Helmerich and Payne Inc

NYSE:HP

Earnings Call Transcript 2018-Q1

[Operator]

Good day, everyone, and welcome to today's first quarter earnings conference call. [Operator Instructions]. It is now my pleasure to turn today's conference over to Mr. Dave Wilson, Manager of Investor Relations. Please go ahead, sir.

[Dave Wilson, IR]

Thank you, Lynn, and welcome, everyone, to Helmerich & Payne's Conference Call and Webcast corresponding to the first quarter of fiscal 2018. With us today are John Lindsay, President and CEO; and Juan Tardio, Vice President and CFO. John and Juan Pablo will be sharing some comments with us. After which, we'll open the call for questions.

As you know, 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 be - 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 calculation in today's press release.

With that said, I'll now turn the call over to John Lindsay.

[John Lindsay, President, CEO & Director]

Thank you, Dave, and good morning, everyone. The new tax law had a significant and positive but noncash impact on our income this quarter. Better still, the H&P team executed on our plans, delivered on the value proposition to our customers, and operational results exceeded expectations in the first fiscal quarter.

The downturn has been a challenging three-year journey, and H&P has been preparing for the opportunity this improved outlook presents for 2018 and beyond. There are three main areas I'd like to highlight this morning. First is the industry-leading success we've had in upgrading our FlexRig fleet to super-spec in order to provide the right rig for our customers. Second, the pricing power we are seeing as a result of the performance the FlexRig super spec fleet is delivering, which is the reason customers are willing to pay for the value proposition. The third highlight I will cover is the digital evolution that continues to be an important part of our industry's future and the fact that we are a leader in utilizing data to deliver performance.

The recent motive in MagVAR acquisitions during 2017 create powerful software platforms that will position us to be even more successful going forward. So let's begin with the industry's super-spec fleet being essentially fully utilized in U.S. land with approximately 400 rigs active today. We define super-spec rigs as AC drive, 1,500-horsepower, 750,000-pound hook load, pad capability and 7,500-psi mud systems. H&P currently has 171 super-spec rigs operating at approximately 98% utilization. We believe there are another 200 to 250 rigs in the industry where upgrades to super-spec capacity would be economically feasible, and H&P owns roughly half of those.

Of our upgradable fleet, approximately 30 FlexRigs are currently active today and can be upgraded to super-spec status in the field with a $2 million to $3 million investment. The FlexRig design allows H&P to reinvest in our fleet to enhance rig capabilities that will benefit our customers in the areas that require well designs which are more challenging and complex. In fact, since the first fiscal quarter of 2017, we have upgraded 107 FlexRigs to super-spec capacity. If customer demand remains and we're able to achieve reasonable pricing, our upgrade cadence could average 12 or more FlexRig upgrades per quarter.

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. This successful strategy has allowed us to grow market share from 15% to 20% in the U.S. land fleet and over 30% in the AC drive market.

But not every customer needs a super-spec rig, and we continue to contract previously idled rigs as well. Our ongoing effort to provide the right rig from our family of solutions for our customers enables H&P to serve a wider segment of the market and further enhances market share.

The second point I want to make is that pricing in U.S. land is led by super-spec rigs, and the main driver in rig pricing today is the near full utilization of the high-capacity super-spec U.S. land rig fleet. The primary reason customers want super-spec rigs is the fact that lateral lengths have increased to the extent that this is pushing the limits of the standard AC drive rig fleet.

In fact, in 2017, the average lateral increased another 15% to approximately 8,000 feet, and we expect this trend of longer laterals to continue. As a reference point, the average lateral in 2015 was approximately 6,000 feet. H&P has over 40% of the active super-spec rigs, and with the industry fleet fully utilized, we expect to be able to continue to realize pricing improvements. Again, the potential for margin expansion, coupled with our having approximately 100 rigs readily upgradable to super-spec status, gives the company excellent prospects for continued growth going forward.

The super-spec classification FlexRig provides the rig capability needed for the more complex and long lateral wells. Delivering on the performance and reliability required today means having the right data and technology that are crucial to maximize value for our customers.

The final topic I'd like to highlight is that we are making great strides toward becoming a bigger participant in the industry's digital evolution. For the past 10 years, our uniform fleet of AC drive FlexRigs has enabled us to utilize high-speed data generated from the rig and leverage IOT tools to enhance efficiencies and reliability. The MOTIVE Drilling Technologies and MagVAR acquisitions in 2017 create powerful complementary software platforms and compelling opportunities for E&P companies. Both technologies are designed to deliver real-time actionable results and enable enhanced collaboration for on and off rig site teams for our very time-sensitive industry.

MOTIVE and MagVAR are technology leaders in their respective space, and these technologies provide additional value for our customers through improved wellbore quality in placement while offering the flexibility to utilize these services regardless of the drilling contractor or directional drilling company. These acquisitions add an attractive dimension to our strategic vision and further differentiate us from others in the market.

The MOTIVE and MagVAR technology and service offerings don't compete in the traditional directional drilling and downhole tool space, although both companies provide software and services to E&Ps and directional drilling companies.

MOTIVE's Bit Guidance System has unique directional drilling software technology that uses cognitive computing to provide optimized steering decision automation for the directional driller. MOTIVE has commercially drilled in excess of 350 wells and over 4.75 million feet of wellbore.

MagVAR's technology helps operators achieve optimal well placement and unconventional field development which leads to improved hydrocarbon extraction for the target reservoir. MagVAR leverages enhanced geomagnetic referencing and specialized data analytics and real-time to improve MWD survey accuracy which, in turn, improves the customer's capability to drill longer lateral wellbores within geological and reservoir targets.

During the 2017 December quarter, MagVAR provided correction services for more than 600 wells, up from approximately 270 wells in the same quarter in 2016. We've been very pleased with the integration of both companies not only to technology, but especially their people. Their great synergies and their cultures match well with H&P.

Before turning the call to Juan Pablo, I want to emphasize that we believe that our people, performance, technology, reliability and our uniform FlexRig fleet remain our strongest competitive advantages. Coupled with our scale and financial strength, we are able to continue to provide superior value to customers and shareholders.

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

[Juan Tardio, VP & CFO]

Thank you, John, and good morning, everyone. As usual, I will expand on some of the announced information on each of our three drilling segments followed by some comments on corporate level details. On our U.S. land drilling segment, let me first highlight some of the details related to our growth and activities during the last few months. Since our last earnings call in November 16, 2017, our activity has increased by six rigs. The Permian again led the way with four rigs along with minor up-and-down movements in other basins. Our three most active basins today are,, The Permian, the SCOOP and STACK play and the Eagle Ford. The Permian remains our most active operation with 102 rigs contracted. We still have 46 idle FlexRigs in the area, 25 of which have 1,500-horsepower drawworks rating.

In the SCOOP and STACK and Eagle Ford today, we have 30 and 31 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 first fiscal quarter, we exited the period with 204 contracted rigs and had an increase of approximately 4% in total quarterly revenue days. We continued to experience growth in activity from beginning to end of the quarter and now expect a similar trend for the second quarter of fiscal 2018.

In general, the improved level of pricing in the spot market more than 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 increased by $483 to $22,167 during the most recent quarter.

The average rig expense per day decreased by $359 to $13,546, mostly driven by lower-than-expected self-insurance expenses in the quarter as we adjusted our corresponding reserves.

Looking ahead at the second quarter of fiscal 2018, we expect a sequential increase of approximately 3% to 4% in the average number of active rigs. Compared to the prior quarter at $22,167 per day, we expect the adjusted average rig revenue per day to remain relatively flat to slightly up as the underlying dynamics of newbuild term contract roll-offs and increasing spot pricing continue to offset one another.

Although our average day rate in the spot market is still in the high-teens, leading edge super-spec FlexRig pricing is in the low to mid-20s. The average rig expense per day level is expected to be roughly $13,900. The normalized average rig expense per day directly related to rigs that are already working in the U.S. line 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.

109 of our 206 contracted rigs today are under term contracts, and 38 of the 109 rigs under term contracts were priced during strong markets before the 2014 downturn. The remaining rigs under term contracts were priced since the downturn and have a remaining average duration of less than one year. The expected average rig margin per day for all of our rigs already under term contracts in this segment during the second fiscal quarter is roughly $10,500. The expected average rig margin per day numbers for rigs already under term contract for the second half of fiscal 2018, for all of fiscal 2019 and for all of fiscal 2020 are roughly $10,300, $12,100 and $15,400, respectively.

The average number of corresponding rigs that we already have under term contracts for each of those 3 time period is approximately as follows, 83 for the second half of fiscal 2018, 35 for fiscal 2019 and 8 for fiscal 2020.

No early termination notices for rigs in the segment have been received since mid-2016, but given the prior terminations, we expect the generate approximately $4 million during the second fiscal quarter and a total of approximately $6 million during the following three quarters in early termination revenues.

Let me now transition to our offshore operations. The number of quarterly revenue days decreased by approximately 6% with five rigs contracted through the quarter. The average rig margin per day increased sequentially by $287 to $12,375. Management contracts contributed approximately $6.5 million through operating income, benefiting from adjustments that are not expected to recur during the following quarter.

As we look at the second quarter of fiscal 2018, quarterly revenue days are expected to decrease by approximately 2% with five rigs contracted during the quarter. Average rig margin per day is expected to decrease to $11,500 as one rig will be moving from an operating rate to a standby-type day rate for a few months. We are working on prospects for two idle rigs to go back to work during this fiscal year and are certainly encouraged by that possibility. Management contracts are expected to contribute approximately $4 million to the quarter's operating income.

Moving on to our international land operations. The average rig margin per day in the segment decreased by $1,035 to $11,351. Both sequential quarters included favorable adjustments that are not expected to recur going forward. The number of quarterly revenue days increased sequentially by 23% as a result of increased activity in Argentina, as mentioned during our prior call.

As we look at the second quarter of fiscal 2018, quarterly revenue days are expected to slightly declined by about 4% as we have two rigs immobilized during the first fiscal quarter, after the completion of the corresponding projects. Nevertheless, one of those rigs is contracted and scheduled to go back to work for a different customer early in the third fiscal quarter.

In addition, we are working on another opportunity that could resolve in one additional rig returning to work before the end of the second fiscal quarter. Accordingly, we would not be surprised to end the quarter with 18 active rigs in the segment, including 16 in Argentina, one in Colombia and one in Bahrain. The average rig margin per day is expected to be approximately $8,000.

Let me now comment on corporate level details. We expect an increasing level of activity and opportunities to upgrade FlexRig3 to specifications in highest demand and have adjusted our CapEx estimates accordingly to $350 million. Roughly 40% of that estimate is attributable to maintenance CapEx, including tubulars. As previously announced, and mentioned by John, we acquired another small company, MagVAR, during the first fiscal quarter. This acquisition is not included in our CapEx estimate. Our balance sheet, liquidity level and term contract backlog remain strong and provide great flexibility to pursue plenty of opportunities while, at the same time, sustaining current dividend levels. Our estimate for general and administrative expenses for fiscal 2018 increased to $180 million. The increase estimate is primarily a result of higher-than-expected year-end employee incentive compensation compared to the corresponding prior estimates and accruals, along with expenses related to our most recent acquisition, including restricted stock awards as announced in early December.

The new income tax law is expected to significantly benefit our future financial earnings and after-tax cash flows, which, of course, is what drives the required and favorable adjustment to our deferred income tax liability. Excluding that adjustment, our net income for the first fiscal quarter was very close to zero. And when the denominator for a rate calculation is so low year-to-date, it is not useful to refer to any expected income tax rate estimate for the rest of the fiscal year. Nevertheless, the statutory U.S. federal income tax rate for our 2018 fiscal year, given our September 30 year end, is approximately 25% and is expected to move to 21% for our 2019 fiscal year.

In addition to those statutory rates, of course, there are state and foreign income taxes to consider. We would not be surprised if we have a total blended statutory income tax rate of around 25% during fiscal 2019 and beyond.

Let me now turn the call back to John.

[John Lindsay, President, CEO & Director]

Thank you, Juan Pablo. We are encouraged by an improving macro outlook for oil prices and the prospect of an increasing level of rig activity that it pertains. It is gratifying to see that many of the strategies we employ to prepare for this eventual increase in demand are bearing fruit as we have redeployed rigs to the field. Our fleet is particularly well-suited for the more technically challenging wells being drilled today. We believe there will be an accelerated bifurcation in the rig count as the rig replacement cycle persists.

Before we open up for questions, I want to take a moment to say that our thoughts and prayers are with those individuals, their families and friends who were impacted by the gas well blowout and explosion that happened earlier this week here in Oklahoma. Although it was not our rig that experienced this event, as a company in the oil and gas industry, I know we all strive to work safely each and every day. It is something that's top of mind for anyone in this line of work. This situation is a tragedy and a reminder for all of us that life is precious.

And Lynn, we will now open the call for Q&A.

[Operator]

[Operator Instructions]. And the first question comes from Colin Davies with Bernstein Research.

[Colin Davies, Sanford C. Bernstein & Co.]

Just sort of thinking about all the activity in the Permian. And a lot of conversation around the underlying cost base of the industry. I noticed the sort of direct expense comments in the prepared remarks was sort of keeping things around that 13,000 level. How is it looking on the ground in the Permian? Are you experiencing inflation and pressure to that?

[John Lindsay, President, CEO & Director]

I think there's always some inflation. We haven't really seen it bear out in our results right now. As you said, the average working rig is still around 13,000 but we have a lot of moving parts and pieces related to the number of rig activations and those sorts of things. Juan Pablo, would - anything to add there?

[Juan Tardio, VP & CFO]

No. I don't believe that there are any significant adjustments that we might be expecting or any pressures that are worth mentioning or significant.

[Colin Davies, Sanford C. Bernstein & Co.]

Yes. And then just a more strategic follow-up. The strategy that you outlined around the digital impact and evolution of the industry seems quite distinctive perhaps from what some others are doing, much more sort of open-source strategy. But such against that, as the industry grows, there's clearly an object to try and capture more of the direct spread cost, if you like, of running the rigs through the drill - the well construction process. Can you just perhaps just take a step back and perhaps differentiate your approach from perhaps some of the other approaches that are out there and how you see your approach translating into capturing that spread?

[John Lindsay, President, CEO & Director]

Yes. I think one thing, Colin, is our goal - I mean, at the end of the day, our goal is all designed to support our customer and to support the performance at the rig site, obviously. And so from an integrated perspective, I don't really see us necessarily looking at - to that particular avenue. I think when you start thinking about the - how we've utilized data, I kind of mentioned this in our comments over the last 10 years, I mean, we've utilized - with AC drive technology, our Center of Excellence here in Tulsa and our ability to utilize that data to enhance our performance for our customers, also to use tools that allow us to maintain our equipment in a more effective way to predict failures, to do things that are, I think, outside of what the typical drilling contractor has been able to do. Obviously, with MOTIVE and MagVAR, both of those technologies, they're different offerings, to your point.

They're different in what our peers and others are doing because one is related to bit guidance in general, which enhances the capability of the directional driller on the rig. We've seen for a long, long time that a poor directional driller or an inexperienced, that's probably the best way to describe it, an experienced directional driller, can really damage our value proposition for the customer. So the ability to more automate that and give that directional driller and ultimately, our driller, when you get to the point where you can eliminate the directional driller off of the rig floor or off of the - I have a driller's cabin, offside, I guess, I should say. And so we're giving turn-by-turn instructions to that DD, ultimately to a driller, hopefully at some in time in the future, no different than other industries, you get to the point where you can automate that function. So I think that's compelling.

And then I think with MagVAR, the ability to real-time autocorrect or correct surveys. MWD surveys, whether it's a survey tool or whether there's geomagnetic interference, different processes that companies use on surveys and being able to correct that survey is vitally important. And particularly, as you think about these laterals getting longer, one-degree or two-degree error on a 10,000-foot laterals are much different outcome that in a 5,000-foot lateral. So there's things like that, that are, I think, are compelling. And I think they're compelling to customers. It's kind of hard for me to exactly compare that with what all the other peers and competitors are doing, but I do think that we're in a great place to help our customers going forward.

[Colin Davies, Sanford C. Bernstein & Co.]

That's great. And just to follow up on that thought. As we think ahead for the next couple of years, are you seeing HP getting more active in those sort of technology bolt-on acquisition space? Do you see more coming?

[John Lindsay, President, CEO & Director]

Well, let's put it this way. We've got our eyes open. We're looking for opportunities. We've said for a long time that it didn't make sense for H&P. We thought there was a dilutive effect to us acquiring other company's drilling rigs. We think having a uniform fleet of FlexRigs, 3s, 4s and 5s, is a significant competitive advantage. So we didn't expect to see us looking at that type of acquisition. And so the technology acquisitions makes sense. Again, we've talked about that for a long period of time. And I think the way to summarize is the technology that would enhance the performance for our customers, improve wellbore placement, quality, production and all of those things. I think customers would be willing to pay us to get a return on the investments that we're making.

[Operator]

Our next question comes from Byron Pope from Tudor, Pickering, Holt.

[Byron Pope, Tudor, Pickering, Holt & Co.]

John, could you, in a qualitative way, just give a feel for how the nature of your conversations with customers might be evolving with regard to their recognition to term out upgraded FlexRigs just given the tightness of the super-spec rig market today?

[John Lindsay, President, CEO & Director]

Yes. I think there are some interest in terming up rigs. I think you heard in our prepared remarks and you've just kind of seen it over the last several quarters that we've got a pretty good mix of term and spot pricing. It's essentially 50-50 today. We've also been pretty adamant about not continuing to do super-spec upgrades without some sort of a term commitment and better pricing because I think that's important. And the last thing we want to do is overbuild the super-spec segment. It's hard to get your arms around exactly what - how large that segment should be. We know it's around 400-or-so, maybe a little more than 400. We know what the additional upgradable rigs. So I think there is some appetite for customers looking at term. I know for H&P, we have a high appetite for wanting to enter into more term contracts as we go forward as we upgrade these rigs.

[Byron Pope, Tudor, Pickering, Holt & Co.]

And I'm assuming it'd be reasonable to assume that the leading edge day rates that Juan Pablo referred to in his remarks would be representative of what we could expect for those upgraded super-spec FlexRigs?

[John Lindsay, President, CEO & Director]

Yes. I think that's a reasonable expectation.

[Operator]

Our next question comes from John Daniel with Simmons & Company.

[John Daniel, Simmons & Company International]

I'm going to just touch on offshore and international. First with international, can you just speak to customer increase right now? I know you alluded to potentially two rigs going back to work. But just given the recovery in oil prices, what are you seeing?

[John Lindsay, President, CEO & Director]

Yes. I think in general, with the kind of the oil prices that we're seeing today, it's not that surprising that we're starting to see some interest. And so it's encouraging, like Juan Pablo said, to have a couple of rigs on the horizon offshore. International, as you know, international markets move pretty slowly. We have participated in a few tenders. We do have some conversations going on. Unlike U.S. land, those reactivations typically - or contract awards don't happen in a week or two, and you have rigs moving in 2 or 3 weeks. They're longer lead. But it is encouraging that we are beginning to see some interest and some discussions ongoing. So anything to add there?

[Juan Tardio, VP & CFO]

I think that captures it.

[John Daniel, Simmons & Company International]

And when you are participating on these tenders, can you just speak directionally to where the - those that win the tenders, where the margins are shaking out? And Juan Pablo, should we expect any type of reactivation or mode costs? Or is that embedded in that - the guidance for the $8,000 cash margin?

[Juan Tardio, VP & CFO]

Yes. We have included some assumptions related to that in the margin outlook that we've provided. But as you know, there may be unexpected moving pieces related to putting rigs back to work. We don't expect those to be significantly detrimental to the margins. Hopefully, they're favorable.

[Operator]

Our next question comes from Angie Sedita with UBS.

[Angeline Sedita, UBS Investment Bank]

So John, based on your customer conversations that you had, and obviously, you've been here for many years. You know the industry. So thoughts about the rig count growth we could see for the industry in 2018. How many rigs do you think we could be adding by year-end this year? Is it 100? Is it 200? Are we exiting the year at 1,000 rigs or slightly above? I mean, what are you hearing and what are you feeling at this point in the year?

[John Lindsay, President, CEO & Director]

Yes. That's a great question. I wish I had a crystal ball to look into to know for sure. I know you've heard us say that our belief for the last couple of fortress is that the rig count that we've been experiencing was kind of an expectation of $45 to $50 oil. And now, again, I think oil prices have probably exceeded everyone's expectation this early in 2018. And so if we're looking at a $60 or $65 oil price going forward, I think we're - we can logically expect to see customers pick some rigs up. What's interesting is there are so many variables in that and in that decision. I think first of all, one thing to keep in mind is that there is a lot of evidence for higher levels of discipline for E&Ps in terms of spending within cash flow.

So I think that's one factor. Service costs, clearly, are going to go up. I think with the budget increases that we've seen thus far, again, I think that probably gives kind of a moderate sort of rig count increase, which is what we would expect. But you've got other variables like rig efficiency, type of wells that are going to be drilled. What does the legacy fleet ultimately do? Because obviously, we're all focused on AC drive. I think there's around 225 legacy rigs drilling horizontal and directional wells today. That's down from 250 a few months ago. So we're seeing some sort of a - potentially seeing a trend there. So there's a lot of moving parts and pieces. It's hard to say, is it 100 rigs? Is it a 200-rig increase? And then again, I think you have to answer the question, what type of wells are they to be? If they're going to be longer laterals and more complex in tiger spacing on pads, I think you have to believe that you're going to need super-spec capacity rigs. And that capacity, overall, is somewhat limited, as we've described.

[Angeline Sedita, UBS Investment Bank]

So then, if anything, you would say, it's on the lighter end of that range. I mean, to be closer to 100 rigs than the 200 rigs based on all those factors. Is that fair?

[John Lindsay, President, CEO & Director]

You know what, Angie, it's just hard to say. I mean, obviously, in a very strong - again, we've been in this business for a long time. And in a very strong commodity price improvement, rigs are going to go to work, and they may not be the ideal rigs for the projects. Eventually, we can get around to doing that. So I think it's hard to say. I think 100 and 200 rigs is a reasonable estimate. I think it's as reasonable as anybody could make.

[Operator]

Our next question comes from Tommy Moll with Stephens.

[Thomas Moll, Stephens Inc.]

So the first question for you is just making sure that I'm understanding the CapEx budget correctly. On the revised number of $350 million, if we just ballpark the growth and maintenance, I'm getting to, call it, $200 million for growth this year. And then, John, you mentioned on the cadence of super-spec upgrades, it could be about 12 per quarter. So if we just ballpark $200 million on 50 upgrades, call it, $4 million per upgrade, am I thinking about that the right way? Or is there something else baked into the growth number?

[Juan Tardio, VP & CFO]

Tommy, this is Juan Pablo. As we've said, there are other considerations that impact the number. We've mentioned in the past the fact that we want to stay ahead in terms of long lead items that we need to put in place. We want to put in place in order to be able to quickly react to market conditions. It does improve. And that's exactly what we did last fiscal year, and we were able to take advantage of those opportunities. So there is a portion of the $350 million that is dedicated to that. In general terms as well, another moving piece is that as we upgrade rigs, it will depend what the upgrade looks like, what it includes. As you know, many of our upgrades relate to adding a skidding package in addition to the 7,500 psi circulating system. That type of investment might be a $2 million to $3 million investment per rig. And in other cases, we may wish to upgrade of a standard FlexRig3 with a walking system and other capabilities. That investment would be higher, closer to $8 million.

In both cases, we've seen that we can get very attractive returns on those incremental investments, and so they're all favorable. At the end of the day, it will depend on the mix of how many we have. Just to give you a sense for last year, I believe we upgraded a total of 91 rigs. Only a few of those, maybe three, were walking rigs. All the rest were skidding systems. And so as you have seen, we spent approximately $400 million during fiscal 2017 in terms of CapEx. Your assumptions in general are fair, but just to warn you that there's many other moving pieces that impact the numbers.

[Thomas Moll, Stephens Inc.]

Fair enough. My one follow-up would just be on the rigs that you do decide to upgrade this year, did I hear you correctly, it's right for us to think about some kind of customer commitment at the leading-edge?

[John Lindsay, President, CEO & Director]

Tommy, that's our expectation. I think, again, we're trying to get our arms around the super-spec fleet. We kind of have an idea on what the supply side could possibly be. We're trying to determine what the demand side of the equation is. I think there are clear indicators that it's trending towards more complexity, longer laterals, more challenging, which pushes a standard reconfiguration. And so I think as a result of that and the customer needing more horsepower and more capability, therefore provides higher levels of performance. Well, then, I think in that case, we ought to have some sort of a commitment to make certain that we're getting reasonable rate of return and a payback on our investment.

[Operator]

Our next question comes from Kurt Hallead with RBC.

[Kurt Hallead, RBC Capital Markets]

The one data point that called my attention again this quarter, as it did last quarter, was the commentary about the rigs that are currently under contract over the course of the next couple of fiscal years and the corresponding cash margins for those rigs that are under that term contract. And I just wanted to kind of assess, when you talk about the rigs that are on the contract for fiscal 2020, that they carry a $15,000-a-day cash margin. Were those contracts booked prior to 2014? Or since 2014?

[John Lindsay, President, CEO & Director]

Prior to, Kurt. Those are old contracts. They're - I think there was a slight adjustment there. Sometimes, we need to make them. But yes, the 7 or 8 rigs that we already have contracted for 2020 at $15,400 expected margin, those are priced in a very attractive market conditions before the downturn.

[Kurt Hallead, RBC Capital Markets]

All right. Second question, follow-up for you was in the context of, you referenced that spot rates are in the high-teens. Super-spec rates are in the low to mid-20s. But I mean, John or Juan Pablo, the assets, effectively, the H&P operates right here. My guess is you're not really pricing in the high-teens. So I'm just trying to kind of calibrate that data point, right. Or probably more - your asset base is more gravitating to that low- to mid-20s kind of dynamic at this juncture.

[John Lindsay, President, CEO & Director]

I think that is a fair assumption, Kurt. What we think the main takeaway from those two references, the high-teens going toward the low to mid-20s, is that we expect pricing to continue to go up, and especially average rig pricing. And so that's encouraging as we look not only at this second fiscal quarter, but hopefully, beyond through the rest of the fiscal year as well.

[Operator]

Our next question comes from Sean Meakim with JPMorgan.

[Sean Meakim, JPMorgan Chase & Co.]

So gentlemen, something - just to talk a little bit more about the CapEx budget, and I think the reasons to increase that are clear, but I was just curious why we remove the band. So is the visibility such that you're confident that number given customer budgets, cash flow they may have locked in as - through hedging is fairly tight here? Just trying to get a sense of the decision-making there and how much flex there is in that budget in both directions for fiscal '18.

[John Lindsay, President, CEO & Director]

I like that, Sean. Flex in our budget. Flex in our FlexRig budget. That's nice. Can I use that going forward?

[Sean Meakim, JPMorgan Chase & Co.]

Sure. The pun was not intended, but happy for you to.

[John Lindsay, President, CEO & Director]

Again, everyone is pleased. Everybody in the oil and gas business are pleased with improved commodity prices. And so I think there is an element of - with the outlook that we have. As Juan Pablo said, a lot of the CapEx is designed for outward months. We want to make certain we've got the appropriate supply chain in place. And so again, I think with what we're looking at right now, that would probably be the reason why we're closer to that $350 million, and we didn't give it a $300 million to $350 million range. So I think that's a reasonable assessment.

[Juan Tardio, VP & CFO]

And then if I may add to that, John. I think if market conditions and opportunities coming our way allow it, there certainly is a possibility that the CapEx level or CapEx estimate would continue to go up. That is just our estimate in terms of what we believe is fair to assume at this point given what we see today.

[Sean Meakim, JPMorgan Chase & Co.]

Very helpful. Yes, I think that helps to frame it quite nicely. Just another topic I was hoping to touch on, you've made it pretty clear, certainly over time, that there's dilutive effects to M&A across rig fleets in the U.S., and no disagreements there. Just curious how you think about international. And clearly, longer cycle. It's an important part of your business, not the main driver. Is there appetite? I mean, could it make sense at some point to try to scale up that business if there are assets available or ways in which you could perhaps do a little more in the international side? Just curious how you think about that given there are some clear contrast versus the U.S. business.

[John Lindsay, President, CEO & Director]

Sure. No, that makes sense. It's a good question. I - the international assets, rig assets, that are out there, that have been out there for quite some time, there's - I don't think anybody would be surprised which assets those are. And so I think, all of those have kind of had the tires kicked, so to speak. And they're just - when you look at the cost to acquire those assets and the level of the technology of those assets, we believe that this business is going to continue to be technology-driven going forward and acquiring older assets and older technology just doesn't really make a lot of sense. I think the analogy of kind of buying some assets and buying a beachhead, I think, you'd have to just pay for it too much for that. That's just - that's our perspective, but there may be others - other people that can make that strategy work.

[Operator]

Our next question comes from Marc Bianchi with Cowen.

[Marc Bianchi, Cowen and Company]

It looks like free cash flow after the dividend in this quarter was a negative about $100 million. Cash balance is now $380 million, yet you have CapEx going higher. You said you feel comfortable to continue paying a dividend. Should we interpret the increase in CapEx as confidence that cash generation should be improving kind of going forward from here?

[Juan Tardio, VP & CFO]

Marc, this is Juan Pablo, by the way. I think your point is that when you look at cash from operating activities, the number may have been a little lower than what you may have expected. We do expect that number to continue to increase significantly. Part of what impacted the number related to some cash absorption in terms of working capital, obviously, as business improves, revenues increase. There's higher accounts receivable, et cetera that absorb working capital. Some movements in that regard and other considerations related to the quarter translated into a higher level of absorption of working capital than we or you may have expected. But going forward, I don't think that, that necessarily continues, at least to the extent that we saw during the first fiscal quarter. I would expect cash from operations levels to be significantly higher for the second fiscal quarter, given our guidance.

[Marc Bianchi, Cowen and Company]

Okay. Is it fair to think that cash after CapEx and after dividend can kind of get to some kind of a positive contribution at some over the next 2 or 3 quarters?

[Juan Tardio, VP & CFO]

That all depends on our market conditions. Could it be the case? I think, yes. It's certainly possible. We wouldn't be surprised if that were to happen. But as you know, we don't provide guidance to give you a better sense of that.

[Operator]

Our next question comes from Michael LaMotte with Guggenheim.

[Michael LaMotte, Guggenheim Securities]

John, you've described MOTIVE and MagVAR as being a part of a family of solutions. I'm curious as to what your thoughts on how extensive that family could get with uncles, cousins, nephews, what it could look like in terms of sort of the range of solutions over time?

[John Lindsay, President, CEO & Director]

Well, Michael, it's again another great, great question. If you think about the areas that we're focusing on, and we've spent a lot of time, I won't to go all the way through it, but just to mention that, over time, we've seen challenges with drilling efficiencies and reliability as a result of directional drillers. So that's one solution. The other is lateral for getting longer well complexity is greater, much higher opportunity for wellbore collision or as you're fracking these swells, making certain you have the right spacing. And that's where companies like MagVAR come into play.

And so again, I think as it relates to providing services and providing things that really help our customer be more efficient and effective, not just efficiency-related to the time drilling the well, but the overall production. So wellbore placement. So less tortuous wellbore long term creates a better-producing well as well as less cost associated with it to the life of the wells. So things like that. And so I sure wouldn't limit what we've done at this point. I think there's other opportunities. I'm not in a position, obviously, to talk about what those are today, but that's definitely in our sights as we see the market evolve and we see other ways to hopefully add value to customers.

[Michael LaMotte, Guggenheim Securities]

Okay. And somewhat related to that, I think it's interesting that the steps you've taken so far have been all software-related. Do you see a place or a need for any hardware component? Or are you happy to stick with software-based solutions?

[John Lindsay, President, CEO & Director]

Well, hardware covers a broad spectrum. And so hardware as it relates to the rig, definitely, those are the things that we're going to continue to adopt and we'll continue to improve. Obviously, there's also additional software capabilities and other aspects of the business. I think what we've tried to be clear on is that what we aren't trying to do is to get into the downhole directional drilling space. And I think our desire is to help our customers and help our customers with the directional drilling space in the way that we've described with MOTIVE and MagVAR, but not to get into the downhole tool business and compete in that what you would consider a very highly competitive industry, if that helps.

[Operator]

Our next question comes from Timna Tanners with Bank of America Merrill Lynch.

[Timna Tanners, Bank of American Merrill Lynch]

Just want to cycle back and see if I could clarify some earlier comments in light of now achieving positive EBIT for the first time in seven quarters. Any fresh thoughts on capital allocation? I know you increased the CapEx somewhat. Obviously, we've talked about that quite a bit. But dividend, happy with where it's at? Any thoughts of returning cash to shareholders? I know we talked about M&A, but can you rank order some of the priorities?

[Juan Tardio, VP & CFO]

Thanks, Timna. This is Juan Pablo. It's great to have a flexibility that we have, given our balance sheet and liquidity backlog, et cetera, to do all of the above, so to speak. We always have a preference in terms of investing in the business and certainly, making sure that before we do invest in the business, that we expect this opportunities to be attractive in terms of returns for our shareholders. And so when we see opportunities, we have plenty of flexibility to pursue those, and that's our first priority. Fortunately, we can also continue to return cash to shareholders. Our dividend level is at a level that we can sustain. Of course, we've increased that annual level for over 40 years. It's something that we think about carefully before making changes or defining levels, as we've said in the past. And if there are other opportunities, such as share repurchases, we will analyze of those as well. At this point, I think that it's fair to assume that the first two that I mentioned will probably continue to be our preferred vehicles.

[Timna Tanners, Bank of American Merrill Lynch]

Okay. Great. High-quality problem, of course. And then I just wanted to settle back, and maybe I'm too hung up on this, but in the prepared remarks, you made a comment that at the right price, you are prepared to add, I think it was 12 rigs per quarter, the reasonable pricing. Is that all baked into your assumption that pricing will be reasonable? Is that kind of a gradual price? What does reasonable pricing means to you, I guess, is the question?

[John Lindsay, President, CEO & Director]

Yes. I guess what you're saying is we're not good now - one thing what we would say is we're not building these upgrades on spec. We're requiring, again, low-20 to mid-20 type of rate. We'd like to have a term contract to go along with that. So if we're receiving the kind of demand from customers like that, then we would continue to upgrade rigs. If you're not seeing that, if the customer - if the well economics don't support it for whatever reason or the outlook becomes negative, then we wouldn't continue to just build out super-spec rigs. We're going to have some limitor. So that's really what we're trying to accomplish. Lynn, I think, we have time for one more question, please.

[Operator]

Our last question will come from Ryan Pfingst with B.Riley FBR.

[Ryan Pfingst, B. Riley FBR]

I'm in for Tom Curran this morning. If you could, what is MOTIVE's current active rig count right now and it's split between you guys and third-party rigs?

[John Lindsay, President, CEO & Director]

I think they're in high-teens. And I want to say 1/3 of the fleet are FlexRigs. Is that in line?

[Juan Tardio, VP & CFO]

Yes.

[John Lindsay, President, CEO & Director]

They're closing in on 20 jobs, so that's been good. They've made some nice progress. And like I said, 1/3 of the fleet are FlexRigs.

[Ryan Pfingst, B. Riley FBR]

Great. Do you have any targets set for that for growth in calendar 2018?

[John Lindsay, President, CEO & Director]

Well, we always have some internal targets that we're trying to achieve, but nothing that we're in a position to announce. But we are very pleased with the progress that they're making, both on a technical basis as well as just customer adoption. All new technologies have a certain level of adoption time, and we're encouraged with the adoption process there we're seeing at this point in time.

[Juan Tardio, VP & CFO]

Thank you, Ryan, and I believe John has some concluding remarks.

[John Lindsay, President, CEO & Director]

Okay. So yes, I would just want to close out this morning just emphasizing how proud I am of our people. How they've embraced the challenges set before us these past three years has been a really challenging three years, as we all know, in this industry. There's a lot of evidence out there that the response that we've had in 2017 to the improving market conditions, which have been remarkable in terms of number of rigs activated. Our folks in the field have had an amazing response, those in terms of just putting rigs to work and providing very, very high levels of value to customers. Obviously, that flows through to shareholders, and just want to thank everybody for that. So we're looking forward to a really strong 2018. And thank you again for your time, and have a great day. Thank you.

[Operator]

This does conclude today's program. You may disconnect your line at any time, and have a wonderful day.