Helmerich & Payne, Inc.
Q2 2016 Earnings Call Transcript

Published: 2 May 2016

[Operator:]

Good day, everyone, and welcome to today's Second 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. Please note, this call may be recorded. I will be standing by if you should need any assistance. It is now my pleasure to turn the conference over to Mr. Juan Pablo Tardio, Vice President and CFO. Please go ahead, sir.

[Juan Pablo Tardio:]

Thank you, Tanisha. And welcome, everyone, to Helmerich & Payne's conference call and webcast corresponding to the second 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 (00

[John W. Lindsay:]

Thank you, Juan Pablo, and good morning, everyone. And thank you for joining us on the call this morning. Last week, a former oilman and well-known investor dubbed the American oil industry as dead in the water after multiple quarters of capital starvation and deteriorating rig counts. While we don't agree with the characterization of the industry being dead, that shoe may fit non-Tier 1 legacy, SCR and mechanical rigs in the U.S. We have long believed Tier 1 AC drive rigs, which constitute nearly 100% of H&P's fleet and 64% of the working industry fleet today, are the relevant rig assets for drilling horizontal wells in the U.S. land segment. After hearing many of the comments from this earnings season about the importance of Tier 1 rigs for drilling the most efficient horizontal wells, this appears to be the consensus view today. Since 2002, our strategy has been designing, building and operating Tier 1 rigs. Over the past five years, the industry has gone through an energy renaissance, and well complexity has dramatically increased right along with efficiency. H&P has led the way with innovative solutions that have set H&P apart from its peers, particularly in how we have leveraged AC drive technology. First, by taking ownership by internalizing expertise in the areas of equipment performance, capital repairs and where practical, vertical integration. Second, providing support services. Our electrical and mechanical staff enable us to leverage knowledge and life cycle learnings of equipment, and our performance groups are proactively engaged in helping our customers to lower total well cost. Finally, we are committed to a process I will call continuous evolution where in-house technical resources collaborate with their operational counterparts to enhance existing technology by adding new capability and functionality, as well as leveraging data more effectively to the benefit of both our customer and the company. As in the past, we will continue to invest through the cycles. We have had great success in partnering with customers and moving ideas quickly into operational deployment. We are developing solutions that will add incremental capacity and/or capability to address market requirements, and we can do this in a scalable and cost effective way by leveraging our uniform base of existing FlexRig designs to provide value for customers. We've also taken leadership positions in other areas. Our many firsts include integrated casing running services, scripting of wells for enhanced reliability and efficiency, enhanced software control capability, integrated stick-slip mitigation, and many other technology solutions that today are standard offerings. The industry has also formed a consensus view that 1,500 horse power AC drive Tier 1 rigs provide the best drilling performance for drilling the most challenging horizontal wells. H&P's fleet has over 30% of the estimated 700 rigs in the U.S. market today that fit that description. We believe H&P's rigs are strategically placed and ready to mobilize quickly. Let me use the Permian Basin as the example of strategically placed and ready to mobilize quickly. The Permian, by all accounts, is the premier basin in the U.S., and some would argue in the top three of oil basins in the world. No drilling contractor has a stronger Tier 1 footprint there than H&P. Today, we have a total of 39 FlexRigs on contract in the Permian, more than our top three peers combined. Additionally, we have over 60 idle FlexRigs available with 1,500 horsepower AC drive capability that are ready to work. Let me also make the point for ready to mobilize quickly. We've made prudent investments and taken great care to idle and maintain the FlexRigs properly. Field-tested processes are used to clean and preserve the equipment. In addition, the rigs have been assembled and maintained as needed so we are ready for the most efficient and cost-effective deployment when the market improves. For good or bad, H&P's Permian facility has become one of the photographic symbols of this downturn. And as many can see, our FlexRigs are standing tall and ready to go to work. We often get questions regarding how quickly we can respond to demand with our idle fleet of FlexRigs. We feel very confident we are positioned better to respond than others as a result of the investments made in the fleet as described. Whatever the demand might be going forward, we believe we can grow our market share in an improving market as a result of the mentioned characteristics, strategic placement and the ready state of our rig fleet. In addition to rigs being ready, an obvious need and a key advantage in ramping up activity is the availability of quality people. We have done everything in our power to keep our best people. Clearly in a downturn of this magnitude, it is impossible to keep everyone. Like all companies in the energy sector, we've had to make significant cuts in spending and personnel. It has been very difficult to say good-bye to so many, but we are thankful for having such great people today and look forward to the opportunity of bringing back to work many of those former employees once the cycle turns. Before turning the call back to Juan Pablo, I want to recognize that in the face of adversity, I've been very pleased with our folks' response in dealing with the downturn. Our focus has remained on doing the right things and retaining the right people to enhance our competitive advantages going forward. Juan Pablo?

[Juan Pablo Tardio:]

Thank you, John. The company reported $21 million in net income for the second quarter of fiscal 2016. Compensation from customers corresponding to early termination of long-term contracts, once again allowed us to report quarterly profit. Nevertheless, market conditions continued to deteriorate and drilling activity for the company continued to decline. Following are some comments on each of our drilling segments. Our U.S. land drilling operations generated approximately $63 million in segment operating income during the second fiscal quarter. The number of revenue days declined by approximately 20% as compared to the prior quarter, resulting in an average of close to 106 rigs generating revenue days during the second fiscal quarter. On average, approximately 84 of these rigs were under term contracts, and approximately 22 rigs worked in the spot market. In addition to rigs that are no longer contracted and became idle during the quarter, several more rigs became idle that remain under long-term contracts and that are generating revenue days at standby-type day rates, protecting the expected daily cash margin during the term duration of the contracts. This increasing number of rigs with standby-type day rates represented approximately 17% of the rigs that were generating revenue days in the segment at the end of the second fiscal quarter. Excluding the impact of early termination revenues, the average rig revenue per day declined by approximately 1% to $25,931 in the second fiscal quarter, and the average rig expense per day increased by approximately 10% to $14,139, resulting in an average rig margin per day of $11,792 in the second fiscal quarter. The increase in the average rig expense per day was primarily attributable to the large number of rigs that became idle during the quarter, generating expenses related to personnel management and rig stacking, which were then allocated across a smaller number of revenue days for the quarter. It was not a surprise to see our quarter-to-quarter daily expenses increase as we had guided toward $13,600 per day for the quarter. But the increase was higher than expected as we experienced some unfavorable volatility during the quarter related to different type of expenses that we expect will return to more normal levels during the following quarter. The segment generated approximately $80 million in revenues corresponding to early termination of long-term contracts during the second fiscal quarter. Given existing notifications for early terminations, we expect to generate over $80 million during the third fiscal quarter, about $20 million during the fourth fiscal quarter, and over $40 million thereafter in early termination revenues. Nevertheless, about 60% of the mentioned early termination revenues that we expect to be recognized after the second fiscal quarter of 2016 are attributable to compensation that, as of March 31, had already been invoiced and collected and that is included in the current liability section of our March 31, 2016 balance sheet as deferred revenue. We cannot fully recognize the early termination revenue on a rig until all contractual customer options to 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 87 rigs under long-term contracts in the segment, up 10 rigs since our last conference call in late January. Total early termination revenues related to these 87 contracts are now estimated at approximately $460 million, about $88 million of which corresponds to cash flow originally expected to be generated through normal operations during fiscal 2015, $183 million during fiscal 2016 and $189 million after that. As of today, our 347 available rigs in the U.S. land segment include approximately 84 rigs generating revenue and 263 idle rigs. Included in the 84 rigs generating revenue are 77 rigs under term contracts, 72 of which are generating revenue days. In addition, seven rigs are currently active in the spot market, for a total of 79 rigs generating revenue days in the segment. Nevertheless, approximately 18% of these 79 rigs are now idle and on standby-type day rates, protecting daily cash margins under long-term contracts. Separately, the five rigs generating revenue and not generating revenue days include newbuild rigs with deliveries that have been delayed in exchange for compensation from customers. Looking ahead to the third quarter of fiscal 2016, we expect a decline in the range of 25% to 28% in the number of total revenue days quarter-to-quarter. Excluding the impact of revenues corresponding to early terminated long-term contracts, we expect our average rig revenue per day to decline to approximately $25,000, partly as a result of the relatively high proportion of rigs generating revenue days under standby-type day rates. The average rig expense per day is expected to decrease to roughly $13,800. This expected decrease is primarily attributable to a greater proportion of rigs on standby-type day rates, which is partly offset by expenses related to the growing proportion of total idle rigs. Our third fiscal quarter average rig expense per day estimate also includes the impact of a relatively high level of expenses related to a significant ongoing reduction of field personnel positions and employee early retirements. Absent any additional early terminations and excluding the mentioned rigs for which we have received early termination notifications, the segment currently has term contract commitments in place for an average of approximately 71 rigs during the third fiscal quarter, 69 rigs during the fourth fiscal quarter, 63 rigs during fiscal 2017, and 33 rigs during fiscal 2018. The average daily margins for these rigs that are currently under long-term contract is expected to remain strong during the next several quarters as some rigs roll off and the remaining new builds are deployed. The average pricing today for the seven rigs in the spot market remains over 30% lower as compared to spot pricing at the peak in late 2014. Let me now transition to our offshore operations. Segment operating income declined to approximately $3 million from $8 million during the prior quarter. Total revenue days declined by about 6%, and the average rig margin per day declined by about 7% to $7,436 per day during the second fiscal quarter. Most of the rigs that generated revenue during the second fiscal quarter were rigs that remained idle on customer-owned platforms and are generating standby-type day rates. As we look at the third quarter of fiscal 2016, we expect quarterly revenue days to decline by approximately 8% as seven of our nine offshore platform rigs generate revenue days during the quarter. The average rig margin per day is expected to increase to approximately $8,000 during the third fiscal quarter. The expected decline in activity is attributable to a rig that was demobilized and stacked onshore during the second fiscal quarter. Management contracts on platform rigs continued to contribute to our offshore segment operating income. Their contribution during the second fiscal quarter was approximately $2 million. Management contracts are expected to generate approximately $3 million during each of the remaining two quarters of fiscal 2016. Moving on to our international land operations. The segment reported operating losses of approximately $2 million during the second fiscal quarter. The average rig margin per day decreased sequentially from $11,811 to $10,487 per day during the second fiscal quarter. Quarterly revenue days decreased sequentially by approximately 7% to 1,307 days during the same quarter. As of today, our international land segment has 14 rigs generating revenue days, including 10 in Argentina, two in the UAE, one in Colombia, and one in Bahrain. All 14 rigs are under long-term contracts. The 24 remaining rigs are idle. We expect international land quarterly revenue days to be slightly down by approximately 3% during the third quarter of fiscal 2016, and the average rig margin per day to slightly increase to approximately $11,000 per day. Let me now comment on corporate level details. Our strong balance sheet and high-liquidity position, along with our firm backlog of long-term contracts and reduced CapEx requirements should continue to allow us to return cash to shareholders by sustaining the level of our regular dividend payments as previously discussed. Excluding rigs with long-term contracts that have already been early-terminated and combining all three of our drilling segments, we currently have an average of approximately 99 rigs under term contracts expected to be active in fiscal 2016, 78 in fiscal 2017, and 47 in fiscal 2018. Our backlog level as of March 31, 2016 was at approximately $2.3 billion. Capital expenditures for fiscal 2016 are now expected to be in the range of $300 million to $350 million, as compared to our prior guidance of $300 million to $400 million. 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 second quarter of fiscal 2016 was 32.6%, and we expect the effective tax rate for each of the remaining two quarters of fiscal 2016 to be in the range of 33% to 36%. With that, let me turn the call back to John.

[John W. Lindsay:]

Thank you, Juan Pablo. I wanted to mention a couple of comments before we open it up to Q&A. As you know, the U.S. land rig count today is comparable to the all-time record low that's reached in 1999, and some are comparing the cycle to the 1980s. Even with the recent oil price rebound of $45 a barrel, sharp reductions in personnel expenses and investments are continuing worldwide. With the market intelligence we have today, we expect to see further deterioration in terms of drilling activity during the third fiscal quarter. That said, we are seeing more indications that the bottom of the cycle is nearing. The question remains how quickly E&P companies gain enough confidence in the market to begin investing back into the business and putting idle FlexRigs back to work. And now, Tanisha will open the call to Q&A.

[Operator:]

Certainly. And we'll go ahead and take our first question from Dan Boyd with BMO Capital Partners. Please go ahead. Your line is open.

[Daniel J. Boyd:]

Hello. Thanks, guys. You mentioned the advantages of your rigs and the technology that they have. You also have a number of competitors that are coming out with sort of the latest and greatest rig designs. So I just wanted to get your thoughts on are you looking to come out with a new rig design? And at what point do you think you'll start increasing investments to prepare yourself for the next cycle?

[John W. Lindsay:]

Good morning, Dan. This is John. Well, I think if you look at the investments that are being made, first of all, all of those rigs are AC drive technology and so that's kind of the basis for the design. And a lot of the design criteria on a lot of the rigs are really in an effort to match a lot of the rigs that we have out in the field today. So as far as just pure rig designs – and I'm speaking primarily to the drilling contractors, I'm not addressing some of the other rig designs out there described as futuristic-type designs. I'm speaking more to the contractors today. We continue to add technology, and we have over the past 10-plus years. We've continued to have innovations that improve our systems, and we're continually upgrading and high-grading. So I sure wouldn't want to leave you with the impression that we're not looking at other designs and other opportunities. The fact of the matter is I think the industry has all of the Tier 1-type rig assets that are needed, the question is which of those assets are going to work. Obviously, we feel very confident that our rigs are the ones that are going to be most sought after. So we are continuing to invest, but I don't see any real – based on what I've seen, I don't see any real breakthroughs in terms of technologies that are being talked about out there.

[Daniel J. Boyd:]

Okay. And then just to follow-up on the last point you made about being able to put rigs back to work. There's a lot of moving parts in your daily operating cost. But if you were to add an incremental rig or 10 incremental rigs, what do you think the daily operating cost would be for those specific rigs?

[John W. Lindsay:]

I think putting out the next 10 rigs, 20 rigs, 30 rigs would be a very low cost for us. The good news for us, obviously, as you would increase your revenue days so your denominator would increase, I mean that's, part of what's driving our costs up. Costs, in general, and rigs that are actually working are very reasonable, it's the other costs that we have associated. So I think the more rigs we could put back to work, the better off we're going to be in terms of our total cost per day.

[Daniel J. Boyd:]

Okay. All right, thanks.

[Daniel J. Boyd:]

Thanks, Dan.

[Operator:]

Thank you. Our next question comes from Angie Sedita with UBS. Please go ahead. Your line is open.

[Angie M. Sedita:]

Thanks. Good morning, guys.

[John W. Lindsay:]

Good morning.

[Juan Pablo Tardio:]

Hey, Angie.

[Angie M. Sedita:]

So John, if you think about – and we've talked about this a little bit before, but maybe you can elaborate the potential day rate outlook in a U.S. recovery and how you think it could play out. Some drillers are saying that push for day rate on the initial rig is activated, but I think you said in the past that you thought maybe the first 100 rigs could be up flat, day rates to maybe bend under pressure, some fight for share, and the second 100 of rigs where you could start to see rates play out. So can you give us your thought?

[John W. Lindsay:]

Yeah, Angie. I think that what you described, I think, has some merit. I mean, obviously, ultimately if you have folks that are pricing in such a fashion that is outside of the norm – but I think, in general, what you described makes sense. I mean, early on, I think you're going to see some real pressure on spot market pricing. I mean, as you know, there's not much of a spot market to speak of out there right now. There's not a lot of pressure, there's not a lot of bidding going on. But I think the other thing to keep in mind is, in contrast to previous cycles where really every rig out there was out there fighting for that type of work for the more difficult, unconventional horizontal wells, that's a fairly small subset, as you know, of the total rig fleet if you were look back to the peak activity in October of 2014. So I think it's – we've described it as around 700 rigs or so that are 1,500 horsepower. And, of course, you're going to have a subset of those rigs that are going to be the top performers that are going to have the best equipment. And those are the rigs that are going to be those most sought after.

[Angie M. Sedita:]

Okay. Okay, that's helpful. And then, I guess, in conjunction with that is if you think you play through that recovery and you know that a number of rigs are in this ready-state status, and if you think back how quickly you could start to add rigs, is people going to be a bottleneck and have you had any conversations with your E&Ps on what oil price they would need to come back to the market?

[John W. Lindsay:]

Well, we have on the price, and as you know that price is different for different customers. I think in our last call, we described it as a $45 to $55 range. There's been a few E&Ps, I think, recently that have talked about $50. Obviously, there's a lot of confidence that has to be made up between now and then, really beginning to put rigs back to work. But I think that's probably the range that we would need to see in order to see rigs going back to work. As far as our fleet and related to people, we've had great success in past cycles in attracting people back to H&P. We obviously have a lot of experience on the rigs today, so we have all the drillers and all the skill positions. We would need to be hiring back more jobs related to floorhand-type work. And again, our belief is that once the industry is on a clear path to recovery, I think you have people that would come back to the industry. But again, only time will tell on that.

[Angie M. Sedita:]

Okay. And one more if I could slip it in, that's really helpful. Can you remind us of your FlexRigs? And you mentioned 700 of the rigs are 1,500 horsepower. How many of your FlexRigs is at1,500 horsepower?

[John W. Lindsay:]

It's over 300 – yeah, 323.

[Angie M. Sedita:]

Okay. Okay.

[Juan Pablo Tardio:]

That would be in the U.S.

[John W. Lindsay:]

Correct. Yeah, that's just in the...

[Angie M. Sedita:]

Okay. Great. Wonderful. Thanks. I'll turn it over.

[John W. Lindsay:]

And Angie, I might also mention when you look at where the rigs are positioned, and I talked about the Permian, if you look at our available fleet, the rigs that are idle, we have a little over 30% in the Permian, a little over 30% in the Eagle Ford. And so those are, from my perspective, two of the lower cost basins that you would expect to see rigs going back to work. So we're positioned really well from that.

[Angie M. Sedita:]

Okay. And then for – you guys are the leading market share in both those basins, correct?

[John W. Lindsay:]

Yes.

[Angie M. Sedita:]

Okay, got it. Thanks.

[John W. Lindsay:]

Okay. Thank you.

[Operator:]

Thank you. And our next question comes from Matt Marietta with Stephens, Inc. Please go ahead. Your line is open.

[Matt Marietta:]

Thank you, and good morning. Thanks for taking the questions.

[John W. Lindsay:]

Good morning.

[Juan Pablo Tardio:]

Good morning, Matt.

[Matt Marietta:]

I wanted to see if I can get a little bit more color on the CapEx reduction. Are you guys seeing greater efficiencies on the maintenance CapEx side? Are you seeing deflation in supplies or labor? Is this more of a function of the overall outlook in the active rig count in the fleet? Maybe help us understand all the different ins and outs there as it is about $50 million or so in savings from the prior guide.

[Juan Pablo Tardio:]

Sure, Matt. This is Juan Pablo. As we had described in the past, a lot of the $300 million to $400 million that we've previously estimated were related to market conditions. And obviously, market conditions have been soft, even softer than expected and they're expected to remain relatively soft. And so that is driving down some of the maintenance CapEx, and also some of the special projects that would be in response to a potentially improving market. So it's mostly based on market conditions.

[Matt Marietta:]

Thank you. So I guess there hasn't been a major structural change in kind of a run rate maintenance CapEx as we think about a per-rig basis. We shouldn't think of there being a permanent change there, right?

[Juan Pablo Tardio:]

Not really. It's not a perfect process, of course. Maintenance CapEx depends on a lot of considerations. One important one is what rigs do you have working. If you have mostly newbuild rigs working or rigs that have been built in recent years, then your maintenance CapEx will probably be lower, and that's part of what we're seeing out there. The other consideration relates to a lot of components being available in the existing fleet that we're trying to be as efficient as we can in using that, of course, (33

[Matt Marietta:]

I appreciate the color. And then my next question here, really switching to the international fleet, can you maybe help us see the long-term goal internationally? Can you continue to use South America, for example, as kind of a relief valve as it relates to what's clearly an oversaturated U.S. land complex? And maybe talk about the appetite for Tier 1 rigs internationally. Do you see that changing and evolving? I recall you were able to send, I think it was 10, 12 rigs down to South America recently or over the last couple of years. But what other opportunities do you see? Can you maybe expand more in the Eastern Hemisphere? As you look at the international rig fleet, a lot of is in South America. How can we view kind of that international business for H&P in the longer term do you think?

[John W. Lindsay:]

Yeah, Matt. This is John. And we've talked about this for years and you're right, we did have – we did send 10 existing FlexRig3s to Argentina a few years ago now. And we have Flex3s in Colombia, and as well as Flex4s both in Colombia and in Argentina. And we have Flex3s and Flex4s in the Middle East. So we've thought for a long time that we could have some significant growth internationally. As you know, the international markets are struggling right now as well, but we do see the current fleet that we have in the U.S. being able to expand internationally when those opportunities arise. We keep thinking that it will be growth in the international area in terms of unconventional resource plays, and really that's what the 10 rigs – the growth in Argentina for the Flex3, that's what that was all about. And so hopefully, we'll see that happen. I think there's nobody better positioned than H&P to take advantage of that. As you know, we've been working internationally for over 50 years, so we have a lot of experience and capability. So we're just waiting for those opportunities.

[Matt Marietta:]

I appreciate that. And do you think that as you look in the Middle East as maybe an area where you could deploy more assets, is there a hunger for more rig contractors to enter into the market? Or can you maybe help us understand the competitive landscape, how difficult it is to break into certain territories, I guess, in a greater scale if you're already there? That's kind of my last question here, and I'll hop back in the queue.

[John W. Lindsay:]

Sure. Well, I don't think there's any doubt that having a footprint there is advantageous. We've got a couple of Flex3s in UAE and we have some Flex4s in Bahrain. So we have some opportunity to expand. Again, we're looking forward to that. We just don't have anything, really, in our sights right now in terms of opportunities. But we believe that there will be opportunities in the future.

[Matt Marietta:]

Thanks a lot.

[John W. Lindsay:]

Thank you.

[Operator:]

Our next question comes from Marc Bianchi with Cowen. Please go ahead. Your line is open.

[Marc Bianchi:]

Hey, good morning. Just looking at the guidance here for the upcoming quarter. It seems like the proportion of rigs on long-term contract is going to be pretty high as a proportion of the total rigs working. And then looking at the margin guidance, you have margins going down. I would've thought that margins would move higher if you have a larger proportion being a long-term contract. Can you speak to that, please?

[Juan Pablo Tardio:]

Sure, Marc. This is Juan Pablo. There are at least a couple of things that are contributing to an unfavorable move. And the first one has to do with the growing proportion of idle rigs and expenses associated with those idle rigs. Some of those expenses are fixed. Some relate to the process that we are going through, the transition. As rigs become idle, as you know, there are stacking expenses. There are personnel expenses that we incur, and so that impacts the average unfavorably. We also have a couple of other things going on. One is related to a higher-than-normal number of personnel positions in the field and early retirements related to employees. So that's what is impacting the average rig margin, the $13,800 that we've guided toward, in a way that is unfavorable. Hopefully, as John mentioned, as we see more stability and hopefully see rigs going back to the field, we hope to have a favorable movement in the average rig expense per day.

[Marc Bianchi:]

Is there anything that's – you mentioned the personnel cost there that may be perhaps one-time? Is there any piece of this that we can think of as one-time in your fiscal third that won't be in the fourth?

[Juan Pablo Tardio:]

Well, it all depends on what levels of transition we see in the fourth fiscal quarter. Obviously, when we have transitions like these, all of those expenses, we believe, are specific to the quarter and hopefully are non-recurring. But unfortunately, we've been going through this quarter after quarter. During the third fiscal quarter, we expect a very significant decline, as mentioned, of 25% to 28%. And when that happens, those expenses that pertain to the quarter and all the moving variables that are not normal and that are ongoing, that's really what's going on. Going forward, we – hold on just a second, please. Yeah. One clarification. I may have related it to a margin guidance of $13,800. I was referring to the average rig expense being $13,800, of course, as we spoke earlier about. But let me stop there. Does that answer your question, Marc?

[Marc Bianchi:]

Yes. That's helpful, Juan Pablo. I guess, maybe related is – has there been any adjustment in any of the contracted rates that you have?

[Juan Pablo Tardio:]

Not significant. As we mentioned, some of these rigs are becoming idle, and we are charging day rates that protect us in terms of the expected margin for those rigs. But nothing significant is going on in terms of what we expect to attain from our long-term contracts.

[Marc Bianchi:]

Got it. Okay...

[John W. Lindsay:]

Hey, Marc. This is John. I wanted to also clarify and make certain that the guys in the field have really done an excellent job, we talked about it on the last call, related to expenses and really managing that in a really strong way. So this cost increase really has nothing to do with the rig itself as I had mentioned before. The leadership team was in Permian Basin a couple of weeks ago, and it was really impressive to see how hard they're working and the attitude that they have in this market. But when you consider all the things that Juan Pablo addressed, that's really what's driving the cost. It's not the actual expenses at the rig side.

[Marc Bianchi:]

Got it. Okay. Thanks, John. If I could just one more for Juan Pablo, I guess. On the depreciation, been running a little bit lower than the guidance that you provided for the year. Is there any reason to think that on a quarterly basis it's going to tick up here in the back half?

[Juan Pablo Tardio:]

It may. There are some variables that impact that. Hopefully, we'll see a number for the year that is lower than the $580 million. But we don't have enough information and certainty at this point to provide that guidance. We may update the guidance, of course, during our next conference call.

[Marc Bianchi:]

Okay, great. Thanks. I'll turn it back.

[Juan Pablo Tardio:]

Thank you, Marc.

[John W. Lindsay:]

Thank you.

[Operator:]

Thank you. And we'll go ahead and take our next question from Daniel, John with Simmons & Company. Please go ahead. Your line is open.

[John M. Daniel:]

Hey, guys. A couple of things for you.

[Juan Pablo Tardio:]

Hi, John.

[John M. Daniel:]

How are you?

[Juan Pablo Tardio:]

I'm doing all right. Thanks.

[John M. Daniel:]

Okay. First question, just based on inbound inquiries from clients, do you believe that revenue days will increase in the fourth fiscal quarter over the current quarter?

[John W. Lindsay:]

John, there's not a lot of – unfortunately, there's not a lot of inbound calls. And I think if we were to make an answer based on a hunch – if oil prices would remain $45-plus, and I think you could see some confidence in the market, I think you could begin to potentially see some rigs go back to work. But as you know, as we all suffer through – witness last summer when oil prices were in the $55 to $60 range and then pull back, and so I think it's going to have to maintain a level of consistency for some period of time before you see rigs going back to work. But I mean, I wouldn't be surprised to see rigs going back in the fourth quarter. But at this stage of the game, we're sure not receiving a lot of calls.

[John M. Daniel:]

Okay. Fair enough. Because you did mention that, I think, the fiscal Q3 cost per day guidance does include some rightsizing costs. That would seem to me that you're not expecting a sharp recovery at this point or a quick recovery.

[John W. Lindsay:]

Based on what we see right now for the third quarter, we don't see any recovery. Obviously, it could happen...

[John M. Daniel:]

Right.

[John W. Lindsay:]

...it could be ongoing right now, and it would begin by – one way to think about it is rigs that have been given notification of release. Those notifications get rescinded and rigs don't actually get released. And rigs that are on standby would go back to work, and then ultimately you'd begin to see some rigs being picked up in the spot market. So that could happen. We just haven't' seen it begin at this stage.

[John M. Daniel:]

Fair enough. Just one final one for me, then I'll it over. But I'm trying to just better understand the whole impact of drilling efficiencies and how that'll impact the recovery in the rig count. So just on that point, when you visit with customers and they share with you their rig count needs going forward, let's assume on a higher commodity price deck, do they provide any color to you about what their peak potential rig count may be? And if so, how does that compare with what may have been their most recent peak rig count?

[John W. Lindsay:]

John, I think there's a...

[John M. Daniel:]

I know it's a hard one.

[John W. Lindsay:]

Well, it is a hard one. And I think one of the reasons why it's so hard is because – I mean, there is that – really, probably one of the last things anybody is really thinking about right now because they've been cutting their rig counts and trying to figure out how to rightsize their organization. I don't think anybody is really thinking about those types of comparisons. I think, longer term, I personally don't think it's as dramatic as a lot of people believe. But again, only time is going to tell. I sure don't expect to see 1,800 rigs working anytime soon. But yeah, we just haven't heard anything from customers on that point.

[John M. Daniel:]

All right. Thanks, guys.

[John W. Lindsay:]

Thank you.

[Juan Pablo Tardio:]

Thank you, John.

[Operator:]

Thank you. And our next question comes from Michael LaMotte with Guggenheim. Please go ahead. Your line is open.

[Michael LaMotte:]

Thanks. Good morning, guys.

[John W. Lindsay:]

Good morning.

[Michael LaMotte:]

May be I can start with just sort of the inverse of Angie's question, which is how much of the fleet today is 1,000 horsepower?

[John W. Lindsay:]

We'll take a look at it.

[Michael LaMotte:]

Okay. And with all the emphasis on the 1,500s, what is the outlook for the 1,000s?

[John W. Lindsay:]

I think we have around 22 rigs that are 1,000 horse. Those rigs are typically designed for more vertical, shallower type work. We actually have that particular model of Flex4 working in Colombia, in Argentina and in the Middle East. Actually, I'm not certain the ones in Argentina are working right now. But, in any event, we have those rigs. So those rigs are candidates to work internationally. They're obviously candidates to go back to work in the Permian Basin because that's where most, if not all, of those rigs are located.

[Michael LaMotte:]

Vertical is?

[John W. Lindsay:]

For vertical-type work now, not for horizontal work.

[Michael LaMotte:]

Yeah. Yeah, okay. So there's no real risk of impairment to those at this point?

[John W. Lindsay:]

I sure don't think so. Again, those rigs have worked recently, and I think that that vertical – that 8,000- to 12,000-foot vertical-type work in some of the basins in the U.S., and as well as internationally are going to be in existence.

[Michael LaMotte:]

Okay. On reactivations, what do I have to see in terms of term? I mean, sure you're going to have to go out in hard cruise and spend some money to gear up. I imagine you're not going to do that for a well-to-well-type of work.

[John W. Lindsay:]

Well, Michael, I think for anybody to expect that you're going to get term contract work coming off the bottom in this environment, I think that would be a surprise. Again, in order for us to activate a rig and get it out working is going to be very, very low cost for us. We're well prepared, acquiring the personnel. That's not a high cost, so I don't see that as being a stretch. And we won't be going in. And more than likely, you're not going to just drill one well unless the commodity environment were to begin to pull back again. You're going to drill multiple wells. So I'd be surprised to see many of these rigs going back to work with term contract commitments.

[Michael LaMotte:]

Okay. So the decision to reactivate really is a function of nothing else immediately available and you don't want to say no to a client?

[John W. Lindsay:]

Well, it's in our best interest to get rigs back working for a lot of reasons related to people and revenue days. And as Juan Pablo described, I mean, that's a part of the challenge that we have related to expenses, is a larger numerator and a smaller denominator. So if we can put rigs back to work, then that's beneficial for us and beneficial for customers, beneficial for our employees.

[Michael LaMotte:]

Yeah, for sure. I understand that, I just mean the decision to activate, whether it's really customer driven or you anticipating customer activity.

[John W. Lindsay:]

Well, yeah. I mean, we have, as you know, really long-term relationships with some really strong customers that would probably be some of those that would respond more quickly than others. So yes, we're going to be there for them and be ready to respond.

[Michael LaMotte:]

Yeah. Okay, great. Thanks, guys.

[John W. Lindsay:]

Thank you.

[Juan Pablo Tardio:]

Thank you.

[Operator:]

Thank you. And our next question comes from Robin Shoemaker with KeyBanc Capital Markets. Please go ahead. Your line is open.

[Robin E. Shoemaker:]

Okay. Good morning. Wanted to – most of my questions have been answered. But I wanted to ask you about the status of the facility that you have in Houston, where you assemble and refurbish rigs. And just from the way it looks, I think you had a little bit of a backlog of maybe three or four rigs yet to be built that you've deferred. But what role might that play going forward? It seems like it would be a long time before you would actually build another rig or even refurbish, since you've got some very new rigs, right, ready to go.

[John W. Lindsay:]

Yeah. Robin, this is John. The facility – you're right. Don't expect to be building any new rigs anytime soon. We have utilized that facility. You touched on refurbishing. We have utilized that facility to refurbish rigs, getting them ready for international work. We've also used that facility for certain upgrades that we've done to our rig fleet. And so that's part of the way that, up to this point, in addition to finishing out those newbuilds that we've been able to keep some folks employed. But obviously, it's not going to be turning out the amount of material that it did before, but we'll continue to keep an eye on that. But that's how we would utilize that facility and other facilities is to upgrade and high-grade the fleet.

[Robin E. Shoemaker:]

And with the remaining kind of backlog of newbuilds that you had, has that been switched to, like, existing rigs that are available or...

[Juan Pablo Tardio:]

Robin, this is Juan Pablo. We have a couple or three rigs that are pending delivery. So those are – the construction for those is ongoing and we expect that to be completed this year. But as John said, other than that, meaning other than the rigs that already have long-term contracts associated with them, there are no plans for other newbuilds at this time.

[Robin E. Shoemaker:]

Right. Okay. All right. Thank you.

[Juan Pablo Tardio:]

All right, Robin. Thanks.

[Operator:]

Our next question comes from Mark Close with Oppenheimer + Close. Please go ahead. Your line is open.

[Mark H. Close:]

Good morning, gentlemen. Just to clarify on the CapEx, the delayed newbuilds, how much of that is included – I mean, we're looking at, I guess, CapEx for the year ahead of – I mean, for the back half of the year of $120 million to $170 million. How much, if any, of that includes those delayed newbuilds and how much of that – how would these delayed deliveries affect your depreciation estimates?

[Juan Pablo Tardio:]

Thank you, Mark. This is Juan Pablo. Unfortunately, I don't have a specific answer for you. I believe that most of the expenses related to the new builds have already been absorbed during the first two quarters. I'd have to double check on that. And remind me the second part of your question, Mark.

[Mark H. Close:]

So if you've got new builds that have been completed but have not been delayed – I mean, not been delivered and are going to be delayed for whatever period of time, are those depreciating? And...

[Juan Pablo Tardio:]

Thank you. Yes. We typically depreciate our rigs once they spud operations. And so the delayed rigs have not yet began depreciation from a financial perspective.

[Mark H. Close:]

Okay. Thank you.

[Juan Pablo Tardio:]

And so obviously, that's impacting the depreciation number in a slightly favorable way, making it slightly lower than expected. But the impact is not very significant, given the scale of our total depreciation.

[Mark H. Close:]

Right. Right. Okay, thanks.

[Juan Pablo Tardio:]

Thank you, Mark.

[Operator:]

Thank you. And we'll go ahead and take our next question from Tom Curran with FBR Capital. Please go ahead. Your line is open.

[Tom P. Curran:]

Good morning, guys.

[Juan Pablo Tardio:]

Hi, Tom.

[John W. Lindsay:]

Good morning.

[Tom P. Curran:]

Thanks. Thanks for squeezing me in. I'll try to be quick. Most of my questions have been answered. Just a few fleet specs ones. John, could you tell us, of your 1,500 horsepower FlexRig segment, what percentage of those have three mud pumps and 7,500 psi capability?

[John W. Lindsay:]

Tom, we haven't published that. I know the number continues to grow. We haven't published that up to this point. So it's probably – hold on, just a sec . Yeah, Tom, we don't have it sorted quite like that. Again, it's probably 30% to 40% of our fleet. But not all rigs that have 7,500 also have a third mud pump. So there's some mix associated with that. Same way with four engines, there's different criteria that customers have had, so it's not as easy to slice and dice.

[Tom P. Curran:]

Understood, John. But that 30% to 40% rough estimate, would that apply to the 1,500-horsepower FlexRigs or your total U.S. land fleet?

[John W. Lindsay:]

I believe the 1,500-horsepower, yes.

[Tom P. Curran:]

Okay. And then one more on this line of questioning. Are you continuing to upgrade your idle rigs? And if so, what all are you including in those upgrades? To the extent you're doing it, is it still just adding skidding systems to FlexRig3s that don't have them, or have you now also started to add third mud pumps, and where possible, upgrade the PSI capability?

[John W. Lindsay:]

Yes, Tom, we've continued to upgrade the fleet to 7,500 on those that have 5,000, where the customer needs it. We've added third mud pumps. We've added fourth engines. We've increased setback capacity on the rigs in order to handle – a lot of the rigs already have the capacity for 25,000-foot a setback, but not all of them do and so we're upgrading that. There's just – there's various – I kind of addressed a little bit of that in my prepared remarks, that we've continued to do that over time, and we're doing that in this cycle as well.

[Tom P. Curran:]

Okay. And I know you spoke to CapEx in the beginning, so I'm sorry if I didn't catch all of this, but could you give us an idea of how much of the CapEx budget is being allocated to such upgrades?

[John W. Lindsay:]

I don't think we've narrowed it down to that, Tom. I mean, it's not a huge percentage. I don't know that we've updated...

[Juan Pablo Tardio:]

Yeah. We don't have a number for you, Tom, unfortunately.

[Tom P. Curran:]

Okay. All right. I appreciate the additional answers and staying on a bit later. Thanks, guys.

[John W. Lindsay:]

Sure, Tom. Thanks.

[Tom P. Curran:]

Thank you. And Tanisha, we have time for one more question, please.

[Operator:]

Okay, perfect. We'll go ahead and take our last question from Darren Gacicia. Please go ahead. Your line is open.

[Darren Gacicia:]

Hey. Thank you very much for adding me on at the end.

[Juan Pablo Tardio:]

Thank you.

[Darren Gacicia:]

My question is around rig margins and the progression they may take in the recovery. I think you said that spot day rates from the peak are down around 30%. I think you said over the course of the call that most of the rigs, if they go to work, at least in the front end of a recovery, will come from spot. So when I think about that, that seems to tell me that even as you recover, your day rates can continue – your average margin can come down. I guess the question really lies in terms of, A, calibrating that, but, B, thinking about what the absorption offset is from a fixed cost perspective, and just how to calibrate that. I realize you guys have taken a fairly conservative tack on the call, but I'm just trying to get a sensitivity thought process on how to think about that in my model.

[Juan Pablo Tardio:]

Yes, Darren. This is Juan Pablo. There are so many moving pieces there that I would hesitate to even start outlining those because – there's not just one or two that I could mention that would bring clarity to that. I think your overall assumption is true. Obviously, if we enter a recovery and we put rigs back to work, those rigs will probably go back to work at day rates and margins that relate closely to where we are in the spot market today. And as that happens, the impact of that will be probably negative on the margin as we have a high proportion of rigs in the spot market going forward, assuming, of course, that there is that recovery. The only other factor that I'll mention is what John already mentioned, and that is that as we put rigs back to work and the total number of idle rigs begins to decline, that in general will have a favorable impact on margins as some of those fixed costs related to the idle fleet will start to be reabsorbed. But I'm sorry not to be able to provide more clarity, but hopefully that helps.

[Darren Gacicia:]

Well, maybe asked a slightly different way, in terms of the margin degradation we've seen so far, is there any way to kind of get a sense of that? What part of it's been absorption and what part of that is pricing?

[Juan Pablo Tardio:]

Darren, I'm not sure that I understand your question. Could you rephrase it, please?

[Darren Gacicia:]

Well, put it this way, pricing declines may roll through and that should impact the margin line directly. Then there's kind of an absorption part of it. So is there a way to think about things on pricing versus absorption in terms of what we've already seen?

[Juan Pablo Tardio:]

Not a simple, straightforward way, Darren. I think pricing will depend – the average rig revenue per day will be impacted by the proportion of rigs that are on standby and that have significantly lower day rates as we don't have the rigs working and what proportion that makes up in terms of the total. But that's just one more moving piece as we go forward. I think what may be an important part of the question is related to the rigs that we already have under term contracts and what those margins might be. And the answer to that is that the margins to the rigs that are under term contracts that are currently operating or that are on standby-type day rates, those are as strong as we expected. We have not seen any deterioration there as expected. Obviously, we've benefited from early terminations in a very significant way. And so our backlog is a very important piece of the equation for us, and it has been strong and we expect for that to continue to be strong. But other expenses related to transitionary expenses, related to all of the aspects that we've already mentioned are also an important part of the equation.

[Darren Gacicia:]

Okay. Thank you very much.

[Juan Pablo Tardio:]

Thank you, Darren. And now, we'll turn it back to John Lindsay for some closing remarks.

[John W. Lindsay:]

So thank you again for listening this morning. I'm going to close by leaving you with the following thoughts in that our long-term contracts have allowed the company to remain profitable and to protect FlexRig investments. The company's efforts in energy are focused on adding value to our customers and becoming even more efficient and effective as an organization. Whether we see more declines in activity or significant improvement in demand, H&P is well positioned to respond. As we have described in the past, our strong and liquid balance sheet, robust backlog, and lower spending requirement should allow us to continue to return cash to shareholders. Our strength is driven by our people, and we appreciate their attitude in the face of this adversity and their dedication to the company through these difficult times. And again, thank you for listening in with us this morning, and have a great day.

[Operator:]

And that does conclude today's program. We'd like to thank you for your participation. Have a wonderful day, and you may disconnect at any time.