Helmerich & Payne, Inc. (HP) Q4 2016 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to today’s Fourth Quarter and Fiscal Year End Earnings Conference Call for Helmerich & Payne. At this time, all participants are in listen-only mode. Later, you will have the opportunity to ask questions during the question-and-answer session. [Operator Instructions] Please note, this call may be recorded. I will be standing by if you should need any assistance. And it’s now my pleasure to turn the conference over to Mr. David Hardie, Manager of Investor Relations. Please go ahead, sir.

Thank you, Tony, and welcome everyone to Helmerich & Payne’s conference call and webcast corresponding to the fourth quarter of fiscal 2016. 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’ll open the call for questions. As usual and as defined by the U.S. Private Securities Litigation Reform Act of 1995, all forward-looking statements made during this call are based on current expectations and assumptions that are subject to risks and uncertainties as discussed in the company’s Annual Report on Form 10-K and Quarterly Reports on Form 10-Q. The company’s actual results may differ materially from those indicated or implied by such forward-looking statements. We will also be making reference to certain non-GAAP financial measures, such as segment operating income and operating statistics. You may find the GAAP reconciliation comments and calculations on the today’s – on the last page of today’s press release. I’ll now turn the call over to John Lindsay.

Thank you, Dave, and good morning, everyone. Thank you, again, for joining us on the call. We’re pleased to deliver better than expected quarterly operational results in the midst of this improving U.S. land market. Our goal is to safely provide performance-driven drilling services. And as we think about the future, I think, it is helpful to step back and properly frame where the company is today. There are three main areas I’d like to focus on this morning. First, the success we’ve had in reactivating idle FlexRigs; second, the leadership position we have in the Permian; and third, some reasons why H&P is in a good position to continue to build its market share. Let’s start with the reactivation of 32 FlexRigs since the trough of activity in May. Of those rigs, 28 are in the spot market and four on term contract. 15 were in Permian; five in the Oklahoma, Woodford; three each in the Bakken and Haynesville; and two each in the Eagle Ford, Powder River Basin and Niobrara. From a FlexRig model perspective, 22 were FlexRig3s and 10 were FlexRig5s. There’s a perception by some that the FlexRig3 isn’t as competitive as other models of rigs in the market. Of course, our customers know differently the FlexRig3 continues to be the workhorse of the fleet and deliver great value for customers. Of the 32 rigs, 75% were pad capable and have 7,500 psi mud pumps. These rigs meet the general criteria of what some industry followers have identified as super-spec rigs and we’ve also added 14 new customers since May and momentum has been building as a result of the performance our people are delivering. Our goal is to respond quickly to customer requests, provide problem free startups, and deliver very safe, efficient and reliable performance. We’re pleased to have delivered great results, particularly on the very first well drilled by each of the reactivated FlexRigs. Let me give you a few examples of this performance. The rig mobilizations out of our facilities have averaged less than four days from the rig down in our facility to moving the rig to the first location rigging up and being ready to drill. Subsequent moves after the first well have averaged less than two days. As far as drilling times by comparing customer AFEs and offset well data, we’ve been able to determine that most of the FlexRigs drill the very first well under the AFE, some have been 20% to 30% under AFE and there have been many that have been record wells. In addition to efficient rig moves and delivering world-class drilling performance, the 32 rigs have actually averaged lower than 1% downtime, which is aligned with the rest of our working fleet. Our people on the rigs are to be commended for the high levels of service attitude performance and value created for our customers and shareholders. Our workforce staffing effort has also been very successful in rehiring previous employees for our reactivated rigs. We’ve had close to a 90% success rate, as we’ve reached out to previous field employees, resulting in hundreds of quality employees returning to H&P. In fact, all of our rigs staffing needs have been provided by rehires up to this point. Another benefit this creates is the opportunity to promote our people. As you can imagine, this is a big boost to the organizations morale. Another success related to our rig activation is our 24/7 center of excellence for safety, learning, and performance. The center of excellence works hand-in-hand providing support services to our field operations, so they can deliver operational excellence to our customers. They’ve developed systems that utilized predictive analytics, which help us reduce nonproductive time, enhance reliability, and optimize operational performance. All of these systems working in Unison shortened the learning curve and allow sharing of best practices between rigs driving performance improvements in a shorter timeframe and across the fleet. I would be remiss if I didn’t also mention the cruise and their supervisors that have managed our idle fleet of FlexRigs and they’ve turned the process around to reactivating rigs. They’ve shown great teamwork and it worked very hard to preserve our idle FlexRig equipment stored in our facilities and also to utilize the consumables throughout the fleet. Thanks to each of you for this great effort. Shifting to the Permian with all the headlines it isn’t a surprise that we’ve activated more FlexRigs there than in any other basin. It is equally important to stress the capabilities we have in our Permian operations. We invested heavily in our infrastructure in the Permian back in 2012 through 2014, and it is our largest facility today, and at the peak, we were working just shy of 90 rigs in West Texas and had expectations to work as many as 125 rigs prior to the downturn. Today, we have 49 rigs contracted coming off a low of 37 rigs. We have 71 idle FlexRigs in the area and 51 of those are 1,500 horse power, and we expect to continue to have opportunities to grow our active fleet in the Permian. In addition to having our FlexRigs offering, we also have additional services in our Permian operation, where we provide rig move trucks and casing running capability for our rigs. We’ve operated our own rig move trucking fleet since 1994, and today, we’re the only major drilling contractor that owns and operates a rig move trucking fleet. Our ability to control the rig move process offers substantial advantages in efficiency, safety, and reliability to our operations and customers. Historically, we’ve ranged between 30% to 40% of all rig moves in the U.S. with our trucking fleet and that’s similar to our Permian activity today. For over 10 years, we’ve offered casing running services in our U.S. land fleet. A light trucking using our casing running personnel and tools provide competitive advantages in safety and productivity for our people and customers. Of the 14 new customers since May, eight are working rigs in the Permian were saying that the Permian is leading the recovery and having this infrastructure in place certainly will be an advantage going forward. The third area I want to focus on is H&P’s market position to continue efforts to grow our market share in U.S. land. The market today recognizes the advantages of 1,500 horse power AC drive rigs, because those rigs are best designed for the complexity and longer laterals for horizontal shale wells and customer demand for high levels of performance and reliability. From a rig requirement perspective, extended laterals require more hydraulic horsepower, drill strength torque, and greater capability from technology solutions that 1,500 horsepower AC rigs provide, and therefore, they are the rig of choice. We estimate that H&P has approximately 55% of the available 1,500 horse power AC rigs in U.S. land today. So we’re positioned with more capacity than any of our competitors in the market. We currently have 104, 1,500 horse power AC drive FlexRigs under contract and 220 idle and available to go to work in the U.S. We have 19% share of the U.S. land horizontal directional drilling market with our closest competitor at a 11%. We have slightly grown our market share from 18% since the peak of activity in 2014. We are very hopeful that the market provides an opportunity to utilize our spare capacity and build on the lead we have. Another example of H&P’s industry-leading position as our currently of AC drive FlexRigs that have 7,500 psi circulating systems and multi-well pad drilling capability. As mentioned earlier, these rigs meet the general criteria of what some industry followers have identified as super-spec rigs, which is a subset of AC drive rigs with 1,500 horsepower drawworks ratings. We have approximately 80 of these rigs in our U.S. land fleet, and if demand remains high, we could upgrade additional FlexRigs and have approximately 120 of these rigs by the end of our 2017 second fiscal quarter. The industry’s capacity to provide additional super-spec rigs appears to be limited today, which positions H&P very well for future expansion in this space. Should there be a significant market demand for super-spec rigs going forwrad, H&P has a capability of providing approximately 270 super-spec FlexRigs to the market without requiring new build rigs, solely through upgrades where needed to our current FlexRig3 and FlexRig5 fleet. Unlike many of our competitors, we don’t need to build new rigs today. Our design allows H&P to invest in our existing fleet to enhance capabilities that will benefit our customers in this more challenging and complex environment. We can do this in a scalable and cost effective way by leveraging our uniform base of existing FlexRig designs. Our spare capacity combined with our strong balance sheet, gives us great flexibility to invest in the fleet providing a family of solutions to meet customer needs and provide value to shareholders. So before turning the call to Juan Pablo, it is clear the upcoming OPEC meeting is weighing on the oil markets. And yet even though oil prices have pulled back over the past several weeks, it’s still encouraging to see signs of optimism in the market, as we’re continuing to reactivate idle rigs out of our facilities safely, efficiently, and cost effectively. And now, I’ll turn the call over to Juan Pablo.

Thank you, John. As reported this morning, the company had a net loss of approximately $73 million during the fourth quarter of fiscal 2016, resulting in an annual net loss of approximately $57 million during fiscal 2016. Nevertheless, operational results were better than expected during the fourth quarter and market improvement signs are encouraging. We are now expecting our second consecutive quarter-to-quarter improvement in overall activity during the first quarter of fiscal 2017 Following are some details on each of our three drilling segments. Our U.S. Land Drilling segment reported an operating loss of approximately $70 million during the fourth fiscal quarter. Nevertheless, the number of revenue days increased by approximately 6% compared to the prior quarter, resulting in an average of close to 86 rigs generating revenue days during the fourth fiscal quarter. On average, approximately 67 of these rigs were under term contracts and approximately 19 rigs worked in the spot market. Excluding the impact of early termination revenues, the average rig revenue per day declined by approximately 1% to $24,404 in the fourth fiscal quarter, as a proportion of rigs working in the spot market increase significantly quarter-to-quarter. The average rig expense per day decreased by less than 1% to $13,326, excluding the loss of settlements and adjustments to self-insurance reserves. The corresponding average rig margin per day during the fourth fiscal quarter was $11,078. The segment generated approximately $30 million in revenues corresponding to early termination of long-term contracts during the fourth fiscal quarter. No early termination notices have been received or announced since our last call in July. But given prior notifications, we expect to generate approximately $9 million during the fiscal – during the first fiscal quarter and a total of over $30 million during several quarters there after in early termination revenues. Since the peak in late 2014, we have received early termination notifications for a total of 88 rigs under long-term contracts in the segment. Total early termination revenues related to these 88 contracts are estimated at approximately $466 million. As of today, our 348 available rigs in the U.S. Land segment include approximately 105 rigs generating revenue and 243 idle rigs. Included in the 105 rigs generating revenue, are 72 rigs under term contracts, 69 of which are generating revenue days. In addition, 33 rigs are currently active in the spot market for a total of 102 rigs generating revenue days in this segment, as compared to 86 rigs during our last earnings call in late July. Approximately 4% of the 102 rigs are now idle and on standby-type day rates. which protect daily cash margins under long-term contracts. Separately, the three rigs that are not generating revenue days include new build rigs with deliveries that have been delayed in exchange for compensation from customers. Looking ahead to the first quarter of fiscal 2017, we expect a quarter-to-quarter increase in activity of roughly 20% in terms of revenue days. Excluding the impact of revenues corresponding to early terminated long-term contracts, we expect our average rig revenue per day to decline to approximately $23,500, primarily as a result of the higher proportion of rigs working in the spot market. Although, we have experienced spot pricing stabilization and are now beginning to see some spot pricing improvement, the average pricing today for the 33 rigs in the spot market is still over 35% lower as compared to our spot pricing at the peak in late 2014. The average rig expense for day level is expected to increase to roughly $14,200. This expected increase is primarily attributable to a significantly lower proportion of rigs generating revenue days, while on standby, down from almost 13% of revenue days in the prior quarter to an expected level of under 5% in the first fiscal quarter. Although, we expect this average expense level to eventually come down to more normalized levels during a recovery, the transitional or rig startup expenses, along with the carrying cost of over 200 idle and available AC drive FlexRig are temporarily and favorably impacting the average. If we isolate rigs that are currently active, their average expense level is at approximately $13,000 per rig per day, which is similar to overall levels experienced in more stable time periods like 2013 and 2014. Absent any additional early terminations and excluding the aforementioned rigs for which we have received early termination notifications, this segment currently have term contract commitments in place for an average of approximately 69 rigs during the first fiscal quarter, 68 rigs during the remaining three quarters of fiscal 2017, 39 rigs during fiscal 2018, and 17 rigs during fiscal 2019. These commitments include about 10 rigs that have relatively recently been placed under term contracts with pricing at slightly higher than current spot market levels. Thus, as we include this newly contracted rigs, the average daily margin for rigs that are currently under term contracts is now expected to decline moving from the prior $15,000 to $16,000 range to a new range between $14,000 and $15,000 per day during the next few quarters. Let me now transition to our offshore operations. Segment operating income slightly increased to approximately $3 million. Total revenue days slightly increased and the average rig margin per day increased by about 14% during the fourth fiscal quarter to $9,070 per day excluding employee severance expenses in the prior quarter and self-insurance reserve adjustments during the quarter. Most of the rigs and generated revenue during the fourth fiscal quarter were rigs that remained idle on customer-owned platforms and were generating standby-type day rates. As we look at the first quarter of fiscal 2017, we expect quarterly revenue days to remain flat at seven of our nine offshore platform rigs continue to generate revenue days during the quarter. The average rig margin per day is expected to increase to approximately $11,250 per day during the first fiscal quarter. The expected increase is primarily attributable to two of five rigs that were previously on standby-type day rates returning to work at operating day rates/ Management contracts on platform rigs continue to contribute to our Offshore segment operating income. Their contribution during the fourth fiscal quarter, however, was lower than expected at under $2 million. Nevertheless, management contracts are expected to once again generate around $3 million in operating income during each of the next few quarters. Moving on to our international land operations, this segment reported operating losses of approximately $200,000 during the fourth fiscal quarter. Excluding the impact of employee severance expenses during the prior quarter, the average rig margin per day increased sequentially by approximately 12% to $10,619 per day. The increase was primarily attributable to favorable retroactive pricing adjustments and to the absence of an expected temporary rate reduction that was mentioned during our late July call. Quarterly revenue days increased sequentially by approximately 8% to 1,372 days at two rigs commenced operations during the quarter. As of today, our International Land segment has 14 rigs generating revenue days, including 11 in Argentina, two in Colombia, and one in Bahrain. 12 of these rigs are under long-term contracts. We expect approximately $5 million in compensation related to early terminations for two rigs in this segment during the first quarter of fiscal 2017. As a result, we expect international land quarterly revenue days to decrease by approximately 5% during that quarter, as compared to the fourth fiscal quarter. Excluding the impact of early termination revenues, the average rig margin per day is expected to decrease to approximately $8,000 per day as a result of several factors, including the expected absent of the early terminated rigs that were generating higher than average rig margins and more of the rigs under term contracts now at standby-type day rates. When we combine all three of our drilling segments and exclude rigs with long-term contracts that have been early terminated, we currently have an average of approximately 82 rigs under term contracts expected to be active in fiscal 2017, 51 in fiscal 2018, and 27 in fiscal 2019. Let me now comment on corporate level details. Our balance sheet and liquidity remained very strong Our backlog also remained strong at $1.8 billion as of September 30. Fiscal 2017 CapEx is estimated to be around $200 million, about 30% of which is expected to be related to maintenance CapEx and tubulars and the remainder mostly to upgrade of our existing fleet. We continue to be in great position to sustain regular dividend levels and with great flexibility to take advantage of future opportunities. After this extremely challenging time for everyone in the business, we are now the only investment grade rated company in our sector and one on a very short list within the entire oilfield services universe. Total depreciation for fiscal 2017 is expected to decline to approximately $525 million and general and administrative expenses to approximately $140 million. The reduction in the depreciation expense estimate is primarily attributable to relatively low-levels of capital expenditures during fiscal 2016 and 2017. The effective income tax rate on the loss for fiscal 2016 was approximately 27%, significantly different than expected, given that instead of a slight gain for the fiscal year, we experienced a significant loss as a result of the expected – of the unexpected select items that impacted the fourth fiscal quarter. The effective income tax rate for fiscal 2017 at this point expected to be around 36%. As of September 30, other current assets in our condensed balance sheet include a prepaid tax balance of $26 million and a tax receivable balance of $38 million. Also included in current assets are approximately $50 million related to insurance receivables, which are more than offset by approximately $72 million included in current liabilities in our condensed balance sheet related to the mentioned lawsuit settlement. We have a portfolio of equity security consisting of Atwood Oceanics Inc. and Schlumberger Limited that is reported under investments in our balance sheet. And we have been monetizing these holdings over the years and recording very significant gains from the corresponding sales. Nevertheless, our 4 million share position in Atwood was determined to be an other than temporary loss during the fourth quarter as a result of the length of time that its share price had been under our corresponding cost. As a result, we recognized a $26 million impairment charge equivalent to an after-tax loss of approximately $0.15 per share. This compares to an after-tax gain of approximately $0.86 per share recorded in 2013 when we monetize 4 million shares of our Atwood Holdings and reduced that position in half. As we have in the past, we will probably hold our existing portfolio positions through this downturn and once again start to monetize them during more attractive times through the cycle. Our non-current deferred income tax liability as of September 30, 2016 was slightly over $1.3 billion, which is slightly higher than the prior year-end level. We expect this liability level to remain in the range of $1.2 billion to $1.4 billion during the next couple of years. With that, let me turn the call back to John.

Thank you, Juan Pablo. Prior to open the call for questions, I want to reiterate a few points. We strongly believe H&P is the best fleet, especially for the more technically challenging horizontal shale wells. And equally, if not more important, we also have the people, the systems, and the operational support structures to drive the highest levels of performance and reliability for our customers. We’ve accumulated more than 1,800 rig years of AC drive operational experience. Our expertise designing, building and now upgrading the fleet provides great optimality for the customer and has resulted in H&P having the largest and most capable fleet of AC drive rigs in the industry. We remain committed to further expand our competitive advantages through technology and the scale of our operations in order to continue to add value to our customers and shareholders. And Tony, we will now open the call for questions.

Great. Thank you. [Operator Instructions] We’ll take our first question from Michael Lamotte with Guggenheim Securities. Please go ahead. Your line is open.

Thanks. Good morning, guys.

Good morning.

John, what is the – roughly the cost of upgrading a 1,500 to a super-spec? And what are you looking at in terms of components to accomplish that?

If we were to use a base Flex3 that didn’t already have a pad system then it would be to add 7,500 and the pad system would be approximately $2 million.

Okay.

If we already had the – which there are Flex3s that are idle that have the pad application to skid system that are idle. So there are several that we will just upgrade with just the 7,500.

Okay.

And then there’s also some – in some cases, we’re upgrading the setback capacity, that’s a relatively small…

Small...

…investment, I want to say, it’s around $200,000 or so. There’s some folks that include in a super-spec the third pump and the fourth engine, the way we’ve approached it, Michael is, it’s really on a needs basis. If the customer has a true need for the third pump or the fourth engine, if the hydraulics requirements are there then that’s what we’re doing. But it really depends on basin and it really dependent on customer-to-customer, whether you need two or whether you need three, and that’s a relatively small incremental investment. Obviously, we already owned the pumps and the engines, it’s just really the installation cost, the rigs are set up and designed to accept the additional equipment.

Okay. And then about how much time, if you’re doing the full $2 million, how much do you need to get all that work done?

Well, a lot if it, as you can imagine, it’s kind of like asking us a question, how long does it take to build a FlexRig, because a lot of the work has been done offline. If you’re doing the work on a rig – on a – drilling a rig move, which happens occasionally, you’re talking about a couple of extra days. If it’s being done on a rig that is – that has been idle, again, it doesn’t take very long. A lot of the manufacturing, the fabrication is being done offline in our facilities similar to the or in the facilities that we’ve used to build rigs in the past. So, as you can imagine, it’s being done offline. The fleet profile is uniform. So it’s kind of a lean manufacturing effort, if you will.

Right. That’s helpful.

So it’s kind of hard to say, how long it takes for a rig that’s idle, it really doesn’t make any difference, because it’s being done offline. During a rig move, I want to say, it’s two to four days. I don’t remember exact, but I think that’s right.

Okay. So the important thing is, it’s not a month.

Right.

It really is pretty quick. And then last one for me, on those super-specs, just in terms of the increase that you’re getting, as you sort of look forward into the demand, is it a third of the incremental inquiry half? What’s roughly the mix in terms of what customers are coming to you for these today?

That is a great question, and I wish I would have thought about that and had the answer for you. I think about looking a lot of our market lines, surprisingly enough we still have, I’d say surprising, because there’s so much focus on super-spec. We still have customers that are still their requirement, their needs basis is a FlexRig3, some are single well, some are pad, with two pumps and 5,000 psi. If I were to guess, I’d say, it’s anywhere from 0.5% to 75%, it’s kind of what I would estimate today.

Okay.

We made a note in our comments that for the rigs – the 32 rigs that we reactivated, 75% of those were super-spec.

Okay.

With the pad and 7,500 psi. And again, to be clear, some of those 7,500 had two pumps and some had three. And again, it’s based upon what the customers needs are.

Okay. That’s a great color. Thanks so much. I’ll turn back.

All right, Michael. Thank you.

Thank you. Next, we’ll move to Kurt Hallead with RBC Capital Markets. Please go ahead.

Hey, good morning.

Hey, Kurt.

Good morning.

So, John, I know there’s a lot of different semantics flying around the marketplace in terms of super-spec and obviously, one of your larger competitors over the last couple of weeks had an Analyst Day and talked about some additional technology that they were adding to the mix. But focusing on the super-spec, as you referenced it and focusing on the term pad optimal, is that had optimal include walking systems, or is that just your current skid system?

Yes, the pad optimal or pad capability whatever you call it, it’s still, as we’ve described our skid systems for Flex3s and Flex5s, of course, Flex4s were designed with skid capability, pad capability as well. So that is the design, and I mean, you know, because we’ve talked about it several times. I think quite frankly, we’ve been talking about it for a couple of years now that when we have the demand from the customer in a meaningful way then that’s something that we will do. We can do. We’ve had – we have designs for it. And so I’m sure eventually we will do that. But at this stage of the game, what we’ve described in our fleet are Flex3s and Flex5s in the traditional pad configuration.

Okay. And then, I guess, we would – we takeaway from your commentary today that again the vast majority of the customer base is not asking for omni-directional walking rig capability?

Well, we do have – when you say omni-directional, we do have omni-directional capability with Flex4s and Flex5s. And but typically that isn’t the need. And so and the Flex5, I’m sorry, the Flex3, of you go back long enough, the initial pads were relatively small, they were 50 to 75 feet. And we have Flex3s today that are actually on 200 foot skid applications that were great. So the omni-directional portion of the demand, we’ve been able to meet with Flex5s or Flex4s where we’ve needed it and it really hasn’t impacted our customers designs as far as using the FlexRig3.

All right, great. And then maybe just one more follow-up on the incremental demand. You mentioned additional rigs in the number of different basins clearly, the vast majority being in the Permian. With – what have you been taking up recently in discussion with E&P customers with respect to increased activity in Eagle Ford or the Bakken, obviously, you mention the Haynesville, so that kind of captured my attention as well. So outside of the Permian, what are you hearing?

I think my sense would be, it seems like Eagle Ford compared to the last several months, there have been more inquiries in the Eagle Ford than what we’ve seen, which is obviously great news for us, if we can see some material increases, because that’s our – that was our second largest operational area back at the peak. We have great rigs and people and we’re set up very well there. As I think about it, David, I don’t know, if you’re – my sense would be, we continue to have a demand kind of across the board like it has been. I look back on this quarter and in the previous quarter and the Permian continued to be just under half and then the other ones are pretty equally distributed.

I think, that’s fair, John.

Yes. There’s just nothing that that jumps off the pages, says, oh, yes, this is the area maybe with the exception of the Eagle Ford, we have had some, at least, it seems like some additional discussions.

Right. I appreciate the color as always. Thank you.

All right, Kurt. Thank you.

Thank you. Next, we’ll move to Michael Lamotte with Guggenheim. Please go ahead. Your line is open.

I didn’t expect to get pulled in so quickly. Again, thanks, guys. John…

How did you do that, Michael?

I don’t know. Can you maybe provide some context on the term of the terms, are they rate escalators, or are there options on time? I imagine that the – are they wells six months what’s kind of the context there?

The average of the term contracts is a little over a year.

Sorry, the new ones, that’s of the new signed?

Of the – yes, that’s what I thought you were addressing, I’m sorry.

Yes, yes.

Was that your question?

Yes, sorry on the new ones, I think, I remember you saying that there were four ads of the – since trough that went out on term?

Yes, Michael, and this is Juan Pablo. We also mentioned that in general of the new term contracts that we’ve signed including some rigs that were rolling off of new build type term contracts and then went into shorter-term contracts but at much lower day rates, meaning, at spot-level day rates or slightly higher. We had approximately 10 of those. And the average, as John said, was a little over a year on all of those.

Okay. And is there any – are there any common elements to those contracts or are they all very customer specific? What I’m getting at is, I guess, what kind of visibility do you have fixed versus option on these? And what are – where the rate escalators what actually gets you more rate, as we move out in time on those contracts?

Well, Michael, on the term contracts, it’s a true term contract, where it’s for a year, they’ve got – it’s a fixed rate. It had cost escalators. If we had some sort of an increase, a wage increase or something, and we have cost escalation provisions. But in general, it’s a fixed rate or maybe the way to think about as a fixed margin for us. Again, you’ve – we’ve talked about it over the last several months. We’re not going to be entering into very many of those. Obviously, we haven’t in this particular case. Most of what we’re going to be doing is just what you’ve seen, which is spot market contracts and spot market pricing.

Okay. And then on the field labor where are we today relative to peak in 2014 in terms of wages?

We’re at the same level – our wages are at the same level a day, as they were in 2014.

Okay. And is there any pressure on those as you are out rehiring folks?

I don’t get a sense that there’s pressure. I think one of the things to consider is that, I mentioned it in my comments, workforce staffing is doing a great job and we’re having great success in hiring former employees back that were laid off during the downturn and they’re coming back to work. And so what that’s creating is, they’re coming into the entry-level positions and now it’s a great opportunity to move a floorhand back into drillers position, a driller back into a rig manager position, we’re even promoting a few superintendents up into position. So there are increases that are going on in the organization, but it’s a function of being promoted to a higher level position. I would be surprised that that there would be wage pressure, at least, for the foreseeable future, and it’s kind of hard to get arms around. We haven’t predicted what the rig or the rig count is going. But I don’t see that on the horizon right now.

Okay. Thanks, guys. I’ll turn back again.

All right. Thank you, Michael.

Thank you. Next, we’ll move to Robin Shoemaker with KeyBanc Capital Markets. Please go ahead. Your line is open.

Yes, thanks. So, John, wanted to ask about the – on the super-spec rigs, what is the sort of pipe-racking capacity that goes with that kind of asset?

Well, we have – again, it comes back to definitionally, we have the standard FlexRig3, which was 22,000 to 23,000 feet. We’re upgrading it to 25,000 to 26,000 foot range. But we’re only doing that upgrade and if you’re drilling 18,000, 20,000 foot wells, obviously, by definition, you don’t need that additional setback capacity. Flex5 came out standard with a 25,000 or 26,000 foot setback capacity, I believe, I’ve got that right. So it’s really, Robin, in response to what the customers needs are, we have that capability of with a pretty low cost investment of extending that setback capacity to 25,000 to 26, 000 feet.

Okay, thanks. I had another question on an unrelated. We’ve been hearing from other drilling contractors and service companies about quite a bit of tendering activity for land rigs in the Middle East, multiple countries. And wonder if you could comment on that and your level of interest in those tenders. Are they the type of rigs, are they for FlexRigs? Are they the type of rig tenders for, which your rigs are suited?

Yes, there has been some tenders, I don’t remember all the details. We have bid Flex3s in – on international projects. I think, we’ve also possibly even bid on some 3,000 horsepower work, which obviously, we have 3,000 horsepower SCR rigs as well. So we have participated, or at least, on the front-end of participating as far as I know we haven’t heard anything back, I think, it’s still in the early stages at this stage.

Okay. And finally, on the – you mentioned at one point that in the U.S. spot – average spot rates have come up a little bit from the lowest point. And I wonder if you could characterize – should we characterize that as a couple of thousand dollars a day, or is there some way you can frame that for us?

Well, they have begun to come up, I think, it’s – if you go back to our call in July and even some of the conferences that we’ve been – we’ve talked about, there would be a lot of competition coming off the bottom, kind of looking back in hindsight, you could say that May was the trough, and I think our lowest pricing was in August, and so we’re starting to see some improvements. I think to generally categorize $1,000 to $2,000 a day is a fine categorization again depending on the area, depending on the customer, depending on lot of things, but that’s about all the clarity that I think we’re willing to talk about at the stage. But I don’t think there’s any doubt that for high-quality rigs and high-quality performance, our expectation is that, they’ll start to become some pricing power in the market.

Okay, all right. Thanks a lot, John.

Thanks, Robin.

Thank you. Next, we’ll move to Marc Bianchi with Cowen and Company. Please go ahead. Your line is open.

Thank you. Maybe following up on that last line of discussion on kind of pricing. Can you talk to where some of these super-spec rigs kind of the – maybe how much of a margin premium, or are you seeing a margin premium for those rigs?

Marc, there are some today, I mean, we’re – and I say today recently I don’t know over the last several weeks. There has been some additional pricing capability because of the needs and particularly focused on the higher spec rigs, the super-spec type applications. So we are starting to see that for contracts that we’ve been bidding and that we’ve been awarded for the most part.

Okay, that’s great. But fair to say there is sort of upward pricing momentum across the spectrum of your offering?

I think so. That’s why we spent the time we did talking about the performance that we’ve seen. I think, again, customers are willing to pay for performance. Obviously, we’ve been in a one heck of a downturn and so to be able to be in a position to hopefully be able to get return on the investments that we’re making with these upgrades. So yes, that would be our expectation. But again, we expect it to be pretty slow.

Sure, okay. Maybe just one more on the CapEx that you’re talking about for 2017, I think, Juan Pablo, you said about 30% of that is directed towards maintenance, leaving $140 million for other stuff. I’m assuming most of that’s upgrade. That would imply perhaps you are upgrading more than the 40 rigs that you talked about to get from where you are now to the 120 at the end of next quarter. So just kind of curious, if that’s right or maybe what some of those other buckets might be?

Yes, I think that is fair. Of course, we’ve already spent some money in fiscal 2017 getting to the 80 that we mentioned. But it is fair to assume that we will continue to upgrade a fleet and some rigs require or we are planning for greater investment than $1 million might suggest. As John said, investments might require $2 million or more million dollars per rig. And so it’s a combination of making sure that we are ahead of the game, but we have great flexibility. We don’t have to upgrade all 270 rigs that are capable of becoming super-specs. But we are very well prepared to be ahead of the market and trying to make sure that the timing does not represent a bottleneck for us as we continue through, or I should say, as we hopefully continue through this recovery.

Okay, thanks. Maybe just, if I could, one more modeling. Is there an OpEx number we should be thinking about for standby rigs? Usually, we just sort of think about the pure margin there. But is there any OpEx associated with that that would maybe be showing up in the cost number? That’s all I have, I’ll turn it back after that.

Thank you. Yes, very low, very, very, very low. We’re talking about probably less than 10% – less than 5% of what a typical operating rig would be running at. We mentioned, we only have a handful of rigs on standby at this point that are generating revenue days and we’re protecting the margin on those, but it’s very, very low.

Thank you.

Thank you.

Thanks, Marc.

Thank you. Next, we’ll move to Robert MacKenzie with. Iberia Capital. Please go ahead.

Thanks, guys. I had a – I wanted to shift gears, I guess, maybe you said it, but maybe I didn’t catch it, offshore. I know you talked a lot about land, but offshore you’re guiding revenue days to be unchanged in the first fiscal quarter, but rig margin to expand quite substantially. Can you give us some color as to why that should occur?

Sure. So this is Juan Pablo. It’s been interesting to watch that segment about a handful of rigs the seven that were active and on customer platforms were receiving day rates on standby-type condition. So in essence, they were inactive by generating revenue. We’ve seen a couple of those rigs go back to work at operating day rates, which create, of course, margins that are higher than would be generated under standby-type conditions, and that’s creating a favorable impact that is and that’s why we are increasing, excuse me, that’s why we’re expecting an increase in the margins there.

So in terms of what you call revenue days then, if you’re receiving a standby rate even though it’s not working, you’re considering that a revenue day?

Yes.

Okay. Good. And then coming back to some of Michael’s questions early on about the term of new contracts, it sounds like you’ve said you are getting some term contracts of over a year now. But I didn’t hear your answer on how you are protecting yourself and preparing for either cost inflation or rates rising in the future. How do you think about structuring term contracts of over a year now to not give away too much upside?

So, Robert, this is John. We only entered into four and there was some, I’d say, it was a total of 10, okay, so you’re going. So there’s some particulars tied to why we entered into those. What we’ve been saying all along is that, don’t expect us to enter into a longer-term contracts at – in this kind of a pricing environment. The protection we have if price – if expenses go up then we have protection the contract to cover that, so our margin is held firm. But the majority of the contracts that we’ll be entering into and have entered into are going to be spot market base pricing. And so, our protection is in an improving environment is, it’s typically a well to well agreement, and we would increase pricing in the next logical well assuming we see that kind of pricing increase. Does that answer your question?

Yes, it very much does. And I guess, the question that also follows is, are those term contracts of one year or more, is there any kind of differentiation between kind of the standard Flex3 or 5 versus a super-spec rig, or is it across the board?

Some of those would have been standard rigs and some rigs would have had some upgrades and may have already had existing upgrades. I don’t know for sure, whether I know, we didn’t have the investment in all 10 of those. But some would be standard, some would be super-spec, and some of what we would have made the upgrade.

And, Rob, were you also asking about the pricing on those?

I think you guys already answered the pricing question.

Correct.

So, yes, I was asking more about just the mix. So, and then on the super-spec, just the whole capacity, I mean, given your capacity and what we’ve heard from others, does it sound like the established players have more than enough capacity to meet client demand in a fairly modest growth scenario?

My impression is, it’s pretty tight. I mean, based on what I’ve seen from the other contractors and again, Juan Pablo made the point, we’ve talk about what we could do. But we’re the only one that has a real upside and how we can respond without having to build a new rig or without having to have some pretty major investments. Our other peers have a fairly limited number of AC drive 1,500 horsepower rigs to source. And so my feeling is that, it’s a pretty tight market. So I guess, that’s my perception.

So that given that then coming back to the pricing question, and as a method here, do you expect to see the premium for these types of rigs continue to or expand or continue to expand over non-super-spec rigs?

Well, I think that’s logical. I mean, the reality of the rigs are working really hard. They’re drilling really good wells for customers that the rate on the rig doesn’t really move the cost needle on the curve. So I think there is an opportunity to increase pricing, again, we’re starting at a very low level. But anything, I think, at this stage of the game, we would all be pleased to just get some additional $1,000, $2000 a day here and there. So, yes, I think there’s some opportunity. I don’t think there’s any doubt that the rig – the super-spec rig should command a premium over rigs that don’t have those additional investments, or don’t have the capability, or don’t perform well. I think that’s the other point to make is just, because you have the rig that doesn’t mean that you’re going to necessarily be able to deliver the performance and the value that customer requires.

Great. Thank you. I’ll turn it back.

All right, Robert. Thank you.

We probably have time for one more question.

Thank you. We’ll take our final question from Sean Meakim with JPMorgan. Please go ahead. Your line is open.

Hey, thanks. Just to continue on that line of questioning, you were characterizing the market or the supply for super-spec rigs as being limited in the press release and you’re saying you think the market is fairly tight. We’ve heard from your other peers this quarter; just offhand, I think the count as well over 100 rigs that they say are upgradable as a collective group. So you add that with yours. Given the modest capital costs, how quickly these rigs can get these upgrades kind of in-between jobs, doesn’t that suggest that we need to put a couple hundred more rigs back to work in this class in order to see pricing gains continue, or it seems like, honestly, you don’t seem to agree with that?

Sean, I’ll make certain. I understood your question. So you’re saying that we’ve made the comment that there seem to be a tighter supply and you’re suggesting that there’s over a 100 that would be available outside of your….

Among your peers?

…among our peers, yes. And I think that’s where if you start to think about it in terms of rather than looking at it as an entire fleet of rigs and focus on the rigs that are growing horizontal and directional wells that do have the higher capability needs not just, because somebody wants it, but because they need it. That’s when you start getting into more of a scarcity, where I think you have the potential for, at least, some pricing power, and I’m not talking about $25,000 a day. I’m just – I’m talking about getting additional getting higher rates and improving our margins. I’m not making any sort of prediction on how high they might go. But I think that does begin to tighten the market. I think the other element is that these rigs you can’t just continue to drill the kind of wells that the industry is drilling and not get paid for it as a contractor. The rigs are working harder. You get 7,500 psi pumps. Engines are working harder. Pumps are working harder. We’re using more consumables. Costs are going to have to, I think, you begin to put cost pressure in the equation. So, I think, in general, we’re going to see improved pricing. I think there is an opportunity to differentiate substantially over our peers, I think, that’s as we have in the past, we’re going to be able to command a premium.

I guess, what I was trying to get at is by last count earlier this year, there was perhaps like 300 super-spec rigs to use a round number, and another 400 across the rest of the group that could be upgraded to that under the conditions we discussed earlier, which are pretty simple. So if that’s the case, what I’m saying is, it seems like the supply of available rigs to do that kind of work, it seems like it’s pretty considerable relative to where the horizontal rig count is today, and even though, there’s a subset that’s not necessarily looking for this pad-optimal work. So I just – that’s what I was trying to get at is just the slack seems like there’s still a good bit out there outside of the optionality you guys have?

Right. Well, and that’s part of the problem is it, it’s not the quite the “super-spec” rig isn’t as transparent as I’m sure everybody would like and I think everybody’s to a degree working from a different definition. We’ve seen a range published of 150 to 250 rigs that are "supper-spec”. There’s a little over 700, 1,500 horsepower rig – AC rigs, but we don’t believe all those have the capability to be upgraded to super spec capacity. They don’t have the mass structure. They don’t have the higher hook load capacity. I think there’s a fewer number of rigs than people are anticipating that are capable of doing the kind of work it’s being done. But again, that that’s our perspective. It’s hard to nail it down, because you don’t have all the facts.

Understood, that’s a very fair point. Those would be important caveats. Just the last piece I guess to end this would be, for these upgrades that you are doing, are you effectively willing to fund them on spec, or is the idea that you need to get some level of increase in rate to justify that capital commitment?

Well, up to this point, it’s been the price of admission to work the rig in the areas, where it’s been needed, and again, not all rigs needed, I think, what is it David, 80% of our working fleet is super-spec, is that I suppose.

Yes.

So we still have customers that they don’t need that the higher spec. So – but our intent is to get paid for that. I think, in general, we’re probably getting paybacks in one to two years is kind of the way we’re looking at it. But I think, in a lot of cases, that’s going to be the price of admission to compete on these wells.

Got it. Yes, thanks for all that detail, John. I appreciate it.

Thank you.

Thank you. At this time, I’ll turn the call back over to our speakers for closing comments.

Hi, Tony, thank you. I want to just quickly thank each of you again for joining us on the call today. And before I – we sign off here just a couple of quick final thoughts just to reiterate, we believe our AC FlexRig fleet is positioned to take market share and a strong or even a moderate U.S. land market recovery. We think we’re uniquely leveraged to provide E&P companies the rig of choice to drill the more challenging horizontal wells. The design of our FlexRig fleet allows for a broad range of rig upgrades, providing a family of solutions for our customers. So we thank you again for your time and have a good day.

Thank you. This does conclude today’s conference. You may disconnect any time and have a great day.