,000 rig years of FlexRig experience. This combination allows us to provide the right rig for the customer and has enabled us to grow U.S. land market share to 20%.

The headlines during our fourth fiscal quarter were dominated by oil price uncertainty, which remained range bound in the mid-40s; and skewed expectations toward a substantial rig count reduction for the balance of 2017. Recall that during the summer, some experts were predicting the rig count to decline by 100 to 300 rigs by year-end.

Even with that cautious outlook, H&P was able to grow its rig count and obtain leading-edge pricing due to value proposition we provide to customers. We have also seen improvement in our international markets, where our rig count has increased to 17 active rigs. Looking forward, oil price increases during the past several weeks could provide additional opportunities for rig count growth and higher day rates going into 2018, which should also improve our key financial metrics.

A crucial driver for increased pricing is the limited super-spec capacity we see in the market today. The total super-spec fleet in the U.S. is estimated at 400 rigs and we believe H&P makes up about 40% of that total. The industry's super-spec fleet is nearly fully utilized and demand continues to be bolstered by customer requirements for increased capacity rigs that can effectively drill more complex horizontal wells with longer laterals. We believe the rig replacement cycle persists and that pricing will continue to improve.

Another consideration that needs to be factored in is the tight supply of upgradable super-spec fleet of only around 250 rigs, is what we estimate today, that could be candidates for super-spec upgrades, about half of which are already working. Unlike our peers, H&P has the capability to upgrade over 100 FlexRigs to super-spec capacity. 1/3 of those FlexRigs are already active and H&P has developed a very efficient process to make these upgrades during a rig move.

Of course, demand for additional high-performing rigs will drive our decisions on upgrades. We are optimistic that drilling economics will improve for E&Ps and that they will support the higher day rates and longer-term contracts that we will require to make these upgrade investments as market conditions improve. That said, the key takeaway here is that H&P is uniquely positioned to grow its active rig count without building new rigs, whether that be under improved commodity pricing or the range-bound pricing we've experienced most of this past year.

Another critical driver of improved pricing is our ability to deliver on an attractive value proposition for our customers. We see our value proposition measured by performance and reliability that delivers a lower-cost well. The super-spec classification provides the rig capability needed for the more complex and long-lateral wells, but performance, reliability, data and leading technology also play crucial roles in the value equation. You really need those capabilities in order to deliver the best performance for customers.

One critical support system we have developed to enhance reliability is our Center of Excellence for safety, learning and performance. The Center of Excellence is in its fourth generation and we started up the first gen in 2004. We've been utilizing high-speed data generated from the rig and leveraging the Internet of Things creative processes for years.

We use several IoT tools developed for the Center of Excellence to proactively monitor rig equipment and operations by acting upon conditions, patterns and recurring trends. An example of this is our critical alarm and maintenance dashboard, which provides complex event analysis based on real-time streaming data. The dashboard facilitates a more focused and prioritized approach to preventative and condition-based maintenance. And really, what that effectively helps us deliver is better uptime and less downtime on the rigs.

We use similar tools for all of the performance metrics that are vitally important to adding value for customers like drilling performance, rig moves and trip times, to name a few. These are just some of the ways that technology and data are changing our business. Having a uniform fleet offers a significant competitive advantage over our peers as we are able to capture and leverage important data that is transforming the business.

Another technology we are excited about is our acquisition of MOTIVE Drilling Technologies in June. The integration process is going smoothly, and we are seeing increased interest by E&Ps and directional drilling companies. MOTIVE has recently surpassed 4 million feet of hole using their bit guidance system to provide customers with drilling performance enhancements as well as more consistent and accurate wellbore. This leads to both short-term economic improvements to drilling cost, but perhaps more importantly and impactful, can lead to enhanced production over the life of these wells.

It's important to keep in mind the bit guidance system isn't a downhole tool, it's a software solution, and therefore, H&P isn't competing in the traditional directional drilling business. With the pace of drilling today, in some cases directional drillers are struggling to keep pace with increased drilling speeds, while delivering the accuracy required to place a wellbore in the desired sweet spot to maximize production. MOTIVE is currently active on 15 rigs, and 5 of which are FlexRigs, serving 10 customers, with several additional rigs scheduled to pick up through the remainder of the year.

As we look to the future, we expect an ongoing trend to more complex well trajectories with tighter well spacing and longer lateral lengths, resulting in the need to enhance control of wellbore placement and quality. We are optimistic about the future with MOTIVE as they represent a disruptive technology for directional drilling execution and providing significant value to customers.

So before turning the call over to Juan Pablo, in addition to having the right rigs, we have great people who are developing and harnessing leading-edge systems and technologies to support our value proposition to the customer, and I'd like to take this opportunity once again to thank every one of them for their outstanding service.

And now I'll turn the call over to Juan Pablo.

Thank you, John, and good morning, everyone. I will expand on some of the announced information on each of our 3 drilling segments, followed by some comments on corporate-level details.

On our U.S. land drilling segment, let me first highlight some of the details related to our growth and activity during the last few months. Since the last earnings call in July 27, 2017, our activity has increased by 11 rigs. The Permian again led the way with 7 rigs, followed by 3 in the Eagle Ford. We also experienced minor up-and-down movements in other basins.

We have added 10 new customers since the last call as a result of the great performance that our organization is delivering. Our 3 most active basins today are the Permian, the SCOOP and STACK play and the Eagle Ford. The Permian remains our most active operation, with 98 rigs contracted compared to 85 rigs during the 2014 peak. We have 46 idle FlexRigs in the area, 25 of which have 1,500-horsepower drawworks ratings.

In the SCOOP and STACK and Eagle Ford today, we have 31 and 29 rigs contracted, coming off a low of 15 and 16 contracted rigs, respectively.

As for the overall U.S. land segment results corresponding to the fourth fiscal quarter, we exited the period with 197 contracted rigs and had an increase of approximately 6% in total quarterly revenue days. Most importantly, we continued to experience growth in activity from beginning to end of the quarter and now expect a similar trend for the first quarter of fiscal 2018.

In general, increasing pricing in the spot market offset the decreasing proportion of rigs under long-term contracts that were priced years ago during strong markets. As a result, the adjusted average rig revenue per day remained flat at around $21,700 during the 2 most recent quarters.

The average rig expense per day decreased by over 2% to $13,905, mostly driven by a lower number of reactivated rigs generating upfront expenses as compared to the prior quarter. The average rig expense per day for the quarter was slightly higher than originally expected, primarily as a result of the higher-than-expected level of activity and the number of previously idled rigs that returned to work after many quarters of inactivity.

Looking ahead at the first quarter of fiscal 2018, we expect a sequential increase of approximately 4% to 5% in quarterly revenue days. We expect the adjusted average rig revenue per day to remain relatively flat at approximately $21,700 as the underlying dynamics of new-build term contract roll-off and increasing spot pricing continues to offset one another.

Although our average day rate in the spot market is still in the high teens, leading-edge FlexRig pricing is in the low-20s. Thus, we continue to experience spot pricing improvement while delivering great value to customers through our differentiated offering. Our customers clearly understand how FlexRig performance and reliability levels allow them to lower their total well cost and to attain a higher-quality wellbore.

The average rig expense per day level is expected to slightly increase to roughly $14,100. The expected increase is primarily attributable to expenses related to moving all 5 of our rigs in California to Texas in efforts to reduce overall expenses in the segment going forward and move the rigs to better markets. Those 5 FlexRigs have been idle for some time and are very well suited to go back to work in West Texas in the near future.

The average rig expense per day directly related to rigs that are already working in the U.S. land segment continues to be around $13,000 per day. This general estimate excludes the impact of expenses directly related to inactive rigs and upfront reactivation expenses related to rigs that have been idle for a significant amount of time.

Approximately half of our 200 contracted rigs today are under term contracts and roughly 40% of those rigs under term contracts were priced during strong markets before the 2014 downturn. The remaining rigs under term contracts were priced during the downturn and have a remaining average duration of less than 1 year. As a result, the expected average rig margin per day for all of our rigs already under term contracts in this segment during the first fiscal quarter is roughly $11,000.

Given the changing mix of term contracts that are currently in the backlog as a result of our success in securing over 30 rigs under new term contracts since our last call in late July, the expected annual rig margin per day averages for fiscal 2018, fiscal 2019 and fiscal 2020, corresponding to all of our term contracts in the segment, are now roughly $11,000, $12,300 and $15,500, respectively. The average number of corresponding rigs that we already have under term contracts for each of those 3 years is approximately as follows: 80 for fiscal 2018, 30 for fiscal 2019 and 7 for fiscal 2020.

No early termination notices for rigs in the segment have been received since mid-2016. But given prior notifications, we expect to generate approximately $4 million during the first fiscal quarter and a total of approximately $10 million during the following 4 quarters in early termination revenues.

Let me now transition to our offshore operations. The number of quarterly revenue days decreased by approximately 10% and we exited the fourth fiscal quarter with 5 contracted rigs. The average rig margin per day increased sequentially by about 5% to $12,088. Management contracts contributed approximately $2.5 million to operating income, which was lower than expected as a result of some adjustments to our self-insurance reserves related to these contracts.

As we look at the first quarter of fiscal 2018, quarterly revenue days are expected to decrease by approximately 6%, with 5 rigs contracted during the quarter. Average rig margin per day is expected to increase to approximately $13,000.

Moving on to our international land operations. The adjusted average rig margin per day in the segment increased by 38% to $12,386, primarily as a result of favorable onetime adjustments. The number of revenue days for the quarter was 1,291 or an average of 14 contracted rigs. We exited the quarter with 16 rigs, including 13 in Argentina, 2 in Colombia and one in Bahrain. The favorable impact of these improvements in adjusted margins and activity was partly offset by $3.7 million in foreign exchange expenses incurred during the quarter.

As we look at the first quarter of fiscal 2018, quarterly revenue days are expected to increase by approximately 20%, potentially exiting the quarter with 17 active rigs. We were very pleased to see the significant level of uptick during the quarter, which was driven primarily by an agreement for 4 rigs going back to work in Argentina. We don't have any set commitments to expand our international activity beyond the mentioned 17 rigs as we enter calendar 2018, but do expect to see some opportunities for potential activity expansion going forward.

The average rig margin per day is expected to be approximately $8,000. This average rig margin per day may be higher as a rig rolling off a long-term contract is not recontracted. As in that case, we would benefit from demobilization compensation during the quarter.

Let me now comment on corporate-level details. Fiscal 2017 provided attractive opportunities to continue to add even greater capabilities to our existing FlexRigs. During that year, we upgraded over 90 rigs to specifications in highest demand, increasing the number of rigs with super-spec level capacity to over 150 in our U.S. land segment. We also acquired a small company, MOTIVE Drilling Technologies, as we continue to look for ways to increasingly add value to the customer.

As John described, we hope to see similar type of investment opportunities during fiscal 2018. Although early CapEx estimates for the year are currently in the range of $250 million to $300 million, we expect to see further improvement in market conditions and additional attractive opportunities to invest in the business. Our balance sheet strength and high liquidity level provide great flexibility in pursuing these additional opportunities, while at the same time, sustaining current dividend levels.

A few more references that may be helpful for modeling purposes. First, maintenance CapEx, including tubulars, represent close to 40% of our current CapEx estimate for fiscal 2018. Second, our $560 million depreciation estimate includes approximately $20 million in abandonment charges. The latter may significantly fluctuate as a function of the volume of rig upgrades as the replaced equipment is abandoned. And last, the effective income tax rate is expected to be around 32% during fiscal 2018.

Let me now turn the call back to John.

Thank you, Juan Pablo. We've commented for some time that a significant factor related to the ongoing rig replacement cycle is the number of legacy rigs still drilling unconventional horizontal and directional wells. That figure continues to dwindle, but today, there are still approximately 240 legacy rigs drilling in U.S. land. Approximately 155 of those are SCR rigs and the remainder are mechanical rigs. When you consider how technology has changed the drilling process over just the past few years, 1970s technology is seriously deficient in its ability to deliver the high levels of performance and reliability demanded by customers who will be drilling even more complex well designs in the future. So we see that, again, as an opportunity going forward.

And Chris, now we will open the call for questions.

(Operator Instructions) And our first question comes from Kurt Hallead with RBC.

So gentlemen, I think you provided a pretty upbeat, optimistic outlook heading out of this year, going into next year, especially the sharp contrast to, as you mentioned, the expectations in kind of the midyear dynamic. So with that said, I've also noticed that the incremental rigs that you've been able to place on the term contract, relative to what you had shown back in the September time frame, kind of slowed a little bit. You guys, what would you chalk that up to in your mind? Is it that the E&P companies kind of going through their budgeting process and kind of getting a read on what they need -- may need in '18? Or do you think that E&Ps are again maybe getting ready to hit the pause button?

Kurt, this is Juan Pablo. Are you referring to the 30-plus rigs that we were able to place under new term contracts as we continued to increase our rig count and as we continue to see roll offs from old term contracts?

Just as one example, right? I mean, back in early September, you indicated that there may be an average of 59 rigs on term contract for fiscal '18. In early October, that number jumped up to 75. And now in mid-November, we're looking at 80, right? So I'm not trying to nitpick, I'm just trying to gauge as to -- you saw a significant surge in incremental contracts between September and October and a bit of a slowdown in that process going into November. So just wanted to see if there's anything to read into that or not.

This is Juan Pablo again. We don't see anything significantly different as compared to what we may have expected, Kurt. It's a combination of the market being relatively strong for FlexRigs. And as we continue to upgrade our fleet, customers, on the one hand, being willing to enter long-term contracts. And when we say long-term contracts, these are 12 months, 18-month type contracts in general, and our willingness to do that at the same time while we're investing in some of these upgrades. So we think it's a win-win situation. But again, it's nothing that surprises us significantly.

Okay. And John, a question for you is, you look at the opportunities. Just wanted to make sure I heard you correctly when you referenced you have the most rigs that could be potentially upgraded to super-spec capability. And then you went on to say, even if the market, rig market, remained flat -- did I understand that correctly, that you guys would still expect to increase your market share and upgrade assets even in a flat rig count environment?

Yes, Kurt. I think we've been talking about that now for a while. I think we've been able to demonstrate that kind of in a flattish, slightly down, I guess it depends on which rig count service you're looking at. But in general, over the last quarter, the rig count's been relatively flat, and we've been able to continue to add to our active fleet as well as continue to upgrade rigs to super-spec. And again, we've got our market share up to 20%. I do think that the rig count that we've seen over the last quarter is a function of an expectation of $45 to $50 oil price or mid-40s type oil prices. Obviously, oil prices have improved significantly over the last several weeks. We're not necessarily expecting or have a belief that it's going to remain there. But if you do see that outlook change toward an expectation of higher oil prices, then I think, in some cases, you may see, not a dramatic improvement in rig count, but I think maybe a continued improvement in rig count. And with that, what we've seen is a pretty high level of churn related to contracts and working for different customers. And I think customers in that sort of an environment, where they're focused pretty heavily on capital discipline, they're going to be looking at getting the best services and the best performance that they can get. And so if you're drilling more challenging wells and you don't have a rig that is super-spec capable, you've got some opportunity to improve your drilling times and lower your cost by having a higher-capacity rig. So I know it's a long answer to your question. But yes, I think in general, we feel pretty confident that we can continue to grow our fleet and take some market share because of the value that our folks are able to provide in the field.

And what do you think the market price would have to be to economically justify a new build?

Well, I'm not certain what a competitor's new build would be. I've heard estimates of low $20 million range. I think if that's the case and if they're going to get a reasonable rate of return on that investment, I think you're going to need a $26,000 or $27,000 a day, day rate in order to get a reasonable rate of return. And again, I would think you'd want to have a multiple-year term contract.

And Kurt, let me add a little bit more granularity on your prior question as relates to term contracts. Part of the consideration is that our fleet in the U.S. land segment has been more or less 50% under term contract, 50% in the spot market. That metric has remained relatively flat, so that is not surprising. The other consideration as well is that as availability of the right type of rig, as John mentioned, becomes tighter, customers are more willing, and as a matter of fact, requesting to enter into term contracts. So the combination of those 2 things, I believe, is what leads to what we saw, and thus, is not surprising, given market conditions.

And our next question comes from Colin Davies with Bernstein Research.

The tone, obviously, is far more positive than a quarter ago, where the narrative was much more cautious, and you alluded to that in the prepared remarks. We have to talk about the dividend. And you did emphasize at the closing of the prepared remarks that you're anticipating to be able to hold the current level of dividend through next year. Is it fair to say that those more cautious comments that you made on the last call, that's really been put to one side now in terms of the financial plan going through for next year?

Well, Colin, this is John. I'll let Juan Pablo make a few remarks on this as well. He'll have some additional color. But I think in general, you look back and you just look at oil prices, I don't remember what oil was trading in that -- during that week, but I remember we had some low-40s and mid-40s. And I think just the general outlook, obviously, was challenging. At the same time, we also had a belief that the rig count was going to remain relatively flat, even though there were folks that were saying look for 100 to 300 rig count pullback. And we didn't believe that. We didn't see it coming from our customers. Obviously, it could have happened if oil would have remained in the low-40s or gone into the 30s, which I think a lot of people were thinking. But I think in general, just as it relates to our outlook, yes, with the oil prices that we've seen, not even necessarily $55, but just closer to $50, having some of the things in the market that just looking more positive. But we've continued to say that we believe we can continue to fund the dividend for the foreseeable future. We have a lot of confidence in that. We have a belief that, of course, this is a cyclical industry, and at some point in time, you would see the other side of the cycle. All we've seen for the last 2.5 years, of course, 3 years, is a downside to the cycle. And we believe there is an up cycle, an improvement in the future. And again hopefully, we're on the front end of that. But even if we're not, even if it's not in the next 6 months or year, I think we're still well positioned. Juan Pablo, would you add anything more to that?

I think that covers it well, John. Thank you.

That's great. And then just one follow-up on the CapEx guidance for next year, the $250 million to $300 million. You sort of implied that 60% of that is upgrade CapEx beyond the maintenance CapEx. What should we be assuming in terms of upgrade cost? And sort of the scale of upgrade that's being constructed into that $250 million to $300 million plan?

Colin, this is Juan Pablo. To your first question, I think that most of the 60% is attributable to upgrades in general. As we look forward and look at the opportunities at hand, there are several things that we considered. One important consideration is lead times for certain components, make sure that we are not constrained with bottlenecks and that we have the capability to quickly respond to market conditions, as we have in the past. And so part of what you see there is us just making sure that we're well prepared to respond to improving market conditions. Another part of your question related to upgrade cost per rig. As you have heard us say before, as we upgrade our standard FlexRig3 rigs and add pad drilling capability through skidding systems and 7,500 psi systems in general, that type of upgrade can be a $2 million to $3 million per rig upgrade. We've also introduced some walking systems. So instead of the skidding capability, we add a walking system and also a 7,500-psi system. That type of investment is significantly higher at closer to $8 million. But what we've seen in the past is, again, a much higher number of skidding-type upgrades as compared to walking. So that gives you a sense of how we're looking at upgrade costs. In both of those type of scenarios, we have found that our expected returns on incremental CapEx or investments on those rigs is very attractive, especially of course, on the skidding upgrades to super-spec capacity. Does that answer your question, Colin?

Yes, I think it does. I was trying to just get at the extent to which you're seeing any mix shift between the more expensive upgrades and the skid-able upgrades as you're seeing the market pull from that. And also to the extent as a company in the plan leaning forward on building, perhaps, an inventory of upgraded ready-to-go rigs so that you can respond to demand.

Yes, Colin, it's a great question. I think it's -- with the outlook, I mean, let's face it. The outlook remains fairly uncertain with where oil for sure is going to go. We've got the OPEC meeting upcoming. We don't know for sure what the outcome's going to be there. But again, I think in the oil price range that we've talked about, we think we're going to have the ability to continue to upgrade. Just to kind of -- to give you an example from last year, of course, we upgraded over 90 rigs and I think we averaged 20 -- 22 a quarter with a range of anywhere from 12 upgrades to 38 upgrades per quarter. Clearly, we're not going to be doing anything on the 38 end, but 12 is reasonable. I mean, it's possible for us to do that. But as Juan Pablo said, we're not just going to -- I guess to answer your question directly, our intent is not to upgrade rigs on spec with an expectation that the market's going to improve. I think we have the capability to respond much more quickly than others. And having the CapEx that we've talked about enables us to prepare the supply chain, if you will, to be able to respond. And if we see an improving outlook going forward in the next quarter, then we can ramp our cadence up, very similar to what we did with new builds in the past, where we would start with 1 or 2 rigs a month. And when we saw demand, we were able to scale up to 4 rigs a month. And it would be the same thing with the upgrade if we saw that sort of a demand.

And our next question comes from Marc Banichi (sic) [Bianchi] with Cowen.

Following up to the upgrade questions, Juan Pablo, I just want to clarify. You said $2 million to $3 million, sounded like, for the basic upgrade. And then it could be as high as $8 million. Is that an additional $8 million so we should be thinking $10 million to $11 million as sort of the high end? Or was that all in for $8 million?

Marc, it is all in. But just to clarify, we are only adding, in some cases, walking systems to rigs that don't have any type of skidding or pad drilling -- multiple well pad drilling capability. So we would never take a rig that already has a skidding system and add a walking system to that. Hopefully, that clarifies the question.

Yes -- no, that is helpful. I guess, on the context of your earlier comments, prepared comments about 250 upgrade candidates in the marketplace. What do you think the average upgrade cost is for those? Because if we go back maybe 3 or 4 quarters to what you and some of your peers were saying, it sort of sounded like most of the rigs to upgrade were in the couple, $3 million range. And now here, we're hearing from you guys and we've heard from some others that there's this higher $8 million to $10 million for maybe the next layer of rigs to be upgraded. Do you have any comments on the -- kind of the market overall?

Yes, Mark, it's a great question. We only really know, of course, what our upgrades are. And again to be clear, $2 million to $3 million is our skid system and 7,500 on base -- on a base FlexRig3. And then the $8 million is to go all in on the skidding system -- or pardon me, on the walking system. And so what we're trying to do is develop some demand on that walking system. And we think that's going to -- we'll see probably more of that as we go forward. But we haven't seen a huge demand pull. But I think in general is -- you're right. The upgrades, as you get into the back end of that 250 rigs, the upgrades are going to be higher. You see some of our peers that are upgrading 1,000-horsepower AC rigs to 1,500-horsepower, and those are $8 million to $10 million investments, and they have a relatively small number of candidates in order to do that. So that's what we like about our position, is that we have the capability to ramp up quickly. We have a big inventory. But as I said earlier, we're not going to do that on a speculative basis, we're going to do that based upon customer demand. Of the 91 upgrades that we did, 3 of the 91 were walking systems last fiscal year. So going forward, we haven't really announced what our cadence would be. But we'll -- I would imagine we'll have more skid system upgrades than we will the walking upgrades. But again we're going to base it on demand from the customer.

Do you see -- does it seem reasonable that you could execute all this CapEx for upgrade if the rig count's flat and if day rates are flat? Does that still kind of work for you?

In terms of the CapEx that we've announced, is that what you're asking?

Yes. I mean, I guess it kind of works out to about $165 million of nonmaintenance for these upgrades. Does that get executed if the rig count, overall rig count stays flat and kind of day rates stay flat, I mean, albeit in the low $20,000 range for you guys?

Yes. I think in the case of low $20,000 with some term contract commitment, not doing that on a well-to-well basis, that we would have some interest in continuing to add some upgrades into the market. I think the other thing to consider -- and this was, again, part of our prepared remarks. And you won't be surprised, you've heard us talk about this before. But there is still that legacy fleet out there that's drilling these wells. Now I don't know -- or drilling horizontal wells and directional wells. Now I don't know if they're drilling the longer laterals. But as this trend towards longer laterals continues, I think the average lateral is still around 7,000 feet. What we've seen is when lateral lengths get to 7,000 to 8,000, that's when you begin to see the traditional 5,000 psi systems and -- begin to be stressed. So I think as these legacy rigs are asked to drill longer laterals, that's an opportunity for super-spec upgrades. And again, maintaining even a flat rig count environment, but you've got high-grading that's going on that's kind of embedded, it kind of speaks to that churn that we talked about earlier.

And our next question comes from Thomas Curran with B. Riley, FBR.

John, I'm sorry if I missed this in your introductory remarks. But where would your team currently place the industry's existing super-spec fleet? How big is it as of today? And then on the new-build side, what's your current tally or estimated range of the number of new builds that remain in the industry construction queue?

I'm not certain about the new build. Dave, do you have any feedback on the new build? It's been a -- it's a relatively small number. I'd say. Yes, I was going to say 10, I was going to say 2 handfuls. So about 10 that we hear about. I think, depending on the definition of super-spec, in the purest definition, the way we've outlined super-spec, we think there's around 400 that are active today in U.S. land. And I think there's -- if you add in some other categories, it could be as high as 450 to 475. Total AC rigs running drilling horizontal and directional wells is close to -- according to the rig data, is close to 900 rigs. So about half of the AC rigs that are running today, we believe are -- close to half are upgraded to super-spec. And then there's another 250 that we think are upgrade candidates. We know we have 109 of those that we know are upgrade candidates. The others, again, we're just kind of looking at base model designs and making the assumption that those rigs can be upgraded. And if I'm not mistaken, the 250, about half of those are working. So of the 250, about half of that upgradable fleet is actually working today.

That's exactly the perfect super-spec supply-side summary I was looking for. And then turning to Argentina, hasn't gotten much attention lately for some obvious reasons. But on the back of YPF's recently announced plan to spend $23 billion over the next 5 years and the passage and sort of sigh of relief coming out of the elections, what are your expectations there? Have you seen or do you expect to see new opportunities arise? And if so, would you be interested in them?

Yes. I think there is some opportunities. It's funny how this international market can change pretty quickly just like the U.S. market can change pretty quickly. It's nice to see our international rig count increasing. And again, a big portion of that's been in Argentina. So I do think that there's some additional opportunities for us. If you recall, we sent the 10 Flex 3s to Argentina for YPF several years ago. Those were all FlexRig3s with skid systems. And so, again, I think we have the -- we always have the rigs on the ground here and the capability to do that if the demand is there and the right contract and the right rate is there. Again, our rigs has done a great job drilling, so I think we'll have some opportunities.

And then I'll squeeze in one more here. What is the CapEx allocation for MOTIVE in 2018? And what are the catalysts, if any, that might lead you to decide to meaningfully step that up?

Well, the CapEx, if you look at it as it relates to rigs, it's just very, very minimal. It's -- I'm not even sure. Juan Pablo?

Yes, it's insignificant.

Yes. I mean, it's -- again, the great news for us is it's really a software company. And the CapEx requirements are very, very low. And so that's one of the things that's really compelling about their business model. So I wouldn't expect it to be a needle-mover.

And our next question comes from Brad Handler with Jefferies.

Maybe some small questions first. The low-20s day rate that you cited, John, is that for a super-spec rig, so having that 7,500-psi mud system, for example, and other bells and whistles? Versus something that is super-spec-able?

Yes. The low-20s is a super-spec rig. So it has the super-spec upgrades.

Okay. Got it. You've had this nice experience of customers saying, "Let's just get to work and then we'll upgrade on the fly." And you've talked about -- you've talked to us about your ability to do that. Do you sense that, that's still the -- sort of the primary way customers are contracting with you? Let's get going and then we'll upgrade as we can. Or is it shifting to, I'd like to actually get a super-spec rig, so please, put the investment in now and then we'll start?

Well, Brad, for the most part, the customers that wanted super-speccing -- and go back to, if you heard my earlier comments related to super-spec. We've put out 91, about 22 or so a quarter. Most of those, the customer wanted the super-spec upgrade prior to taking the rig. And so what happened though is once we kind of outran the capability of our cadence, that's when customers said, hey, I'll go ahead and I'll take the rig now and we'll upgrade it in a month or in 2 months, whatever time period. So I think again today, we're not at near the cadence that we were then. I think in most cases, we're able to make the upgrades prior to the rig going to work. Not in all cases. But I think to the heart of your question, if it's a longer-lateral, higher-complexity well, by not having some of the super-spec upgrades, primarily on the pumping side and sometimes on the top drive side, top drive horsepower side, then you're put -- you actually are putting the wellbore at risk if you don't have those capabilities. So I think it's kind of at that type of a trade-off. I think it depends on how long the laterals and how challenging the wells might be.

That make sense. Okay, I get that. Okay. Juan Pablo, on the OpEx side, please, in the U.S. onshore. Is it reasonable for us to think about some sort of pro rata stepping down over time? Let's just say hypothetically, you exit fiscal '18 at 250 rigs working, for example. Could we think about operating expense being something like $13,250? In other words -- right, because there's less allocating, there's less inactive rig costs and there's -- I'm sort of obviously taking out the reactivation time. Is that the logical way for us to think about getting down to your underlying per-rig OpEx?

I think that's very reasonable, given the assumptions that you mentioned. We'd probably in that scenario have some idle rigs still out there. And so the 250 given that level of activity sounds reasonable. Meaning, the 250 over the $13,000 average.

Right, right, right. Okay, that's helpful. Just I felt like I hadn't had a placeholder on that. And then maybe the last one, and I don't mean to cheat or something. But are you charging for MOTIVE services today? Or would you say that the rigs on which it's working are still in trial mode? Could you just give us a status update there?

Yes. MOTIVE is working as they were prior to the acquisition. And so yes, they are -- charge at different business models in terms of how they charge. But yes, they are charging for their services and there's varying levels of the product that they provide, if you will. And so there's different levels of charges depending upon what they're providing. So it's not part of -- it's not thrown in on a FlexRig, it's not just part of the offering. And again, I think it's important to note that the MOTIVE activity today, 1/3 of the work is on FlexRigs, the rest of it is on peer rigs.

Right. And that's -- you will remain open to using third-party rigs, I imagine, right?

Yes. We said it from the beginning that they -- our intent is to keep them kind of in -- to keep MOTIVE independent. And we're kind of agnostic as to where they work. And again, they're working for E&Ps. Their customer base are E&Ps and directional drillers. And it doesn't matter to them whether they're on a FlexRig or brand X.

Chris, we probably have time for one more question.

And our last question comes from Waqar Syed with Goldman Sachs.

My question is regarding working capital. What do you expect for working capital changes in '18? Do you see that a source of cash or a cash beat, if you assume kind of a flattish rig environment going forward?

Waqar, this is Juan Pablo. We would expect that to -- we would expect the working capital requirement to increase. So that would probably be a use, given that we have a relatively optimistic expectation in terms of what happens going forward. But given your assumption, which is relatively flat, then working capital requirements may stay relatively flat as well.

Okay. Alrighty. And then, your offshore management contracts, how long should we expect those revenues and margins to continue?

We have 5 -- you referred to the offshore?

That's right, yes.

Yes. We have 5 rigs that are currently working. I believe that most of those, 4 of the 5 are under operating day rates. I believe we have 1 still is under standby type day rate. So nothing necessarily expected to change significantly going forward. There are some opportunities ahead and we may see some movement there, but I'd be speculating if I mentioned some numbers. I think assuming that what we expect to see in the first fiscal quarter may recur probably makes sense.

The $4.5 million management contract margin that you have in the December quarter, you think that could reoccur again in the following quarters?

We expect -- yes, we expect $4 million to $5 million in cash flow from management contracts during the quarter. And hopefully that, again, recurs going forward at least for the foreseeable future.

Now your international margin guidance about $8,000. Is that the new normal? Or it's still has some load utilization cost embedded in that, so it could get better in the future quarters?

Well, we would certainly hope to see improvement there, assuming that we continue to see increase in activity. But given that we don't have any secured commitments, as I mentioned, we expect to exit with 17 rigs approximately. And that would be a first fiscal quarter exit entering calendar 2018. And so if everything stays more or less as it is, I think that the assumption of the margin that we guided toward for the first fiscal quarter is fair to assume for following quarters. Again, we hope to do better. But at this point, we have nothing to announce in terms of additional contracts.

And then just one final quick one on taxes for next year. You mentioned 32% tax rate. How do you see cash taxes versus reported taxes?

We probably will see our deferred income tax liability come down slightly. So the tax benefit will suffer some, but not in a significant way.

Well, I want to thank everyone again for participating on the call. I want to close by emphasizing again that our spare fleet capacity, combined with our strong balance sheet, gives us great flexibility to invest in the fleet and complementary technologies to meet customer needs and provide value to shareholders.

We remain confident about the future for H&P because our competitive advantages reside in our people, performance, technology, reliability and our uniform FlexRig fleet.

So thank you again for participating and have a great day.

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