Helmerich & Payne, Inc. (HP) Q3 2016 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to the Helmerich & Payne Third Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, you will have the opportunity to ask questions during the question-and-answer session. [Operator Instructions] Please note, this call is being recorded. It is now my pleasure to turn the conference over to Manger of Investor Relations Mr. David Hardy [ph]. Please go ahead.

Thank you, Keith. And welcome everyone to Helmerich & Payne's conference call and webcast. 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 last page of today's press release. I'll now turn the call over to John Lindsay.

Thank you, [ph] Dave, and good morning, everyone. Thank you for joining us on the call. Even though oil prices have pulled back over the past several weeks, it is still encouraging to see signs of optimism in the market. In May, the Baker Hughes U.S. land rig count hit a low of 380 rigs and has since increased from what everyone hopes was the absolute bottom of this market cycle. Recently, some E&P companies have announced budget increases and rig count additions. It is a positive sign, although many still remain on the sidelines. This has been an extraordinary downturn, over 1,400 rigs have been idled in the U.S. and tens of thousands of industry participants have been laid off. The impact has been pervasive and has affected every enterprise within the industry. H&P remains very strong and has been proactive and effective in adjusting to this new environment, but the declines in activity and spot pricing have significantly impacted our bottom line and the size of our organization. An improving market holds these two trends, I believe that H&P is uniquely positioned to grow market share in the increasingly complex drilling environment, that will attend most, if not all, of the unconventional shale plays going forward. Operational excellence is one of our competitive advantages in capturing market share. Part of our core purpose is to manage and improve performance in all aspects of the well cycle, and we continue to invest in tools and processes that will increase our reliability for customers. The industry has long-held to a show-up and fix-it model, when dealing with rig equipment downtime, but our model is preemptive and predictive, developing systems that utilize predictive analytics, reduces non-productive time, enhances reliability and optimizes operational performance. The complexity of horizontal shale wells, demand advanced technology solutions to drive high levels of performance and reliability. Shale customers have high expectations, and concurrently, well complexity is increasing as a result of extended laterals. From a rig requirement perspective, extended laterals require more hydraulic horsepower and greater capability, which is why 1,500 horsepower AC rigs are the rig of choice. H&P has close to 50% of the available 1,500 horsepower AC rigs in U.S. land, so we're positioned very well in the market. We currently have 90, 1,500 horsepower AC rigs under contract and 234 idle AC FlexRigs available to go to work. While we aren't building new rigs, we are investing to enhance capabilities that will benefit our customers in this more challenging and complex environment. Not only are we investing to enhance our fleet, we are having great success in partnering with customers and moving new ideas quickly into our operational deployment. We can do this on 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 through the cycle and with our eyes on the future. Before turning the call to Juan Pablo, I'd like to end by saying this downturn has lingered on for over 20 months and very recently, some respected companies have called the bottom of the market. If that is the case, H&P has the operational capacity to respond quickly, given the investments we have been making in the fleet and our organization throughout the cycle. Whatever the demand might be going forward, we believe that the strategies we are employing coupled with our financial strength, give us superior competitive footing to grow market share in an improving market. We have the largest spare capacity of 1,500 horsepower AC rigs strategically located in the strongest basins and an unmatched ready state of our rig fleet to return to work. 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 $21 million during the third quarter of fiscal 2016. Nevertheless, after six consecutive quarters of reduced drilling activity, we are now expecting slight quarter-to-quarter improvements and the number of revenue days during the fourth fiscal quarter. Following are some details on each of our three drilling segments. Our U.S. land drilling operations generated approximately $26 million in segment operating income during the third fiscal quarter. The number of revenue days declined by approximately 22%, compared to the prior-quarter, resulting in an average of close to 82 rigs generating revenue days during the third fiscal quarter. On average, approximately 72 of these rigs were under term contract and approximately 10 rigs worked in the spot market. Excluding the impact of early termination revenues, the average rig revenue per day declined by approximately 5% to $24,684 in the third fiscal quarter, as a proportion of rigs generating revenue days under standby-type day rates increase significantly quarter-to-quarter. The average rig expense per day decreased by approximately 4% to $13,417, excluding employee severance expenses. The decrease in the average rig expense per day was also attributable to a greater proportion of rigs on standby-type day rates, which was partly offset by expenses related to the growing proportion of total idle rigs. The corresponding average rig margin per day during the third fiscal quarter was $11,267. The segment generated approximately $81 million in revenues corresponding to early termination of long-term contracts during the third fiscal quarter. Given existing notifications for early terminations, we expect to generate approximately $30 million during the fourth fiscal quarter and over $40 million thereafter in early termination revenues. Nevertheless, about half of the mentioned early termination revenues that we expect to be recognized after the third fiscal quarter of 2016 are attributable to compensation that, as of June 30, had already been invoiced and collected and that is included in the current liabilities section of our June 30, 2016, balance sheet as deferred revenue. As mentioned in the past, we cannot fully recognize the early termination revenue on a rig until all contractual customer options take that rig back to work at full day rates have expired. 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, up one rig since our last conference call in early May. Total early termination revenues related to these 88 contracts are now estimated at approximately $466 million, about $88 million of which corresponds to cash flow originally expected to be generated through normal operations during fiscal 2015, $179 million during fiscal 2016 and $199 million after that. As of today, our 348 available rigs in the U.S. land segment include approximately 91 rigs generating revenue and 257 idle rigs. Included in the 91 rigs generating revenue, are 72 rigs under term contracts, 67 of which are generating revenue days. In addition, 19 rigs are currently active in the spot market, for a total of 86 rigs generating revenue days in the segment, as compared to 78 rigs during our last update in early June. Nevertheless, approximately 14% of these 86 rigs are now idle and on standby-type day rates, which protect daily margins under long-term contracts. Separately, the five rigs that are not generating revenue days include new build rigs with deliveries that have been delayed in exchange for compensation from customers. Of note, the number of our rigs active in the spot market has increased from eight rigs to 19 rigs since our latest update in early June. Looking ahead to the fourth quarter of fiscal 2016, we expect a quarter-to-quarter increase in the range of 3% to 7% in the number of total 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 $24,000, primarily as a result of a higher proportion of rigs working in the spot market. The average pricing today for the 19 rigs in the spot market is over 35% lower as compared to stock pricing at the peak in late 2014. The average rig expense per day is expected to decrease to roughly $13,300. This expected decrease is primarily attributable to ongoing efforts to effectively manage our costs. Absent any additional early terminations and excluding the mentioned rigs, for which we have received early termination, notifications. The segment currently have term contract commitments in place for an average of approximately 67 rigs during the fourth fiscal quarter, 62 rigs during fiscal 2017 and 34 rigs during fiscal 2018. The average daily margins for these rigs that are currently under term contracts is expected to remain strong at over $15,000 per day, during the next several quarters as some rigs roll off and the remaining new builds are deployed. Let me now transition to our offshore operations. Segment operating income slightly declined to approximately $2 million from $3 million during the prior-quarter. Total revenue days declined by about 8% and the average rig margin per day increased by about 1% during the third fiscal quarter to $7,981 per day, excluding employee severance expenses. Most of the rigs that generated revenue during the third fiscal quarter were rigs that remain idle on customer-owned platforms and are generating standby day rates. As we look at the fourth quarter of fiscal 2016, we expect quarterly revenue days to slightly increase by approximately 1%, as seven of our nine offshore platform rigs continue to generate revenue days during the quarter. The average rig margin per day is expected to remain relatively flat at approximately $8,000 per day, during the fourth fiscal quarter. Management contracts on platform rigs continued to contribute to our offshore segment operating income. Excluding, the impact of employee severance expenses, their contribution during the third fiscal quarter was approximately $3 million. Management contracts are [Technical Difficulty] each of the next few quarters. Moving on to our international land operations. The segment reported operating losses of approximately $5 million during the third fiscal quarter, excluding the impact of employee severance expenses, the average rig margin per day decreased sequentially by approximately 12% to $9,461 per day, partly as a result of a greater number of rigs generating standby-type day rates during the third fiscal quarter. Quarterly revenue days decreased sequentially by approximately 3% to 1,274 days during the same quarter. As of today, our international land segment has 14 rigs generating revenue days including 10 rigs in Argentina, two rigs in the UAE, one rig in Colombia and one rig in Bahrain. All 14 rigs are under long-term contracts. The 24 remaining rigs include 22 rigs that are idle; and two rigs, one rig in Argentina and one rig in Colombia that are now contracted and expected to commence operations during the quarter. We expect international land quarterly revenue days to increase by approximately 5% to 10% during the fourth quarter of fiscal 2016. And the average rig margin per day to decline to approximately $8,300 per day. As a result of several factors, including a temporary rate reduction for one of our rigs. Let me now comment on corporate level details. We were pleased to announce last month, a slight increase to our quarterly dividend to $0.70 per share. As previously discussed, our strong balance sheet and high liquidity position, along with our firm backlog of long-term contract and reduced CapEx requirements should continue to allow us to sustain the level of our regular dividend payments during the foreseeable future. Excluding rigs with long-term contract that have been early terminated and combining all three of our drilling segments, we currently have an average of approximately 77 rigs under term contracts expected to be active in fiscal 2017, and 47 rigs in fiscal 2018. Our backlog level as of June 30, 2016, was approximately $2 billion. Capital expenditures for fiscal 2016 are expected to be in the range of $300 million to $350 million. We were also pleased to announce earlier this month, a new five-year $300 million revolving credit facility that essentially replaced a very similar facility issued in 2012 that was set to expire in May of 2017. Over recent years, we have only been using our revolving credit facility to support the issuance of letters of credit. We are reducing our total annual depreciation expense estimate for fiscal 2016 to approximately $565 million. And we are increasing our total general and administrative expenses estimate to approximately $150 million. The reduction in the depreciation expense estimate is primarily attributable to lower capital expenditure levels and to new arrangements and customer requested delivery delays, related to some of our new build FlexRigs under long-term contracts. The increase in the G&A expenses estimate for the year is mostly attributable to items related to employee workforce reductions, including required employer 401K plan matching contributions, pension settlements and employee severance expenses. The effective income tax rate for the first nine months of fiscal 2016 was 63% and we expect the effective tax rate for all of fiscal 2016 to be in the range of 75% to 80% at this point. These effective tax rates are higher than expected, primarily as a result of significantly reduced earnings before taxes, combined with prior-year tax adjustments that impact this year's tax rate, such as the fiscal 2015 adjustment to the domestic production deduction mentioned earlier this year. That resulted from a U.S. tax law change in December 2015, extending bonus depreciation allowances that had expired December 31 of 2014. You may recall that this bonus depreciation adjustment had a very favorable impact in reducing our cash tax obligations by roughly $60 million. This adjustment allowed us to benefit from a tax refund this year and to currently have a significant prepaid tax balance. The quarter-to-quarter increase in the line item other current assets in our condensed balance sheet is primarily a result of a corresponding increase in prepaid taxes and taxes receivable. With that, let me turn the call back to John.

Thank you, Juan Pablo. I thought prior to opening the call for questions, we would provide a little more clarity on the rigs we put to work in the spot market. We've been pleased with our ability to respond quickly to customer requests and provide problem free startups and deliver very safe, efficient and reliable performance on the first wells we drilled. We have reactivated 14 rigs in the spot market, 10 rigs are FlexRig 3s and four rigs are FlexRig 5s, and approximately 75% are pad capable with 7,500 psi capability. In addition, we've added six new customers in the past quarter. One of the benefits of a downturn is having more opportunities to introduce and attract new customers to FlexRig technology. So, we're hopeful the market has made its bottom; but regardless of the timing, we will continue to make every effort to emerge from this as a stronger company for customers, employees and shareholders. And Keith, we will now open the call for questions.

Thank you. [Operator Instructions] We'll take our first question from Angie Sedita with UBS. Please go ahead.

I'm sorry, Angie, we're having difficulty.

Can you – there you go. Is that better?

Yes. Thank you.

So, good morning.

Good morning.

John, you made a couple of comments on the cycle, and the first one you said is that the customers remain optimistic. And clearly, you put 14 rigs here back to the market at the spot rate. Have you seen any change of incoming calls or the pace of conversations as far as interest in adding rigs into the back half of the year? Are the customers just as interested as coming back? Are you seeing a little bit of delays until later in the year or even 2017?

Well, I think, I don't know that we've seen any significant change in call volume over the last several weeks, obviously, we're all painfully aware that, that oil continues to pull back. But I think, in general, I described our customers is continuing to be very disciplined in their focus, looking at performance and reliability. I do think, all along, it seems like, at least many of our larger customers have been more focused on probably a September, October, November, timeframe. I think starting at the earliest in September. Obviously, we've had some other customers, as I described, we've got some new customers on board and we put a few rigs to work for them. So, that's been a positive. But, I think, in general, I think we all saw the optimism, there is some concern and I think drives a little bit of lower confidence levels as it relates to this lower oil price environment.

Okay. Okay. That's fair enough. And then you made the comments about investing through the cycle, which you certainly have in prior cycles. So, when you think forward into 2017 and 2018 and specifically 2017, could you restart at a slow level your new construction within the organization? And if so, what rig design would you focus on?

Well, we definitely have the capability, Angie. As we've mentioned previously, we're utilizing that manufacturing capability today. And we have really throughout the downturn, but we've been utilizing that manufacturing capability to upgrade rigs with 7,500 psi, some setback upgrades, just overall looking at upgrading the fleet as needed in order to meet the challenges. Clearly, we could start backup and get our manufacturing capability up and running. It wasn't that long that we just delivered that last new build. So, we can sure do that. Obviously, there is, from a timing perspective, we could do that in 2017, we could do it in 2018, obviously, it's going to require, I think a – it's going to require a strong enough market to deliver much higher day rates and what we see today. I think, in terms of the rig that we would build, I would think more than likely it would be FlexRig 5s as well as some other ideas that we have out there that – obviously, there is not the market to build those style of rigs into. But, again, in an improving market, in a market that required more AC drive rigs or at least quality AC drive rigs, I think we'd be very well positioned to respond to that.

Absolutely, with your fleet. And then, as a follow-up on that, you obviously unstacked 14 rigs here pretty quickly. Are you seeing any bottlenecks on the people side or equipment side? Any thoughts there?

No, I don't see any bottlenecks. The people side has been very good, as we've mentioned before. We obviously have a lot of very experienced employees on the rigs, and I think obviously everybody does. But, we have a lot of men that are ready to step back up into their previous position, step back into rig manager jobs and driller jobs and [indiscernible] positions. So, really no issues at all. It's been very good; again, it's been efficient, it's been safe. And I think it's obviously encouraging for everybody in the field to see some rigs going back to work. So, the morale obviously has improved; and, again, we're prepared, we can respond pretty quickly, and there's no equipment bottlenecks that I can think of.

Okay. Perfect. Thanks so much, John. I'll turn it over.

All right, Angie. Thanks.

We'll go next to Timna Tanners with Bank of America Merrill Lynch.

Yeah. Hey, good morning, guys.

Good morning.

There have been a lot of comments in this earnings season about E&P customers needing to get prepared to pay up for services. Wanted to get your thoughts on how to think about pricing power and what it might take to be able to lift day rates?

Yeah. That's a good question. Obviously, everybody would like to have greater insight into that. I think, we've – we've felt pretty – or consistently said that coming off of bottom, pricing is going to be highly competitive. At the same time, as we described in our remarks, the drilling environment is becoming more and more complex, which means that, contractors are having to upgrade rigs. And so, I think, that in and of itself would potentially drive some higher rates – again, not right off the bottom, but maybe earlier in the cycle. We've described or it's been described as 700 AC rigs, that are 1,500 horsepower and I think – what is it around 250 rigs or so, that are working today? Ballpark range, 250 rigs to 300 rigs. So clearly, they'll need to be some rigs that will go back – need to go back to work in order to begin to drive pricing power; but again, I think this cycle is much different than previous cycles, because the legacy rigs, really aren't playing a role in that. They are drilling, I don't believe those rigs are targeting the more complex well designs. Most of the mechanical rigs, I think over 70% of the mechanical rigs that have been reactivated since the bottom of the cycle, assuming that is the bottom of the cycle, most of those are going to vertical type work. So, I know it's not a direct answer. I don't think anybody has the direct answer; but I think, in general, it's going to be different than previous cycles. I do think pricing kicks in at a much lower rig count than what we've seen historically.

Okay. That's fair. And along those same lines, do you find in your conversations with customers that you're exclusively negotiating on price? Or do you find that they're really having more of an appetite to discuss the characteristics of the rig and the greater productivity of the rig? Or is it really still focused on price?

Well, I think clearly they're going to be interested in both. One way, I would describe it is, it's a value proposition discussion. So, I think, when you think about it in those terms, there is always an element of – there is an element of cost and there is an element of the value that you can provide, in terms of – obviously, safety is key and reliability is key and the type of rig is key. And then, I think also having a track record of performance. So, again day rates in the spot market today are, I would describe as soft. I mean I think we've mentioned 35% off of the peak. And that's similar to what we saw. I think it was 30% back in 2009. So, I think we're starting at a similar place, but clearly the market is different in terms of the types of wells that we're going to be drilling.

All right. Thank you.

All right. Thank you.

Our next question is from Kurt Hallead with RBC Capital Markets.

Hi, gentlemen. How are you?

Hi, Kurt.

Hi, Kurt.

Great. I appreciate, as always, the color commentary. So, I just want to get a general sense from you guys that – a lot of discussion, continues discussion about pad optimal rigs and pad rigs. I think the last time that you and I, as a group, had a chance to visit, you mentioned that you didn't have any kind of pad rigs in your inventory, because you're not getting any, really, demand pull from that side from the E&P. So, I was wondering if you could just provide a little color on the market dynamics and what is it that your customers are really looking for in the land rig these days.

Kurt, I want to clarify, you had, you mentioned that we don't have any pad rigs in our inventory, are you talking about the walking...

Yes, walking, walking, yeah, walking. Yeah.

Okay.

Yeah.

Yeah. No, I think, of course, we're always thinking about it and we get questions, it's interesting as I was coming in this morning and kind of thinking about how long this has been talked about. I think it's actually going back to 2013. So from one perspective, from our perspective, there really isn't much of a debate to be had, because of the number of new rigs that we've built since 2013 that are skid system, FlexRig – additions on to our Flex 3s and then the FlexRig 5. And of course, we've had the FlexRig 4s for years and years. But we've also said, Kurt, that if the market or if customers decide to begin or say to HP, hey, if you really need to have a walking application, and we have the capability, we have the designs, it's just a matter of doing it. I don't see it impacting our activity, go back to the 14 rigs that we just put to work; 10 rigs Flex 3s, four rigs Flex 5s, 75% of those rigs are in our view are optimized for drilling on pads, and obviously the customers are thinking that as well. So, does that answer your question, Kurt?

Yeah, I think, I think, generally, and – yeah, there has been discussion about walking rigs and a preference for walking rigs, along with some other elements of the package. And being the largest land drilling player out there, clearly walking rigs is not the best majority of what the market is or what's in E&P. So, I really just trying to gain some insight. Is that walking capability absolutely necessary? Or is it something that's more like a nice to have?

Well, I wouldn't, well, clearly just based on our track record and working with customers. It's not an absolute necessity. Are there going to be applications for walking, applications in the future, for us I think there's a possibility, yes, that could be the case. But, it's not a situation where you're eliminated from contention and competing, if you don't have a walking system. Again, I think we've been able to demonstrate that.

Got it. Okay. Great. That's great color. Thanks, John.

And, Kurt, if I may add, this is Juan Pablo. Just to clarify, we have close to 190 of our FlexRigs that are pad capable, and we believe optimal for multiple well pad drilling applications. That's over 50% of our existing fleet in the U.S. land. And I just wanted to make sure that we provide the clarity that we do have a solution that we believe is better, or at least comparable to the walking systems that you are referring to.

And I also believe that of the rigs that are working, that we have operating today 75% of those are pad. And again, in our view optimized for pad and I think our customers would agree with that.

Great. Maybe just one follow-up, guys. Appreciate that color. So, you mentioned that spot pricing is 35% lower than the peak in late 2014. I think the last time, if I'm not mistaken, it was down 30%. So, we had some degradation, I guess, during the course of the June quarter. Are we at a point now where pricing is going to stabilize?

Well, well we hope, obviously we hope so. But, I'm not convinced if that's going to be the case. Again, a lot of rumors and a lot of things that you hear on some really low rates that are being thrown around out there that, when you hear about jobs that you've lost, it's hard to say whether that's accurate information. But as I said, a little earlier. I believe coming right off of bottom, which we still are, it's going to be highly competitive and there will be some irrational pricing that will take place. I think eventually that begins to work itself out, after putting a number of rigs to work. And in particularly, when you see some early examples of companies with low rates and low performing rigs, that's not a good combination when you're drilling the types of wells that are being drilled out there. And I think that's really what you'll see and I think that has the impact of beginning to improve pricing.

Appreciate it. Thank you.

Thanks, Kurt.

Thank you.

And we'll go next to Marc Bianchi with Cowen. Please go ahead.

Thank you. Thanks for providing the margin commentary as it relates to the long-term contracts. Can you say where that $15,000 was in the last couple quarters? Has it been pretty steady? I understand the outlook is for it to be pretty steady but just curious where it was last couple quarters?

Thanks, Marc. This is Juan Pablo. That is correct. It has been pretty steady. As a matter of fact, it's been slightly going up over time over the last several quarters as we have rigs rolls off and new builds deployed, et cetera. The new mix is driving a slightly higher average there.

Okay. And that just to be clear, how many rigs does that apply to? I think there's 72 under term contract, but there's some that are on the deferred delivery bucket. Can you just clarify what that $15,000 per day applies to?

Yes. It applies to 67 that are generating revenue days that were mentioned.

Got it. Okay. Thank you.

And as we move forward, you heard us talk about how many rigs we expect or we already have under term contracts for fiscal 2017 and for fiscal 2018, those rigs also are generating that type of margins.

Right. Okay. Thanks for that. Maybe just moving over to international, it sounded like the margin decline – you called out the rate reduction, but then there were some other factors. I guess, could you say how much of the margin decline comes from the rate reduction and then maybe comment on the other factors, if perhaps it's mix or whatever might be going on there?

This is Juan Pablo again, I don't have that exact information in front of me. As we've mentioned, we have a situation where we've had some rigs go to standby-type day rates that has impacted our margins. We've had a reduction as well, temporary reduction for one rig. Those are some of the higher impact items, but I'm sorry I can't provide greater granularity than that.

Okay. Can you say when the temporary reduction goes back to the original rate?

We expect that to happen during this quarter.

Okay. Okay. Thanks for that. Maybe just one more, if I could – I know that this has come up before and you guys have offered some thoughts. But, in terms of the deferred tax liability, if there isn't any new building going on, but you are generating positive net income or positive pre-tax income, how should we think about how that liability winds down over time?

Well, it's currently at around $1.4 billion, slightly under that. As we've said – I believe late last year, we would expect it to remain in the range of $1.2 billion to $1.4 billion through the end of fiscal 2017. So, we don't see any significant changes. If we were to assume that CapEx once again increases during the following years to anywhere – near where the depreciation levels, financial depreciation levels might be, then that liability level would remain relatively flat. If we have a very low CapEx environment for a long time or several years, then it's a very long tail, but slowly during those years you would see that liability decline. But, in no significant way that would impact our liquidity to the point that, that we would be concerned at this point.

Yeah. You guys certainly have a lot of room there. Okay. Thank you very much.

Thank you.

Thanks, Mark.

We'll go next to Rob MacKenzie with IBERIA Capital.

Thanks, guys. With 75% of the new rigs put back to work, to your words, John, pad capable with 7,500 psi mud systems, can you give us a feeling for, A, how many of your remaining idle rigs are similarly kitted out as well as any kind of estimate you have for the broader market?

Well, Juan Pablo mentioned a few moments ago about the number of, I think, he mentioned a number of idle pad capable rigs. Maybe you were just talking total, that would be total, the idle number of pad capable would be 119.

Yeah. So, a significant number, Rob. We do have pad rigs with 7,500 psi that are idle. For competitive reasons, we haven't shared that with anyone we did talk about the rigs that we put to work. Obviously, we're continuing to add 7,500 psi systems. But, we haven't shared that. Was there another part of your question that I missed?

Any of the broader market for that – it sounds like, given the fact that you are adding the 7,500 psi capability as well as others, that there is a potential scarcity of rigs with that spec. Is that fair?

My impression is that is fair. I think it's another element of this 1,500 horsepower AC rig. And the other capabilities. It's not just 7,500 psi, it's also upgrading setback capacity to be able to handle, as an example, 25,000 foot of setback of five-inch drill pipe. And not all AC rigs are capable of handling that sort of a setback upgrade. And so, then you begin to ask yourself, do you really want to invest in 7,500 psi and then not also be able to do the setback. So, there is a lot of variability. Fortunately for us, we have that capability with our engineering staff. And as I mentioned earlier, the manufacturing capability, I think we're able to do that much more efficiently and more cost effectively than most. But no – I do – I think it's going to be a bigger driver. I don't think it's a situation where every rig necessarily needs 7,500 psi, but you'll begin to see more and more.

Thank you. And on those rigs with 7,500 psi, about what portion would you say are utilizing a third mud pump these days?

I think it's a relatively small percentage. I really don't have – again, it's one of those things that we haven't, we purposely haven't shared for competitive reasons. But I think, just in general, there's less demand for that third pump as compared to the demand for the 7,500 two pump operation.

Okay. And if you don't mind, do you mind sharing how long it would take you to say, convert a Flex 3 to the 7,500 psi with the setback you mentioned and what the cost might be?

Well, again, we have some upgrades ongoing. So, obviously, it's a demand pull basis. From my perspective, it's kind of irrelevant for us as far as how much time. I think we're – maybe away for us to summarize it is, we have the capacity to deliver based on what we think the demand is going to be. As far as total costs, Juan Pablo, I don't know.

I don't have the latest on that. John, sorry.

Ballpark it just seems like it's in the $750,000 to $1 million range, I think that's a ballpark range. I think that's probably close enough.

Okay. Thank you, guys. I'll turn it back.

All right, Rob. Thank you.

Our next question is from Sean Meakim with JPMorgan.

Hi, good morning.

Good morning, Sean.

Good morning, Sean.

So, I just wanted to talk a little bit about this cycle versus the prior. You noted earlier a very different cycle on pricing, given the big shift in rig mix toward AC. Obviously, this downturn also much different in terms of the duration, the level which could be a trough here. Does any of that change how you think about your strategy in terms of contracting terms, duration and things like that? How do you think about building that portfolio effectively as we go in the other direction?

Well, you summarized it very well. This downturn is entirely different and the reality is even though there is many that have called the bottom and we all hope that they are right, the fact is, we've had continued softness with oil over the last several weeks. I think, as you think about rigs that we have that are rolling off of term contract, it could be that some of those rigs we would be interested in – if the customer were interested in entering into term contract. I think for the foreseeable future, it's hard to really get your arms around, being able to enter into any sort of a term contract commitment unless that's exactly what the customer wants to do. The contractor is not going to be the one making that decision or having any control over that. Clearly, we'd have some interest in some term contracts, if the day rate was reasonable. I think the other element, which again, I think I've already mentioned is, we've got these new investments that are happening as well. And there is a limited amount of that that you can do before you begin to get higher rates and a commitment of term.

Got it. That makes sense. And then the 14 rigs that you've picked up thus far – could you maybe give us a little more granularity just as we're trying to get a better sense of the underlying activity, maybe rigs that were negotiated versus bid? Are you seeing the same customers come back to some of these rigs that have been idled? Just trying to get a better sense of the underlying activity.

Well, I don't have a lot of additional granularity. I do believe that eight of those rigs – eight rigs of the 14 rigs were in the Permian, and there were a couple in Niobrara and there were – there was, I think a couple in Oklahoma, one in Haynesville, and maybe one in Piceance, I mean, they were – but again, the majority of the demand is coming out of the Permian. You guys – anything else that you can think of to add color-wise?

No. Did that address your question, Sean. I'm sure I might have missed a specific.

No, it's not a big deal. I was just trying to get a sense for were these negotiated with customers, or any of them bids that you won? Are you seeing some customers requesting rigs they had previously used as they go back to work? Just trying to get a little bit more sense of...

Sure. Yeah. I think – again, I don't have the numbers in front of me, but my sense is that many of those were negotiated. I do think there were some bids. I think, there was a question earlier and some customers are different, but where we have our greatest opportunity to pickup share or pickup as I said that we have six new customers in those rigs that we put back to work, which is pretty significant. But when they're looking at the value proposition and they're not just looking at the rate, which most companies don't, particularly the larger, but we're starting to see even some smaller operators that we've developed a really good relationship with and they've seen the value. And so, I think that's – that weighs in a lot, is having that ability to sit down with the customer and kind of go through the process and talk more about the value proposition that you can provide. And so, that's always helpful. That's really about the amount of clarity that we have in those details.

That's very helpful. Thanks a lot. I appreciate it.

Okay.

Thank you, Sean.

We'll go next to Scott Gruber with Citigroup. Please go ahead, Scott.

Good morning.

Good morning.

Just coming back quickly to the rig upgrade line of questions, John, I think it was you, you mentioned about $750,000 to $1 million upgrade. That's just for the pipe retrofit and the setback, et cetera. that does not include this skid system? Is that correct?

Correct.

And then if you were going to add a skid system, as memory serves, they used the cost around $1 million. Is that still the case or has that come down?

I think that's still in the ballpark. Yeah, I don't think that's changed much.

Got it. And then is it safe to say that – I know you're not going to give us the exact number of rigs you have in the sweet spot of demand today. But, is it safe to say that you are long on the skid side, much longer on skid systems versus 7,500 circulating systems?

Yes. We had mentioned earlier, the number of pad, rigs that we have, and we don't have that many 7,500 psi. We do have a pretty fair amount; but again, I'm not going to give that kind of granularity. But, clearly, the 7,500 – while we've had 7,500 psi mud pumps, systems for years, I mean, literally, I can remember a few new builds we've built probably five years ago. But, the fact is that, the systems were very seldom used to their full capability. Well, today, they're being used at a much higher level, and again, it's been driven by these much longer laterals, kind of the extended type laterals that we're talking about. So, that's what's driving that. But again, like I said, I think we're positioned pretty well based on the demand that we think we could possibly see in an improving market that we would be very well positioned to add enough systems to fulfill the demand that we would expect.

And you're hugely advantaged today, because you have long cash that you can make the upgrade investment without thinking about payback. As the industry starts to shift towards upgrading and thinking about payback on the upgrades, how do you think others will think about that payback? Will they look for a one year, will they settle for a two year to three year?

Well, that's a tough one, Scott, because, I mean, it's hard to say what others would do. I know what we've typically done, I mean, you can look at our track record in terms of new builds and these kind of investments over time. And that would be our expectation in an improving market, is that we're going to get the return on our investment. Juan Pablo, you have any other – anything to...

Yeah. I agree, I mean, we've proven over the years that we pay a lot of attention to returns as we invest new cash. We've been very prudent in that regard. You have to compare that to what our competitors have done. But, overall, I think it's fair to expect that some investment will take place and folks will have different levels of discipline.

Got it. Thank you.

Thanks.

And it does appear we have no further questions at this time. I'll return the floor to you Mr. Lindsay for closing remarks.

Okay. Thank you, Keith. I want to thank each of you for joining us on the call today. And before signing off, I want to leave you with a few final thoughts. As we've said, we think we're very well positioned as a result of our strong balance sheet. We have the largest and most modern fleet of AC drive rigs in the industry, and we have what we believe the best people in the business that are committed to delivering value to customers and shareholders. We believe we are in a great position to continue to gain market share going forward. And with that, we will sign off until next time. Have a great day. Thank you.

And this will conclude today's program. Thanks for your participation, you may now disconnect and have a great day.