Helmerich and Payne Inc (HP) 2016 Q1 法說會逐字稿

Good day, everyone, and welcome to today's program. (Operator Instructions) Please note this call is being recorded. It is now my pleasure to turn the conference over to VP and CFO, Mr. Juan Pablo Tardio. Please go ahead.

Thank you, and welcome, everyone, to Helmerich & Payne's conference call and webcast corresponding to the first quarter of fiscal 2016. The speakers today will be John Lindsay, President and CEO; and me, Juan Pablo Tardio. Also with us today is Dave Hardy, Manager of Investor Relations.

As usual and as defined by the US 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 will now turn the call over to John Lindsay.

Thank you, Juan Pablo; and good morning, everyone. Thank you for joining us on the call today.

Our first fiscal quarter results were better than expected, primarily as result as significantly reduced daily rig expenses in our US land segment. Unfortunately, US land drilling activity has declined to levels not seen since 1999, as very low oil and gas prices are forcing customers to make further reductions in their drilling budgets.

The tone in 2016 has shifted to: lower for longer. The industry has idled over 1,400 rigs in the US since the peak rig count in October of 2014, and it continues to decline. Of those 1,400 rigs that have been idled, approximately 900 are legacy SCR and mechanical rigs, and approximately 500 are AC drive rigs.

The industry is experiencing dramatic reductions in personnel and investments, and clearly a number of companies are struggling to survive. We are unable to predict the future, but perspective is necessary in both good and bad times. Recently, oil prices traded below $30 a barrel, and a few pundits see the possibility of $20 oil. We aren't predicting an immediate oil price improvement, but we do believe prices are below the level required to sustain a stable -- let alone growing -- supply over a long period of time.

In the meantime, the capabilities of the oilfield service providers are being reduced significantly. At some point, the question will be: who is in the best position for the eventual return of drilling demand? We believe that we will be well positioned, and that this is simply not a time for us to hunker down and wait for things to get better. While continuing to thoughtfully manage costs, we will prudently invest in opportunities that will enhance the key competitive advantages we have at the Company.

We let me talk briefly about a few of those opportunities. Our fleet profile is the competitive advantage, as the FlexRig design allows us to provide a family of solutions for our customers. For several years now, the industry has been trending toward longer laterals, multi-well pads, and generally more complex well designs, which require AC drive rigs with 1,500 horsepower specifications.

We have over 320 AC drive FlexRigs with 1,500 horsepower rating. And over 180 of those rigs are optimized for multi-well pad operations. And we continue to add 7,500 psi mud systems to a large portion of the fleet as well.

The advanced fleet of FlexRigs supported by our organizational capabilities enables the Company to remain laser-focused on delivering wells safely, quickly, and efficiently while continuing to innovate by providing technology solutions and enhancing our service offering. Our strategy has been successful; our market share in the US has increased from 15% in 2014 to 18% today and has doubled since 2008.

We will also continue to invest in the organizational capability that I just mentioned. This means enhancing our best-in-class reputation for service and the way we create value for our customers. While our organizational infrastructure has been built over the past 10 years, we continue to make investments to improve and to leverage the learnings we capture from the fleet on a daily basis.

This allows us to partner with more closely with the customer to provide greater efficiencies, reliability and safety. These improvements are all aimed at drilling the lowest-cost well for our customers and maximizing the number of wells customers can deliver in a budget year.

And, finally, maintaining a strong balance sheet and a disciplined approach to cost management remains a Company-wide priority. It is in times like these that the practice of maintaining a strong balance sheet becomes a key to future success. Along with this is having a balanced perspective on cost management so that we are making prudent reductions that won't end up costing us more than the initial savings somewhere down the line.

We're also rightsizing the organization along these same principles, with the end goal of enhancing our performance and developing opportunities for future growth. Before I turn the call back to Juan Pablo, clearly the first quarter of our 2016 fiscal year has been a very challenging start to the year. We are fortunate to have a very strong and liquid balance sheet, a firm backlog of term contracts, and the flexibility to significantly reduce spending levels during a soft market. Our approach to capital allocation will remain prudent and should allow us to effectively manage our business through this downturn and emerge from it with even greater competitive advantages.

And with that, I'll turn the call back over to Juan Pablo.

Thank you, John. The Company reported $16 million in net income for the first quarter of fiscal 2016. Given the deterioration of market conditions since late 2014, the average quarterly level of drilling activity for the Company has continued to decline -- down 53% from last year's first fiscal quarter and down 11% from last year's fourth fiscal quarter. Unfortunately, activity is expected to continue to significantly decline across our drilling segments during the second fiscal quarter.

Following are some comments on each of our drilling segments. Our US land drilling operations generated approximately $56 million in segment operating income during the first fiscal quarter. The number of quarterly revenue days declined by 11.5% as compared to the prior quarter, resulting in an average of approximately 130 rigs generating revenue days during the first fiscal quarter. On average, approximately 104 of these rigs were under term contracts, and approximately 26 rigs worked in the spot market.

Excluding the impact of early termination revenues, the average rig revenue per day slightly increased to $26,234 in the first fiscal quarter. And the average rig expense per day significantly decreased by $933 to $12,890, resulting in an average rig margin per day of $13,344 in the first fiscal quarter.

The decline in the average rig expense per day was primarily a result of continued efforts to reduce field overhead costs and direct operating costs on active rigs. H&P managers and employees across our organization deserve the credit for these very challenging and significant efforts. Unfortunately, as I'll also mention later, we expect the per-day impact of these ongoing efforts to be offset during the second fiscal quarter as our activity levels continue to decline.

During the quarter, the segment generated approximately $29 million in revenues corresponding to early termination of long-term contracts. Given existing notifications for early terminations, we expect to generate over $78 million during the second fiscal quarter, about $77 million during the second half of fiscal 2016, and over $40 million thereafter in early termination revenues.

Since the peak in late 2014, we have received early termination notifications for a total of 77 rigs under long-term contracts in this segment, up 17 rigs since our last conference call in mid-November. Total early termination revenues related to these 77 contracts are now estimated at approximately $429 million, about $88 million of which corresponds to cash flow previously expected to be generated through normal operations during fiscal 2015; $166 million during fiscal 2016; and $175 million after that.

As of today, our 347 available rigs in the US land segment include approximately 121 rigs generating revenue and 226 idle rigs. Included in the 121 rigs generating revenue are 93 rigs under term contracts, 87 of which are generating revenue days. In addition, 28 rigs are currently active in the spot market, for a total of 115 rigs generating revenue days in this segment. Some rigs that generate revenue days are on standby-type day rates. Rigs generating revenue and not generating revenue days include 6 newbuild rigs with deliveries that have been delayed in exchange for compensation from customers.

Looking ahead to the second quarter of fiscal 2016, we expect revenue days to decrease by close to 20% quarter to quarter. Excluding the impact of revenues corresponding to early terminated long-term contracts, we expect our average rig revenue per day to be roughly flat.

The average rig expense per day level is expected to increase to roughly $13,600. This expected increase is primarily attributable to the relatively large number of rigs becoming idle during the quarter and impacting total expenses, which are then allocated to a smaller number of expected revenue days.

Subject to additional early terminations, and excluding rigs for which we have received early termination notifications, the segment already has term contract commitments in place for an average of approximately 87 rigs during the second fiscal quarter; 79 rigs during the second half of fiscal 2016; 66 rigs during fiscal 2017; and 34 rigs during fiscal 2018. The average pricing for these rigs that are already under term contract is expected to slightly increase and remain strong during the next several quarters, as some rigs roll off and the remaining newbuilds are deployed.

The average pricing for H&P rigs in the spot market declined by approximately 5% from last year's fourth fiscal quarter to the first quarter of fiscal 2016 and may continue to decline during the second fiscal quarter. Average spot pricing today is over 30% lower as compared to spot pricing at the peak last November.

Let me now transition to our offshore operations. Segment operating income declined to approximately $8 million from $13 million during the prior quarter. Total revenue days remained flat, and the average rig margin per day declined from $13,296 to $7,920 per day during the first fiscal quarter. The decline was mostly attributable to expenses associated with one rig mobilizing from shore to a new platform, a second rig moving from an operating rate to a lower standby-type day rate, and some unexpected downtime during the first quarter.

As we look at the second quarter of fiscal 2016, we expect revenue days to decline by 5% to 10% and the average rig margin per day to slightly increase to approximately $8,250 during the quarter. The expected changes are primarily attributable to the full effect of the previously mentioned day rate changes during the first quarter and one rig expected to be demobilized and stacked onshore during the quarter.

Management contracts on platform rigs continue to contribute to our offshore segment operating income. Their contribution during the first fiscal quarter was approximately $6 million. Management contracts are expected to generate approximately $3 million during each of the remaining three quarters of fiscal 2016.

Moving on to our international land operations, the segment reported operating income of approximately $2 million during the first fiscal quarter, excluding a currency exchange loss of $8.5 million, which was primarily due to the devaluation of the Argentine peso during the quarter. As announced earlier today and starting this first fiscal quarter, the Company eliminated a legacy one-month lag period between its US fiscal year and its international operations' fiscal years. In the past, fiscal years for the international operations ended on August 31 instead of September 30 to facilitate reporting of consolidated results. As required, the Company applied the elimination of the one-month lag retrospectively to all periods presented in today's press release.

The average rig margin per day increased sequentially from $8,129 to $11,811 per day, excluding the impact of charges related to the allowance for doubtful accounts during the fourth fiscal quarter. The increase was primarily a result of better-than-expected contribution from multiple rigs in different countries, including rigs that were working on relatively short-term contracts. Revenue days sequentially decreased to an average of 15.3 active rigs during the first fiscal quarter.

As of today, our international land segment has 14 active rigs, including 10 in Argentina, two in the UAE, one in Colombia, and one in Bahrain. All 14 active rigs are under long-term contracts. 24 rigs are idle, including nine in Argentina, seven in Colombia, six in Ecuador, and two in Bahrain.

We expect international land quarterly revenue days to be down 5% to 10% during the second quarter of fiscal 2016. The average rig margin per day is expected to decline to close to $7,500 per day, and no early termination revenues are expected during the second fiscal quarter in the segment. The expected decline in average rig margin is primarily attributable to the reduction in activity and to day rates for some of our contracted rigs moving from operating rates to standby-type day rates.

Let me now comment on the corporate-level details. Our strong liquidity position, along with our firm backlog of long-term contracts and reduced CapEx requirements, is expected to allow us to sustain our regular dividend dollar-per-share levels, and our intent is to continue with our plan. Capital expenditures for fiscal 2016 are still expected to be in the range of $300 million to $400 million.

Our FlexRig construction cadence plan remains generally the same, with only a few contracted FlexRigs to be completed between now and the end of March of 2016. Including these remaining long-term contracts and combining all three of our drilling segments, we have an average of approximately 104 rigs under term contracts expected to be active in fiscal 2016; 81 in fiscal 2017; and 47 in fiscal 2018.

Given market conditions during the last several months and the early termination of additional long-term contracts, our backlog decreased from approximately $3.1 billion as of September 30, 2015, to approximately $2.7 billion as of December 31, 2015. As mentioned in the past, we expect our total annual depreciation expense for fiscal 2016 to be approximately $580 million and our general and administrative expenses to be approximately $135 million.

The effective income tax rate for the first quarter of fiscal 2016 was higher than expected, primarily as a result of adjustments related to the recent tax law change extending bonus depreciation allowances that expired at the end of 2014. We expect that effective tax rate for each of the remaining three quarters of fiscal 2016 to be in the range of 32% to 35%.

With that, let me turn the call back to John.

Thanks, Juan Pablo. And before opening the call to Q&A, I want to reiterate the challenging oil and gas market today that may be on par with the oil market in the 1980s -- but there are key differences; and one big difference is the age, size, and capability of today's rig fleet.

The AC drive rig replacement cycle of the legacy fleet is ongoing. At the peak of activity in 2014, approximately 41% of the fleet was AC drive; and today, over 63% of the active fleet is AC drive technology. The remaining fleet is legacy SCR and mechanical rigs. And the question remains: what will be the marketable legacy fleet at the end of the downturn?

We believe it will be a very small portion of the marketable fleet. And those rigs will have a very difficult time competing in the world of complex, unconventional, horizontal wells.

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

(Operator Instructions) Byron Pope, Tudor, Pickering, Holt.

John or Juan Pablo, I was struck by the cost side of the equation for your US land operations. And realize there are a lot of moving pieces, with more rigs being laid down in the March quarter, but it almost sounds as though you've gotten that average rig expense per day for a typical FlexRig down to a maybe lower sustainable level.

So, again, I hear the March quarter guidance on the cost front, but is it fair to think that you've gotten that normalized cost down -- if you were to back out any costs associated with the rigs that will be laid down in the March quarter? I'm just trying to think about how that flows as we get deeper into this fiscal year and beyond.

Thank you, Byron. This is Juan Pablo. I think that is fair. However, we -- you know, going forward, it all depends on the number of idle rigs and active rigs, and the corresponding proportion, of course.

In terms of how many idle rigs we will have, that will be subject to some small level of fixed expenses that will impact the total expenses that will then be allocated only among the very small or relatively small number of revenue days. As that denominator gets smaller, it just has an impact on the total average. And that's what we see happening the following quarter.

But I think your point is a good one -- that in general, we have made great strides as an organization to continue to reduce the average expense per active rig. It's just that the inactive ones are creating some volatility.

Byron, this is John. Juan Pablo said in his comments, but the guys in the field have worked really, really hard to get those costs down, and they have. They've done a great job. But like Juan Pablo said, there's -- the denominator is the smaller number of days to spread those costs over.

And I think -- but there's also things that we're working on related to just costs on the supply chain side. There's a lot of things that we're excited about working on. But, again, obviously we've got a large number of rigs that are idle today.

That's helpful. Thanks, guys. Appreciate it.

John Daniel, Simmons & Company.

John, there's lots of -- at this point in the cycle, we get all sorts of various field anecdotes, and we try to figure out what's true and what's not true. But people call in and say, hey, Tier 1 rig rates are now $16,000 a day and below.

As we think about your spot rig portfolio's day rate assumption as we enter the third fiscal quarter, would we be wildly off if we were to use that type of day rate assumption?

Are you saying -- John, I want to make certain I understood the question correctly. You're saying that in the third quarter of 2016?

Second calendar quarter, right. Third fiscal quarter for you guys.

Right.

Because I know you've given guidance for the current quarter, and so I'm just trying to -- I also understand you guys have the revenue per day that's not day rate related, too. So, I mean, it's --

Right.

-- not a true apples-to-apples. So I'm just trying to separate sort of what we hear from the field versus what we should be expecting. That's all.

Right, no, and I hear you; there is a lot of just anecdotal comments out there. I think from our perspective, we've kind of summarized it as mid-to-high teens. And there's various different things that move that rate up and down as it relates to rig capability -- you know, whether it has a third mud pump, or 7,500 psi, or whether it has a pad application.

There's a lot of things that drive that. But I don't think what you're saying is unreasonable in a $16,000, $17,000, $18,000 a day range -- again, depending on the rig and where it's working.

Fair enough. And Juan Pablo, I know that you guys hate giving guidance during the current quarter, but could you just if possible provide some directional color surrounding cash margin expectations for offshore and international, just as we proceed through the year? It's been fluctuating a bit recently.

Yes, that's a tough one. We don't provide guidance beyond a quarter. I think the expectations of those margins remaining where they are for the time being or for the foreseeable future is probably a fair starting point.

Okay, thanks, guys.

Dave Wilson, Howard Weil.

John, in the past you have mentioned a possible structural change in the industry, especially in relation to preserving the dividend at current levels. And given where we are in terms of the overall rig count being less than the number of AC rigs out there in the market, would you view this as a structural change? Or the present oversupply of AC rigs is just kind of a temporary phenomenon, in your opinion?

Well, I don't consider this as a structural change. I see it as a -- really, a classic cyclical market at this stage. I mean, we have -- if you look back in history, you can see wild, pretty wild, swings in down cycles in terms of the number of rigs that are going down.

You're right; there are over 900 AC rigs available today. Not all AC rigs are created equal. You know, there's -- I think when you begin to see oil prices improve in the future -- I don't know when that is; nobody knows -- but there's going to be a high demand for those assets in the future.

You know, I think the real challenge as it relates to the rig fleet -- and that's the legacy fleet, which we've addressed over a pretty long period time -- it's just going to be harder and harder for those rigs to be competitive. So that's a long answer to your question. But no, we don't see this as a structural change at this point.

Okay, thanks for that. And just as a follow-on to that: there's been a lot of talk, or I guess I should say some talk, of some significant attrition in the pressure pumping market in terms of equipment. But we really don't hear that on the land rig side in terms of true attrition from mechanical or SCR rigs. Could you share your thoughts on that as well?

I think there's been a fair number of -- and I don't have any recent information on this -- but there's been a fair number of old rigs that have been written off consistently over the last several years. And I can't speak to any recently. Juan Pablo, I don't know if you know of any. But other than that, I don't really have any to add.

I couldn't add to that, other than I certainly agree that many of our peers have decommissioned and written off a significant number of those legacy rigs, of course. We had some of that over the last few years ourselves, but it was a much smaller proportion of our fleet, of course.

Right.

Okay. Thanks for that, guys. I'll turn the call back over.

Sean Meakim, JPMorgan.

So I wanted just to talk a little bit more about the day rates in US onshore. I'm assuming the guidance reflects some mix shift benefit, as more of the spot rigs are the ones idling, obviously, rather than contracted rigs. With the rig count taking another leg down, are you seeing -- you know, is the mentality shifting amongst your peers at all in terms of -- towards the utilization at any price type of mentality? Or do you believe that the markets-level discipline is holding firm?

Sean, this is John. The reality is there isn't -- and it's been this way, really, since the downturn got into full swing -- there isn't much of a spot market to speak of. And so there's not -- it's not like there's a lot of competition out there for jobs, what few jobs there are out there. The customer knows that they want; they know what the market rate is. There is not -- at least from our perspective, there's not a huge push on those rates at very, very low levels.

I mean, obviously, there's competitors out there pricing to a certain extent irrationally. It may be irrational from our perspective, but from their perspective it may be what they need to do. But there's just not a lot of work out there being bid on. So I wouldn't at this stage say that anybody's strategy on pricing is going to deliver any improvement in market share at this stage of the game.

No, I think that's very fair. So I guess if you think about -- we've heard from a handful of E&Ps with updated budgets in the last couple of days. It's a small sample set, admittedly, but the indications are for substantial capital efficiencies again after what we saw in 2015. Just curious how you see drilling efficiencies unfolding for the industry as a whole in 2016 as we continue to shrink down the level of activity?

You know, if you look back, at least that our performance going back to 2011, we've had double-digit performance improvement in terms of footage per day every year since 2011, with the exception of 2013 to 2014, where 2014 really spiked up. It was high single digits. This year we've got, again, high double-digits improvements. But obviously there's a point of diminishing returns on what's capable of happening out there.

And so I think there will continue to be some performance improvement year-over-year. I would imagine a large portion of that performance improvement is going to be related to Permian, because the other basins have been drilling horizontal wells for a much longer period of time. And I would suspect that Permian is going to drive the overall industry in terms of whatever that performance improvement will be year-over-year, if that makes sense. But I don't really have a feel for -- I mean, my sense is that it's not going to continue to be at high double-digit-type performance year over year.

That makes a lot of sense. And then just the last -- to take it to the other side, in an eventual recovery, would you expect the industry to give back then some of those efficiencies for a period of time?

Well, if it's an H&P rig, I would say no. (laughter) I can't really speak to anybody else.

No, I think early on I wouldn't expect that. But at least -- again, I'm thinking about it from our own fleet. It's hard for me to speak for anyone else's. Clearly, with the amount of reductions -- and we talked about this in our comments -- not only is there a much lower level of budgets, but we've had a lot of, of course, a lot of folks leave the industry. We've had a lot of reductions in that respect. And that ultimately ends up being a bottleneck in a lot of cases, when you begin to take the industry the other direction. So I think that could be a challenge for the industry in general.

Makes a lot of sense. Thanks a lot, John.

Okay, Sean, thanks.

Jeff Spittel, Clarksons Platou.

Maybe to follow up on Sean's question along the lines of productivity, whether it's from a per-rig or per-well standpoint: is it fair to say, in your estimation, that maybe some of those statistics, as resilient as production has been, have been distorted a little bit by high grading of acreage, and crews, and rigs? And if so, I guess, is there a similar trend that you envision in terms of diminishing returns from a productivity standpoint?

Yes, I don't think there's any doubt that the wells that are being drilled are the best wells. I mean, it would just make sense that that's going on. And, of course, we have -- you would think everyone would have their best people, both on the operator side, on the service side, on the contractor side. I mean, it's the best of the best.

So I think all of that makes sense. And if you were to take the industry and increase the rig count by a couple hundred rigs, you'd be hard-pressed to have those same efficiency levels across the industry, I would suspect.

Sure, that makes sense. And maybe thinking at least theoretically when things do begin to recover, and customers start engaging you in a conversation about reactivations, it seems to be sort of a popular notion with some investors that it's going to be very difficult to get any sort of incremental pricing traction to reactivate a rig.

I'd love to hear your take on that. Obviously, it doesn't sound like there's much incremental investment necessary to bring a rig out of the yard these days. But how would you envision those conversations unfolding?

Well, historically what you said is right. And I think that probably holds true going forward. I think initially you're not going to see a pricing improvement. You're right; at least in our fleet, there shouldn't be a high level of investment in order to reactivate a rig. I think we've done a very good job in terms of idling our assets and preserving them. So there's a set of rigs that are ready to go back to work when that time would happen.

And so I think that's true. I do think there is a point in time where you begin to gain a little bit of traction. Because I think the rigs that are going to be desired in the industry are going to be, obviously, the best rigs; and they're going to have higher horsepower. They're going to have greater need related to, again, a third mud pump, 7,500 psi pad applications.

There's going to be more investment, and that investment drives a greater level of performance. So I think there is an opportunity to get pricing up, but it won't be at the very beginning of the cycle. I think we'll have to put some rigs back to work and improve the utilization levels of the AC fleet before you could see pricing improvements, I would suspect.

All right, that makes sense. Thanks, guys. I'll turn it back.

All right, Jeff, thank you.

Brad Handler, Jefferies.

Maybe I'll start with a clarification from Byron's question initially. He was asking you sort of about normalized costs. And it sounds like you said yes, but it was all contingent on the denominator.

So maybe just so I understand what you're suggesting, if we think about the third fiscal quarter, and if the rig count were to stay flat, is that operating cost per day of $13,600 for US onshore -- is that the right -- is that a reasonable expectation in light of the fact that the denominator is what it is?

Brad, this is Juan Pablo. Let me give you some additional color in terms of what I was referring to. If you -- and any time there is a significant transition, in terms of whether it's an increase in the rig count or a decrease, there's a lot of activities that take place related to those rigs that are stacking. We need to transport them; we need to make sure that we rig them up in the right way and prepare them to go back to work, et cetera.

On the other hand, you might recall in years past, when we have had a transition from one region to another region, whether it's related to preference of price for oil as compared to gas, and we have a lot of transition -- that adds up to our costs and has typically an unfavorable impact on our average rig expense per day for the quarter. That's what we see happening in the second fiscal quarter.

Given your assumption going into the third quarter, everything else being equal, I think that there is a potential for that average to come down. But there's always other considerations to keep in mind, and we'll just have to follow that and report on that during the corresponding conference call.

Okay, understood. That makes sense and consistent with the answer around a normalized cost being somewhat lower. So that's great. Okay, understood, thanks.

Unrelated follow-up: so, John, in your comments -- I was trying to tie your comments around what you were doing with rigs through the course of this year with some of what you wrote in the narrative on the front of the press release around upgrades, continuously upgrading our best-in-class rigs. Should we think about as being related to either adding a third mud pump or upgrading it to 7,500 psi? Is that the most important sort of change to your rigs as you think about fiscal 2016?

That is a portion. There's additional horsepower requirements at times. It's a third pump; it's 7,500. There's other upgrades, really, at this stage we haven't talked a whole lot about and don't intend to today.

But the majority, on the cost side, I would say yes; that's the portion that you would see a larger CapEx exposure. There's other things that we are working on that aren't as high on the CapEx side but deliver some value. I mean, our -- you know, as you have followed us for a long time, our goal is to continuously upgrade and improve the Company; not just the rigs, but the structures, and processes, and systems, and tools that we have. We pride ourselves in doing that, and that's what we're doing. That obviously has a price tag to it as well.

Sure, understood. No, I was just hoping for some more color, which I think you've given. So that's helpful. That's fine; I'll turn it back. Thank you.

Robert MacKenzie, IBERIA Capital.

A question for you on the cost side again, specifically in the US. How much of your reduction in operating costs so far, if any, has been related to permanent reductions in compensation for employees that remain employed? And how do you think about that concept of cutting salaries or wages going forward for people that remain employed?

The last part -- I'm not certain I got all the first part of the question. I'll turn that over to Juan Pablo.

The second part of the question is we haven't reduced wages. We hadn't increased wages since December of 2011. And you know, wages -- I think you probably know this, but just to restate -- wages are typically a direct cost pass-through to our customer. So there's really not a savings there for us. So at this stage we don't have any indications that were going to reduce our wages for our folks in the field. Do you have anything to add?

Yes, John. And that's consistent with what I think Rob was asking related to the reductions that we've seen so far. None related to wages, as John mentioned.

Certainly we have to deal with overages at times, and so -- managing the logistics around the personnel. That's a huge challenge. And we've done as an organization a great job so far in that regard throughout the downturn.

So that has an impact on total expenses. But the reduction in expense per day has been a result, as we mentioned, of several factors within the maintenance; the efficiency with which we've been managing the crews; other related costs, et cetera. I can't give you specific examples, but it's been overall a great effort.

No, it is, clearly -- you know, particularly with expense per day for active rigs this quarter being below what you posted in 2012, 2013, and 2014. I guess another way to ask a similar question would be: structurally, when we end the transition process, when we and dropping of the rigs in the market; find -- if you will, find a new bottom or find a steady-state level, where do you think that rig expense per day operating number is, given all of the moves you've made once the volatility ends?

Well, that's a great question. I don't have a number for you, Robert, but I can say that we are continuing to look at all the options available and understanding our costs as best as we can. And from an organizational perspective, the structure of the organization, how we can become leaner and more efficient as a company -- all of those things are on the table and we are looking at.

I think the other thing to keep in mind all during this time is: the rigs have continued to work harder and harder. So the wells we're drilling today are nothing like the wells we drilled two years ago. So when you look at our cost trends over time -- Juan Pablo said it. Our folks have done a great job.

But when you consider the amount of footage that we drill in a year-to-date compared to what we did three years ago, these rigs are working so much harder. The rig move times are much less frequent. You're spending less time moving, and you're spending more time drilling. So you're using expendables, as an example, much more frequently. So the fact that we've been able to get our costs down over time is pretty amazing.

So that's part of the challenges that we have is the variables are not held constant. They are continuing to change on us in an upward fashion, so we're having to work against that at the same time.

Great. Good answer. Thank you. Well, I'll turn it back.

Michael LaMotte, Guggenheim.

A lot of the questions been answered, but a question for you, Juan Pablo, around receivables and collections. Working capital was obviously very strong in the quarter, and you clearly are doing a good job on receivables. So I'm just wondering if you could share with us a little bit your strategy around that, and how you stay close to that in keeping the DSO number so low?

Thank you, Michael. Yes, we certainly pay a lot of attention to that. And in times like this, one of the variables that impacts the numbers on the balance sheet and our working capital, et cetera, relates to revenues corresponding to early terminations. So we may be invoicing some work or early termination fees that are deferred. And so that lands in the liability side of the balance sheet and impacts either cash or receivables, et cetera.

So we have those types of moving variables. But overall we are very pleased with how the working capital is progressing in general. No issues to comment on around receivables; no issues to comment on about any of the other variables. It's great to have the very high level of liquidity that we have today. Obviously, that is partly a result of the early termination fees that we've mentioned. It is helped by the allowance for bonus appreciations that we mentioned as well. We're very pleased to be where we are from a balance sheet standpoint.

Okay. So just so I'm clear, the number -- which continues to -- you know, I'm guessing is still below 80 days for the first quarter. Low, I guess, 73 for the previous quarter. That's not being brought down artificially by the early terminations, is it? That's still kind of a true representation of what you're doing on a true operating basis?

As a matter of fact, we're doing better than that. And that number in general, the days that you mentioned, are skewed upward in both cases and throughout the last few quarters as a result of early terminations. So again, we are pleased with where we are in that regard.

Yes, very good. Thank you for that clarification.

John, a question for you on overseas strategy. I know this is something that remains on the watch board, so to speak. But with so many idled assets now in the US, I'm wondering if there's an opportunity to make a bold move overseas, and if that's something that you're seeing or would consider at this point?

Well, Michael, we would sure consider it. Obviously, the international markets are in a bit of disarray as well, but I think we've shown in the past -- the ten rigs that we sent to Argentina, that was a result of having FlexRigs available. So it's definitely something we have interest in.

I mean, you've followed us for a long time. You know the challenges associated with growing in a significant way internationally. But obviously we are open to having those discussions and making that happen.

So there's nothing in this downturn that makes you think that you want to be 100% US longer-term? You think having some global balance is appropriate?

Yes, we've continued to believe that international has some real upside for us. You've probably heard us say for a long time now that when unconventional resource plays become more popular and become more economic, if you will, internationally -- that, gosh, we ought to be in a position to take advantage of that opportunity. Obviously, the work in Argentina is really the first kind of large-scale unconventional resource play opportunity. And we have more market share there than anybody else.

So I think it presents some great opportunities in the future. We've worked internationally for over 50 years. We have a lot of experience. And, of course, we have a lot more we can learn. We know we can do better. So it is a desire of the Company to continue to try to grow our footprint internationally. And obviously we have the assets and the personnel to make that happen.

To do it. Okay, great, thanks, guys. I'll turn it back.

Tom Curran, FBR Capital Markets.

John or Juan Pablo, I'm sorry if I missed this, but could you give us an update on the percentage of the idle count that is equipped with a moving system -- you know, with a skidding system? And then by the time we reach the end of this downturn, what would be your target percentage for that idle fleet?

Hang on just a second, Tom; we're taking a look.

So, let's see -- of the number of idle rigs that we have, and I'm taking a look at AC drive FlexRigs.

Just in the US, Juan Pablo.

So in the US, it's close to 224 total AC drive FlexRigs idle. Of those, 104 have a pad capability. Does that address your question?

And then I guess you're the latter part of your question is: where would we think that we would be in the future? And there's a lot of moving variables around that. As John mentioned, we continue to add pad systems to existing FlexRigs that do not have those.

And so the total number will continue to shift. The proportion will continue to grow. But not every well that is being drilled out there, as you know, of course, is on a pad or a multiple-well pad. There's still demand for single-well pad drilling. And so we'll continue to monitor that. But for the moment, we do have a significant number of rigs that are capable to address the market. Does that address your question, Tom?

It does, yes. And thank you for that, Juan Pablo. What would you estimate or what have your guys estimated industrywide is the current total AC drive, pad-capable idle rig count in the US?

Let me make a couple of comments. We'll take a look at that. Total number of idle AC drive rigs in the US, we believe, is over 500. Not sure how many of those are being actively marketed, as some of those have not worked for years now. But there is a proportion of that, of course, that are pad-capable. I'm not sure that we can pinpoint the number of rigs that do have pad capabilities that are idle in the entire market. I'm sorry. I don't have that number.

I don't think that's something that's been well advertised. I'm not certain the rig resources that we have, public rig resources have it broken out like that.

Yes, none of the ones I've consulted thus far have been able to nail it down.

What I might add is that we do believe that there's roughly a total -- not idle, but a total -- of 500 to 600 marketable AC drive rigs with pad capability, pad drilling capability.

That's helpful. And even with the unknown idle rigs, given how quickly and cost-effectively -- how low the capital cost would be to upgrade most of those to pad capability, I'm not sure it's a distinction that even matters all that much. But I thought it was worth exploring.

Last one for me: John, since you were Chief Operating Officer, we've talked about how over time -- you know, this is a high-level, longer-term question -- over time, you expected the main advantage technologically for H&P to shift from the rig spec gap relative to your other Tier 1 drilling competitors and move towards this unrivaled in-house database you have of more than 1,200 rig years of FlexRig experience, and combining that with the advances being made in rig computerization to sort of standardize best-case performance, basin by basin, maybe even field by field. Could you just give us an update on where you think you're at with that next phase of technological differentiation?

Tom, that's a great question. There's a lot of things that we do with the data that helps us run our business better as far as maintenance and rig equipment, and that equipment running at high levels and performing well.

The challenge -- and we utilize that data to help the rig drill more quickly for our customers. But when you begin to -- you know, when you're working for a lot of different customers, and there's a lot of different needs and desires on how that data gets used and gets managed. So I see it as -- we still see it as an opportunity. I don't have perfect clarity into how that looks going forward, but you know, the other thing that we've said is because our fleet is all AC drive, and because our fleet is a uniform fleet, and we have the ability to share that information -- whatever that breakthrough may end up looking like in the future, I think we're in a better position than others in order to take advantage of that, whatever that may be. There's definitely some challenges associated with it right now if you look at it across the board because of all the different folks that you're working for. Does that make sense?

It does. But it sounds like it would be fair to say that the vision itself is still intact, and it's one you're continuing to work at in terms of realization?

Yes. I think that there's still that capability. And again, I like the fact that we have this uniform fleet and this ability to take advantage of that across our entire fleet.

Agreed. I think it will -- it's a clear advantage that we'll prove over time. Okay, guys, thanks. I'll turn it back.

Okay, Tom, thank you. And Keith, we may have time for one more question, please.

Chase Mulvehill, SunTrust.

Thanks for squeezing me in. I guess the first question I have is: so what is the variable cash cost per day for running an H&P rig right now?

We don't have an exact number for you, Chase. That's a very fair question, because it goes to the heart of some of the moving considerations or variables related to our total average expense per day. Some of those expenses relate to rigs that are not active. So if you were talking only about active rigs, then the number would be lower.

Then if you also subtract other revenue that may relate to that rig, whether it's related to H&P trucking, or whether it's related to other services -- whether it's rentals, et cetera, then that number continues to go down. And it also depends on the region that you are in. And the cost structure between regions, of course, as you know, is significantly different. So I think a fair assumption is that the cash cost directly associated with the rig and without any other ancillary revenues is significantly lower than our average rig expense per day.

But then, of course, you also have maintenance CapEx considerations that you are probably including conceptually in that cash cost question. And that depends on the rig that you're looking at. If it's a new rig, your maintenance CapEx will be much lower, as you can imagine, as compared to an older rig, et cetera.

So too many moving variables to give you an answer. But I think it's a fair question, and it's an important consideration in terms of pricing and competitive advantages going forward. We think we are very well positioned in that regard, given the uniformity of our fleet, the way that we maintain our rigs, and several other considerations.

Okay. So if I were to throw a number out there, would $10,000 a day, before we started adding maintenance CapEx -- or maintenance expense, sorry -- to that number, would that be a ballpark-ish number?

Probably between that number and the total expense per day that we report on without maintenance CapEx. Then if you add maintenance CapEx, then the number goes on top of that. But again, it probably might be a little misleading to use a round number like that. It's suggests that that applies across the board. So I'm hesitant in giving you a firm answer on that.

All right, understood. And then upgrade CapEx through the downturn -- how should we think about that? 2016 is going to be a rough year. But if we get a recovery in 2017, and then it continues into 2018, what kind of upgrade CapEx should we expect for H&P?

Well, our maintenance CapEx, of course, you know is much lower with a reduced level of activity. You're referring to not only maintenance, I think; you're referring to what -- you know, if you continue to add certain types of capabilities to rigs that don't have it, like pad systems, or 7,500 psi systems, et cetera, how much would that take on an annual basis going forward? And the answer is, unfortunately, also inconclusive. It depends.

We would have to take a look at what the market demand is, and what the shape of the recovery is, et cetera. I'm not sure if I can add much more clarity than that. It's a fair question, Chase, but very difficult to point to a number at this point.

Okay. I just get the question all the time, between what's your maintenance CapEx in a recovery scenario, and what kind of upgrade CapEx should I add in there? So I thought I'd try to get some color there.

And the last one, and then I'll turn it over. Thoughts on building on spec during an upturn? 2017/2018, if the rig count is up 30% a year; your rig count gets 200 or above -- and do you consider building on spec if the recovery is intense enough?

Chase, this is John. Gosh, I wish we had that problem to worry about. Doesn't that sound like a great situation?

Yes. (laughter)

That's a tough one to call right now, when you consider the number of rigs that we have idle -- not only us, but the overall industry. Obviously, we've seen it before. We've seen this market turn very quickly, and it could get there.

We've obviously built new rigs on spec before. You know what our preference has been. We'd be foolish to say, hey, we're going to completely rule it out. There's a lot of different considerations you have to take into account. But at this stage I think anything would be on the table if there's a market there for that type of opportunity.

Nobody can respond more quickly than H&P. Nobody has the ability to build a quality AC rig at the cost that we are able to do it. So it's a great opportunity for us. Again, I look forward to having that opportunity.

Well, our fingers are crossed.

That's right.

All right, John, Juan Pablo, appreciate it. Thank you all.

Thank you, Chase, thank you.

And Keith, we will have a couple of additional comments to make. Just let me hand it over to John, please.

I just want to thank all of you again for joining us this morning. I'm just going to make a couple of more just brief comments before we sign off. You have heard Juan Pablo and I describe that this remains a very challenging environment, but we do believe the Company is very well positioned.

Our long-term contracts continue to protect our investments, and overall our customer base remains resilient. The balance sheet is in great shape, our customer base remains strong, and our competitive advantages have positioned us to manage through this cycle and to capture opportunities when they emerge. We continue to work very hard to improve the capabilities of the Company. We have a lot of very important initiatives ongoing.

I want to thank all our employees and our management teams for stepping up to the challenges that we are faced, embracing this change in a positive way, and responding in an admirable fashion. So again, we appreciate all of you for joining us this morning. And we thank you for your continued support.

Ladies and gentlemen, this does conclude today's program. We thank you for your participation. You may now disconnect. Have a great day.