Helmerich and Payne Inc (HP) 2016 Q2 法說會逐字稿

Good day, everyone, and welcome to today's second-quarter earnings conference call. (Operator Instructions). 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.

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 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, 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 US.

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 US 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 lifecycle 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 in 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 have 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 1500 horsepower AC drive Tier 1 rigs provide the best drilling performance for drilling the most challenging horizontal wells. H&Ps fleet has over 30% of the estimated 700 rigs in the US 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 US 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 1500 horsepower AC drive capability that are ready to work.

Let me also make a point for ready to mobilize quickly. We have made prudent investments in taking 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 goodbye 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 have 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?

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 profits. Nevertheless, market conditions continue to deteriorate and drilling activity for the Company continued to decline.

Following are some comments on each of our drilling segments.

Our US line 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 at 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 US 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 notification, this 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 newbuilds 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 $7,346 per day during the second fiscal quarter.

Most of the rigs that generated revenue during the second fiscal quarter were rigs that remain 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 on shore during the second fiscal quarter.

Management contracts on platform rigs continue 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, 2 in the UAE, 1 in Colombia and 1 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 requirement, 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%. 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.

Thank you, Juan Pablo. I wanted to mention a couple of comments before we open it up to Q&A. As you know, the US land rig count today is comparable to the all-time record lows reached in 1999 and some are comparing the cycle to the 1980s. Even with the recent oil price rebound to $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 Instructions). Dan Boyd, BMO Capital Partners.

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 the latest and greatest rig designs. 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 will start increasing investments to prepare yourself for the next cycle?

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 is 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 am not addressing some of the other rig designs out there described as futuristic type designs; I am speaking more to the contractors today.

We continue to add technology and we have over the past 10 plus years, we have continued to have innovations that improve our systems and we are continually upgrading and high grading. So I sure wouldn't -- I wouldn't want to leave you with the impression that we are 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.

Okay. And then just a follow-up on the last point you made about being able to put rigs back to work. 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 that daily operating cost would be for those specific rigs?

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 is part of what is driving our cost up.

Costs in general on rigs that are actually working are very reasonable, it is the other costs that we have associated. So I think the more rigs we could put back to work the better off we are going to be in terms of our total cost per day.

Okay. All right, thanks.

(Operator Instructions). Angie Sedita, UBS.

So, John, if you think about -- and we have talked about this a little bit before, but maybe you could elaborate -- the potential day rate outlook in a US recovery and how you think it could play out.

Some drillers are saying that push for day rate on the initial rigs activated. But I think you said in the past that you thought maybe the first 100 rigs could be at flat day rates to maybe vendor pressure as some fight for share and the second hundred of rigs where you could start to see rates play out. So can you give us your thoughts?

Yes, Angie, I think that 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 is not much of a spot market to speak of out there right now. There is not a lot of pressure, there is 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 is a fairly small subset, as you know, of the total rig fleet if you were to look back to the peak activity in October 2014.

So, I think it is a -- we have described it as around 700 rigs or so that are 1,500 horsepower, and of course you are 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.

Okay, okay, that is helpful. And then I guess in conjunction with that is if you think -- play through that recovery, and you noted that a number of your rigs are in this steady-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?

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 has been a few E&P's I think recently that have talked about $50. Obviously there is 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 is 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 have 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 floor hand type work. And again, our belief is that once the industry is on a clearer path to recovery, I think you have people that would come back to the industry. But again, only time will tell on that.

Okay, and one more if I could slip it in, that is really helpful. Can you remind us of your FlexRigs, and you mentioned 700 of the rigs are 1500 horsepower. How many of your FlexRigs have 1500 horsepower?

It's over 300 -- 323.

Okay, wonderful.

That would be in the US, correct.

Yes, that is just in the US.

Okay, great. Wonderful. Thanks, I will turn it over.

And, Angie, I might also mention when you look at where the rigs are positioned, I talked about the Permian. If you look at our available fleet, the rigs that are idle, we have a little over 30% of 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 are positioned really well from that perspective.

Okay. Okay and then for -- you guys are the leading -- have leading market share in both those basins, correct?

Yes.

Okay, got it. Thanks.

Matt Marietta, Stephens Inc.

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 as 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.

Sure, Matt, this is Juan Pablo. As we had described in the past, a lot of the $300 million to $400 million that we previously estimated were related to market conditions. And obviously market conditions have been soft, even softer than expected, and they are 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 is mostly based on market conditions.

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?

Not really, it is not a perfect process of course, maintenance CapEx depends on a lot of considerations. One important one is what rig do you have working. If you have mostly newbuilds working -- newbuild rigs working or rigs that have been built in recent years, then your maintenance CapEx will probably be lower and that is part of what we are seeing out there.

The other consideration relates to a lot of components being available in the existing fleet that we are trying to be as efficient as we can in using that of course before seeing any deterioration in the field for the lack of use.

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 is clearly an oversaturated US 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 it is in South America. How can we view kind of that international business for H&P in the longer term, do you think?

Yes, Matt, this is John and we have talked about this for years and, you are right, we did send 10 existing FlexRig 3s to Argentina a few years ago now. And we have Flex3s in Colombia as well as Flex4s both in Columbia and in Argentina. And we have Flex3s and Flex4s in the Middle East.

So, we have thought for a long time that we can 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 US 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 is what the 10 rigs -- the growth in Argentina for the Flex3s, that is what that was all about. And so hopefully we will see that happen.

And I think there is nobody better positioned than H&P to take advantage of that. As you know, we have been working internationally for over 50 years so we have a lot of experience and capability. So we are just waiting for those opportunities.

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 the greater scale if you are already there is my last question here and I will hop back in the queue?

Sure. Well, I don't think there is any doubt that having a footprint there is advantageous. We have got a couple of Flex3s in UAE and we have some Flex4s in Bahrain. So we have some opportunity to expand.

Again, we are looking forward to that. We just don't have anything really in our sites right now in terms of opportunities. But we believe that there will be opportunities in the future.

Thanks a lot.

(Operator Instructions). Marc Bianchi, Cowen.

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 have thought that margins would move higher if you have a larger proportion being long-term contract. Can you speak to that, please?

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 retirement related to employees. So that is what is impacting the average rig margin, the $13,800 that we guided toward in a way that is unfavorable.

Hopefully as John mentioned, as we have seen 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.

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?

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 nonrecurring.

But unfortunately we have 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 is really what is going on.

Going forward we -- hold on just a second, please. Yes, one clarification. I may have related 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?

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

Not significant. As we mentioned, some of these rigs are being -- 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 obtain from our long-term contracts.

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. And so, this cost increase really has nothing to do with the rig itself, as I had mentioned before.

We were -- the leadership team was in the Permian basin a couple of weeks ago and it was really impressive to see how hard they are working and the attitude that they have in this market. But when you consider all the things that Juan Pablo addressed, that is really what is driving the cost, it is not the actual expenses at the rig site.

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 is going to tick up here in the back half?

It may. There are some variables that impact that. Hopefully we will 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.

Okay, great. Thanks, I will turn it back.

Daniel John (sic), Simmons & Company.

A couple things for you. 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, there is not a lot of -- unfortunately there is 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 suffered through, witnessed last summer when oil prices were in the $55 to $60 and then pulled back and -- so I think it is 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 are sure not receiving a lot of calls.

Okay, fair enough. Because you did mention I think the fiscal Q3 cost per day guidance does include some rightsizing costs. It would seem to me that you are not expecting a sharp recovery at this point -- or a quick recovery [apparently]?

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

Fair enough. Just one final one from me and I will turn it over. I am trying to just better understand the whole impact of drilling efficiencies and how that will 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 the 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, I think --.

I know that is a hard one.

Well, it is a hard one. And I think one of the reasons why it is so hard is because -- I mean that's really probably one of the last things anybody is really thinking about right now because they have been cutting their rig counts and trying to figure out how to right size 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 is 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, yes, we just haven't heard anything from customers on that point.

All right, thanks, guys.

Michael Lamotte, Guggenheim.

Maybe I can start with just sort of the inverse of Angie's question, which is how much of the fleet today is 1000 horsepower?

We will take a look at it.

Okay. And with all the emphasis on the 1500s, what is the outlook for that 1000s?

I think we have around 22 rigs that are 1000 horse, those rigs are typically designed for more vertical, shallower type work. We actually have that particular model of Flex4 working in Colombia and Argentina and in the Middle East. Actually I am 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 are obviously candidates to go back to work in the Permian basin because that is where most, if not all, of those rigs are (multiple speakers) for vertical type work, not for horizontal work.

Yes, yes, okay. So there is no real risk of impairment to those at this point?

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

Okay. On reactivations, what would you like to see in terms of term? I mean, if you are going to have to go out and hire crews and spend some money to gear up, I imagine you are not going to do that for well-to-well type work.

Well, Michael, I think for anybody to expect that you are 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 are well prepared acquiring the personnel, that is 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 are not going to just drill one well. I mean, unless the commodity environment were to begin to pull back again you are going to drill multiple wells. So, I would be surprised to see many of these rigs going back to work with term contract commitments.

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.

Well, it is 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 is 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 is beneficial for us and beneficial for customers, beneficial for our employees.

Yes, for sure. Understand that, I just mean the decision to activate whether it is really customer driven or you anticipating customer activity.

Well, yes, 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 are going to be there for them and be really to respond.

Yes, okay, great, thanks, guys.

Robin Shoemaker, KeyBanc Capital Markets.

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, which -- 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 have deferred.

But what role might that play in going forward? It seems like it would be a long time before you would actually build another rig or even refurbish since you have got some very new rigs right ready to go.

Yes, Robin, this is John. The facility -- you are right, don't expect to be building any new rigs anytime soon. We have utilized the facility you touched on refurbishing -- we have utilized that facility to refurbish rigs getting them ready for international work.

We have also used that facility for certain upgrades that we have done to our rig fleet. And so, that is part of the way that up to this point, in addition to finishing out those newbuilds that we have been able to keep some folks employed.

But obviously it is not going to be turning out the amount of material that it did before. So, but we will continue to keep an eye on that. But that is how we would utilize that facility and other facilities is to upgrade and high-grade the fleet.

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

We have -- 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 point.

Right, okay, all right. Thank you.

(Operator Instructions). Mark Close, Oppenheimer+ Close.

Juan Pablo, just to clarify on the CapEx, the delayed newbuilds, how much of that is included? I mean, we are looking at I guess CapEx for the year ahead -- 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?

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 newbuilds have already been absorbed during the first two quarters; I would have to double check on that. So -- and remind me the second part of your question, Mark?

So, if you have got newbuilds 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 --?

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.

Okay. Thank you.

And so, obviously that is 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.

Right, right. Okay, thanks.

Tom Curran, FBR Capital.

Most of my questions have been answered. Just a few fleet specs ones. John, could you tell us of your 1500 horsepower FlexRig segment, what percentage of those have three mud pumps and 7500 PSI capability?

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 the line just a second. Yes, Tom, we have -- we don't have it sorted quite like that.

Again, it is 30% -- probably 30% to 40% of our fleet. But not all rigs that have 7500 also have a third mud pump. So there is some mix associated with that. Same way with four engines, there is different criteria that customers have had. So it is not as easy to slice and dice.

Understood, John. But that 30% to 40% rough estimate, would that apply to the 1500 horsepower FlexRigs or your total US land fleet?

I believe the 1500 horsepower, yes.

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 as upgrades? To the extent you are doing it is it still just adding skidding systems to FlexRig 3s that don't have them? Or have you now also started to add third mud pumps and where possible upgrade the PSI capability?

Yes, Tom, we have continued to upgrade the fleet to 7500 on those that have 5000 where the customer needs it. We have added third mud pumps, we have added forth engines, we have increased setback capacity on the rigs in order to handle -- a lot of the rigs already have the capacity for 25,000 foot of setback but not all of them do. And so we are upgrading that.

There is just -- there's various -- I kind of addressed a little bit of that in my prepared remarks that we have continued to do that over time. And we are doing that in this cycle as well.

Okay, and I know you spoke to CapEx in the beginning so I am 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?

I don't think we have narrowed it down to that, Tom. It is not a huge percentage. I don't know that we have updated (multiple speakers).

Yes, we don't have a number for you, Tom, unfortunately.

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

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

Darren Gacicia.

My question is around rig margins and the progression they may take in the recovery. I realize -- 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 -- your average [margins] 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 that you guys have taken a fairly conservative tact on the call, but I am just trying to get a sensitivity thought process on how to think about that in my model.

Yes, Darren, this is Juan Pablo. There are so many moving pieces there that I would hesitate to even start outlining those because there is not just one or two that I could mention that would bring clarity to that.

I think your overall assumption is true obviously where 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 if that happens the impact of that will be probably negative on the margin as we have a higher proportion of rigs in the spot market going forward, assuming of course that there is that recovery.

The only other factor that I will 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 re-absorbed. But I am sorry not to be able to provide more clarity but hopefully that helps.

Maybe ask it a slightly different way. In terms of the margin degradation we have 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?

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

Well, put it this way, pricing declines may roll through and that should impact the margin line directly. Then there is 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 have already seen?

Not a simple straightforward way, Darren. I think pricing will depend -- the average rig revenue per day will be impacted by any -- 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 is yet 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 for the rigs that are on 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 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 transition area expenses related to all of the aspects that we've already mentioned are also an important part of the equation.

Okay, thank you very much.

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

So thank you again for listening this morning. I am going to close by leaving you with the following thoughts in that our long-term contracts have allow the Company to remain profitable and to protect FlexRig investments.

The Company's efforts and 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 a significant improvement in demand, H&P is well-positioned to respond.

As we described in the past, our strong and liquid balance sheet, robust backlog and lower spending requirements 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.

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