Helmerich & Payne Q2'16 Earnings Conference Call: Full Transcript

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. You may register to ask a question at anytime by pressing the star and one on your touchtone phone. You may withdraw yourself from queue by pressing the pound key. 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:Vice President and Chief Financial Officer:

Thank you, Tanish and welcome everyone to Helmerich & Payne 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 Hardie, Manager of Investor Relations.

As usual and as refined 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.

 

John W. Lindsay:President and Chief Executive Officer:

Thank you, Juan Pablo and good morning everyone and thank you for joining us on the call this morning. Last week our former - and well known investor dead to the American oil industry as dead in the water at for multiple quarters of capital starvation and deteriorating rig counts. While we don't agree with the characterization of the industry being dead that should may fit non-tier 1 legacy SCR and mechanical rigs in the US.

We have believed Tier 1 AC drive rigs which constitutes nearly 100% of H&P's fleet and 64% of the working industry fleet today are 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 we're drilling most efficient horizontal wells this appears to be that consensus for you 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 increase right along with efficiency.

H&P has led the way with innovative solutions that have set H&P apart from it's peers particularly and how we have leverage AC drive technology. First by taking ownership by internalizing expertise in the areas of equipment performance capital repairs and we are practical vertical integration. Second providing support services our electrical and mechanical staff enable us to leverage knowledge and life cycle learning of equipment and our performance groups are proactively engage in helping our customers to lower total well cost.

Finally we are committed to a process I will call continues evolution where in house technical resources collaborate with their operational counter parts 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 of our uniform base of existing fluctuate design to provide value for customers.

We have also taken leadership positions in other areas, our many first includes integrating casing rank services, scripting of wells for enhanced reliability and efficiency. Enhanced software controlled capability integrated ---- medication and many other technology solutions that today are standard offerings. The industry is also formed a consensus view that 1500 horse power AC drive Tier 1-- provide the best drilling performance for growing the most challenging horizontal wells. H&Ps fleet has over 30% of the estimated 700 rigs in the U.S. market today that fit that description.

We believe H&Ps rigs are strategically placed and ready to mobilized quickly. Let me use the Permian Basin as a example of strategically placed and ready to mobilize quickly. The Permian by all accounts is the premier basin in the U.S. And some where in our view in the top three of old basins in the world.

No drilling contractor has a stronger Tier 1 footprint there than H&P. Today we have a total of 39 -- rigs on contract in the Permian more than our top three peers combined. Additionally we have over 60 idle --- rigs available with 1500 horse power AC drive capability that are ready to work.

Let me also make the point for already to mobilize quickly. We have made prudent investments in taking great care ideal and maintain the -- rigs properly field tested process is reduced to clean and preserve the equipment and 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 tool and ready to go work.

We often get questions regarding how quickly we can respond to demand with our ideal flee of FlexRigs. We feel very confident we are positioned better to respond in 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 and an improving market, as the result of the mentioned characteristics strategic placement and the ready state of our rig fleet.

In addition to rigs being ready and obvious need and a key advantage in ramping up activity is the availability of quality people. We've done everything in our prior to keep our best people clearly in the 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 by 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 recognized that in the phase of adversity I have been very pleased with our folks response and dealing with the downturn. Our focus had 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 contacts, once again allowed us to report quarterly profits. Nevertheless market conditions continued to deteriorate and drilling activity for the company continued to the decline.

Following our 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 and approximately 22 rigs worked in the spot market. In addition to rigs, there are no longer contracted and became ideal during the quarter several more rigs became ideal that remained 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 contract. This increasing number of rigs with stand by top 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 idol during the quarter. Generating expenses related to personal management and rigs stacking which were then allocated across the 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 then expected as we experience some unfavorable volatility there in the quarter related to different type of expensive 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 contract during the second fiscal quarter. We have an existing notifications for early termination we expect to generate over $80 million during the third fiscal quarter about $20 million during the fourth fiscal quarter and over $40 million there after in earlier termination revenue.

Never the less about 60% of mentioned early termination revenues that we expect to be recognized after the second fiscal quarter 2016. Our attributable to compensation that as of March 31 had already been in voice and collected and that is included in the current liability section of our March 31, 2016 balance sheet as deferred revenue.

We cannot fully recognized the early termination revenue on a rig until all contractual customers option to take that rig back to work at full day rigs have expired. Since the peak in late 2014 we have receive early termination notifications for a total of 87 rigs under long-term contract 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 to a 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 with 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 base. In addition 7 rigs are currently active in the spot market for a total of 79 rigs generating revenue based into segment.

Nevertheless approximately 18% of this 79 rigs are now idle and on stand by type day rates protecting daily cash margins under long term contracts.

Separately the 5 rigs generating revenue and not generating revenue days include new bills rigs with deliveries that have been delayed in exchange for compensation from customers. Looking ahead to the third quarter of fiscal 2016, we expect that 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 contract 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 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 include the impact of relatively high level expenses related to a significant ongoing reductions of fields personnel positions and employee early retirement. Absent any additional early terminations and excluding the mentioned rigs for which we have received early termination notifications this segment currently have 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 saving margins for these rigs that are currently under long term contracts is expected remain strong during the next several quarters as some rigs role off and the remaining new builds are deployed. The average pricing today for the 7 rigs in the stock 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 where 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 7 of our 9 offshore platform rigs generate revenue days during the quarter. The average rigs 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 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 to our international land operations, the second 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 sequentially by approximately 7% to 1,307 days during the same quarter. As of today our international land segment have 14 rigs generating revenue days including 10 in Argentina, 2 in the UAE, 1 in Colombia and 1 in.

All 14 rigs are under long term contacts. 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 dividends payments as previously discussed.

Excluding rigs with long term contract that have already been early terminated and combining all three of our drilling segment, 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 fiscal 2018. Our backlog level of as of March 31, 2016 will rose 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 rates 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 opened it up to Q&A. As you know that U.S. land rig count per day is comparable for the all time record low reached to 1999 and summer comparing this cycle to the 1980's.

Even with the recent old price rebound of $45 a barrel sharp reductions in personal expenses and investment are continuing real life. With the market intelligence we had today we expect to see further deterioration in terms of drilling activity during the third fiscal quarter. That said we are seeing more indication 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 --- rigs back to work.

And now we will open the call for Q&A

 

Question & Answer

 

 

Operator:

Currently at this time if you would like to ask a question you may press star and one on your touch tone phone. Again that's star and one on your touch tone phone. If you think your question has already been answered you may remove yourself from the queue by pressing the pound key. And we will go and take our first question from Dan Boyd with BMO Capital Partners.

Please go ahead your line is open.

 

Daniel Boyd:BMO Capital Partners:

Well thanks guys. You mentioned the advantage of your rigs and the technology that they have you yourself number of competitors that are coming out with the way the greatest rig designs so just I wanted to get your thoughts on your, are you looking to come out with the new rig design and what point do you think you will start increasing investments prepare yourself for the next cycle.

 

John W. Lindsay:

Good morning Dan this is John. Well I think if you look at the investment 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 and an effort to match a lot of rigs that we have out in the field today so, as far as just peer rig designs and I am speaking primarily to the drilling contractors, I am not addressing some of the other rig designs out there described just as futuristic type designs I am seeking more to the contractors today.

We continued to add technology and we have over the past 10 plus years we have continue to have innovations that improve our systems and we are continually upgrading and high grading. So I assure wouldn't want to leave with the impression that we are looking at other designs and other opportunities the facts the matter is I think the industry has all of the Tier 1 type rig assets that are needed the question is which are those asset are going to work obviously we feel very confident that our rig that are one that's going to be most selling after. So we are continuing to invest but I don't any real based on what I have seen I don't see any real breakthroughs in terms of technologies that are being talked about out there.

 

Daniel Boyd:

Okay and then just follow up on last point you made about being able to put rigs back to work. Just a lot moving parts in your daily operating cost but if you were to add an incremental rig can incremental rigs what you thinks a daily operating cost would be for those specific rigs.

 

John W. Lindsay:

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

 

Daniel Boyd:

Okay thanks.

 

Operator:

Thank you and as reminder if you would like ask a question you may press star then one on your touch tone phone. Our next question comes from Angie Sedita with UBS. Please go ahead your line is open.

 

Angie Sedita:UBS:

Thanks good morning guys.

 

John W. Lindsay:

Good morning Angie.

 

Angie Sedita:

So John if you think about and we have talked about this little bit before maybe you could elaborate the potential day rate outlook and a U.S. recovery how you think it could play out some --thing that push per day rate on the initial rigs activated, but I think you said in the past that you thought maybe the first time of rig could be up flat day rates maybe is under pressure some per share and second hundred of rig rate of start to see rates for can you give us the thought?

 

John W. Lindsay:

Yes -- 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 the 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 the spot to speak about there right now there is not a lot of pressure, there is not lot of betting going on. But I think the other thing to keep in mind is in contrast to previous cycles where really every rig out their was out their 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 to look back to the peak activity in October 2014.

So I think it's we distributed it is around 700 rigs or so that 1500 horsepower and of course you're going to have a subset of those rigs that are going to be the top performer that going to have the best equipment and those rig that are going to be the those most start after.

 

Angie Sedita:

Okay, that's helpful and then I guess in conjunction with that is as you think quite through that recovery and you know that number of rigs are in its ready status and if do you think back how quickly you could start to add rigs is people going to be that and how you had any conversations with your E&P's 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 is 45 to 55 range there is been a few E&P's I think recently that I've talked about 50 obviously there is a lot of confidence it has to be made up between now and then really beginning to current rig 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 had great success and past cycles and attracting people back to H&P, we obviously have a lot of experience on the rigs today. So, we know, we have all the drillers and all the skilled positions we would need to be hiring back more jobs related to flow hand 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, only time will tell on that.

 

Angie Sedita:

Okay and one more if I could -- that's really helpful. Could you remind us of the of you FlexRigs and mentioned 700 of the rigs or 1500 horsepower how many of yours FlexRigs rigs is of 1500 horsepower?

 

John W. Lindsay:

323.

 

Angie Sedita:

Okay. Where?

 

John W. Lindsay:

That would be in the US.

 

Angie Sedita:

Okay, great. Wonderful, thanks I'll turn it over.

 

John W. Lindsay:

Angie, I might also mentioned the 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% in the Permian a little lower 30% in the EagleFord 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 position really well.


Angie Sedita:

Okay and then boy you guys are a leading having leading having leading market share in both of those basin correct.

 

John W. Lindsay:

Yes.

 

Angie 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. Corporated. Please go ahead. Your line is open.

 

Matt MariettaL:Stephens Inc.:

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

 

John W. Lindsay:

Good morning Matt.

 

Matt MariettaL:

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 or you seeing defloration and supply or labor is this more of a function of the overall outlook in the active rig count in the fleet may be 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 of lot of the $300 million to $400 million that we previously estimated or related to market conditions and obviously market conditions have been soft even softer than expected and expected to remain relatively soft and so that is driving down some of the maintenance CapEx and also some of the special project that would be in response to a potentially improving market. So it's mostly based on market condition.

 

Matt MariettaL:

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 where we shouldn't think of there being a permanent change there right?

 

John W. Lindsay:

Not really its not a perfect process of course maintenance CapEx depends on a lot of considerations one important point is what rigs we have working if you have mostly new build working new build rigs working rigs that have been build in recent years then your maintenance CapEx will probably be lower and that's part of what we are seeing out there the other considerations relates to a lot of components being available and the exiting fleet that we are trying to as efficient as we can and using that of course before using any deterioration in the field for the lack of use.

 

Matt MariettaL:

Appreciate color on and then my next question here really switching to the international fleet can you may be help us see for long term internationally, can you continue to use South America for example as kind of a relief valve as it relates what's clearly an over saturated US land complex and maybe talk about the appetite for Tier 1 rigs international do you see that changing and evolving your are able to send I think it was 10 to 12 rigs down to South America recently over the last of couple of years what are 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 that kind of that international business for H&P in the longer term do you think?

 

John W. Lindsay:

Yes, Matt this is John. We've talked about this for years and you are right we did have we did send 10 existing FlexRig3s to Argentina few years ago now and we have Flex3s and Colombian 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 the long time that we can have some significant growth internationally as you know that international markets are struggling right now as well.

But we do see the current fleet that we have in the US being able expand internationally when those opportunities arise. We keep thinking that it will be growth in the international area in terms of unconventional resource place and really that's what 10 rigs growth in Argentina for the Flex3 that's what that was all about and so hopefully we will see that happen I think there is nobody better position and H&P and to advantage of that as you know we've been working internationally for over 50 years so we have lot of experience and capabilities. So we're just waiting for those opportunities.

 

Matt MariettaL:

I appreciate that and do you think that is if you look in the Middle East as may be an area where you could deploy more assets is there hunger for more rig contractors to entering to the market or can you maybe help us understand the competitive landscape how difficult to this to break into certain territories I guess in the greater scale is already there is kind of my last question here and I will hop back in the queue.

 

John W. Lindsay:

Sure. Well I don't think there is any doubt that having a footprint there is advantageous we have got a couple of factories in UEA and we have Flex force 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 sides right now in terms of opportunities, but we believe that there will be opportunities in the future.

 

Matt MariettaL:

Thanks a lot.

 

John W. Lindsay:

Thank you.

 

Operator:

Thank you and just to reminder to participants if you would like to ask a question you may press star and one on your touched tone phone. Our next question comes from Marc Bianchi with Cowen. Please go ahead. Your line is open.

 

Marc Bianchi:Cowen and Company:

Hey good morning. Just looking at the guidance here for the upcoming quarter, it seems like to 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 larger proportion being long term contract can you speak to that please.

 

Juan Pablo Tardio:

Sure Marc this is Juan Pablo. There are at least to couple of things that are contributing to an unfavorable move and the first one have to do with the growing proportion of idle rigs and expenses associated with those idle rigs. Some of those expenses are fixed, some relates to the process that we are going through the transition as rig become idle as you know there are stacking expenses there are personnel expenses, that we incur and so that impact the average unfavorably. We also have a couple of other things going on one is related to a higher than the normal number of personal positioned in the field and early retirements related to employee.

So that's what is impacting the average rig margin 30,800 that we've guided towards 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 you mentioned the personal cost there that maybe perhaps one time is there any piece of this that we can think of this one in your fiscal third that won't be in the fourth.

 

John W. Lindsay:

Well it all depends on what levels of transition we see in the fourth fiscal quarter. Obviously when we have transitions like this all of those expenses we believe are specific through the quarter and hopefully are non-recurring but unfortunately we have been going through this quarter-after-quarter during the third fiscal quarter we expect a very significant decline as mentioned those 25% to 28% and when that happens those expenses that's pertains 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. Yes one clarification I may have related to a margin guidance that ---- I was referring to the average rig expense being --- as we spoke earlier about but let me stop there does that answer your question Marc.

 

Marc Bianchi:

Yes that's helpful on Pablo I guess may be related is has there been any adjustment in any of the contracted rates that you have?

 

Juan Pablo Tardio:

Not significant as we mentioned these some of these rigs are being are becoming idle and we are charging day rates that protect us in terms of expected margin for those rigs but nothing significant is going on in terms of what we expect to at seeing from a long term contracts.

 

Marc Bianchi:

Got it. Okay.

 

John W. Lindsay:

Hey Mark this is John. I wanted also clarify make certain that. The guys in the filed have really done an excellent job we talked about on the last call that related to expenses and really managing that in a really strong way that and so this cost increase really has nothing to do with the rig itself as I had mentioned before and we were leadership team was in Permian Basin a couple of weeks ago and it would 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 Pablo had when Pablo address that's really what's driving the cost it's not the actual expenses that the rig side.

 

Marc Bianchi:

Got it. Okay. Thanks John and if I could just one more for one 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 that you think that on a quarterly basis it's going to tick up your in the back half?

 

Juan Pablo Tardio:

It may there are some variable that impact that hopefully we'll see a number for the year that is lower than the 580 but we don't 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

 

Operator:

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

 

Daniel John:Simmons & Company:

hey guys couple of things for how you are

 

John W. Lindsay:

alright thanks

 

Daniel John:

Okay. First question just based on inbound and commercial clients do you believe that revenue days will increase in the fourth fiscal quarter or was the current quarter?

 

John W. Lindsay:

John there is not lot of unfortunately there is not lot of inbound calls and I think if we were to make an answer based on oil prices would remain 45 plus and I think you could see some confidence in the market I could begin to potential see some rig go back to work. But as you know we all separate through witness last summer when oil prices were in the 55 to 60 range and then pulled 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 surprise to see rigs going back in the fourth quarter, but at this stage we shouldn't receiving a lot of calls.

 

Daniel John:

Okay you did mentioned I think the fiscal Q3 cost per day guidance does include some right sizing costs if seem to me that you're not expecting the short recovery at this point 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 can 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 give resented and rigs don't actually give released and rig better on standby would go back to work and then ultimately you begin to see some rigs being picked up in the spot market. So that can happen it just we just haven't seen it begin at this stage.

 

Daniel John:

Just one final one for me and I will turn over I am trying just better understand the whole impact of drilling efficiencies and how that will impact the recovery and the rig count just on that point when you release customers and they share with you there rig count needs going forward just assume on the higher commodity price deck that they provide any color to you about what their peak potential rig count maybe and if so how does that compared with what they have been in most recent peak rig count.

 

Juan Pablo Tardio:

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

 

Daniel John:

All right. Thanks guys.

 

John W. Lindsay:

Thank you.

 

Operator:

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

 

Michael Lamotte:Guggenheim Securities, LL

Thanks. Good morning guys. May be I can start with just sort of the inverse of Angy's question which is how much of the fleet day is a thousand horse power?

 

John W. Lindsay:

We take a look at it.

 

Michael Lamotte:

Okay and with all the emphasis on the 1,500 what is the outlook for the thousands.?

 

John W. Lindsay:

I think we have around 22 rigs that are thousand horse. Those rigs are typically designed for more vertical shallower type work we actually have that particular model reflects for working in Colombia and Argentina and in the Middle East actually I am not certain the one's in Argentina working right now but in any event we have those rigs, and those rigs are candidates to work internationally there obviously candidates to go back to work in the Permian Basin because that's were most if not all of those of rigs -- for that's the vertical work not for horizontal work.

 

Michael Lamotte:

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

 

John W. Lindsay:

I should don't think so again those rigs are have worked recently and I think that vertical that 8,000 to 12,000 vertical type work in some of the Basins in the U.S. And as well internationally are going be an existent.

 

Michael Lamotte:

Okay on reactivations like to see in terms of term I mean which you are going to have the -- and spend some money to gear up I imagine you are not going to do that for a well type work.

 

John W. Lindsay:

Well Michael I think for anyway to expect that you are going to get term work coming off lot 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's not high cost. So I don't see that is being stretch and we won't be going in more likely you are going just drill one well I mean unless commodity environment were to begin to pull back again you are going to drill multiple wells.

So I'd be surprise to see many of these rigs going back to work with term contract commitments.

 

Michael Lamotte:

Okay so the decision to reactivate really is the 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 on 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 than that's a beneficial for us and beneficial for customers beneficial for our employees. sure and understand that I just mean the decision to activate whether it's really customer driven or you anticipating customer activity.

 

John W. Lindsay:

Well yes, when 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 other so yes we're going to be there be there for them and we ready to respond.

 

Michael Lamotte:

Okay, great. Thanks, guys.

 

Operator:

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

 

Robin Shoemaker:KeyBanc Capital Markets:

okay good morning. Wanted to could most my questions have been answered but I wanted to ask you about the status of the facility that you have in Houston which are you assemble and refurbish rigs and just some of the way it looks I think you had a little bit of backlog of maybe three or four rigs to be yet to be build that you've deferred. But what roll might that play in going forward it seems like it would be 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:

Yes, Robin this is John. The facility you are right don't expect to be building a new rig any time soon. We have a utilized that facility you touched on refurbishing we have utilize that facility to refurbish rigs getting them ready for international work that we have also use that facility for certain upgrades that we've done into our rigs fleet and so that's part of the way that up to this point in addition to finishing out those new builds 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 so but we will continue to keep an eye on that.

But that's how we would utilize that facility in other facilities is to upgrade and high grade the fleet.

 

Robin Shoemaker:

And was the remaining kind of backlog of new bills that you had has that been switch to like existing rigs that are available or....

 

Juan Pablo Tardio:

We have Robin this Juan Pablo. We have a couple or three rigs that are pending delivery. So those are 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 rate that already have long term contract associated with them, there are no plans for other new bills at this break.

 

Robin Shoemaker:

Okay, alright. Thank you.

 

Juan Pablo Tardio:

All right, Robin. Thanks.

 

Operator:

Thank you and just a remind to participants if you would like to ask a question you may press star and one on your touched tone phone. Our next question comes from Mark Close with Oppenheimer & Close. Please go ahead. Your line is open.

 

Mark Close:Oppenheimer & Close:

Good morning gentlemen. One total just a clarify on that CapEx the delayed new builds how much of that is ncluded I mean we are looking at I guess CapEx for the year ahead excuse for the back half of the year of 120 to 170. How much if any of that includes those delayed new builds and how much of that how was be 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 assort during the first two quarters and I have to double check on that. So remind me just second part of your question Mark.

 

Mark Close:

So if you got new build set have didn't 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. We typically depreciate our rigs once they operations and so the delayed rigs have not yet began depreciation from a financial perspective.

 

Mark Close:

Okay. Thank you.

 

Juan Pablo Tardio:

And still 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 Close:

Right thanks. Okay thanks.

 

Juan Pablo Tardio:

Thank you, Mark.

 

Operator:

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

 

Tom Curran:FBR Capital:

Good morning, guys.. Thanks for squeezing me in I'll try to be quick most of my questions have been answered. Just a few, a fleet expect once. John could you tell us of your 1500 horsepower FlexRig segment what percentage of those have three month pumps and 7500 PSI capability?

 

John W. Lindsay:

Tom we haven't publish that I know is that number continues to grow. We haven't publish that of to this point. So it's probably. Yes Tom we don't have sort of quite like that. Again it's 30% to 40% of our fleet but not all rigs that have 7500 also have 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's not as easy to flash ---

 

Tom Curran:

Understood John but that 30% to 40% rough estimate with that apply to the 1500 horsepower FlexRigs or total US rigs fleet

 

John W. Lindsay:

I believe the 1,500 horse power.

 

Tom 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 as upgrade, is it to the extent you're doing is it still just adding skidding systems to fluctuate ---- 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 have we've continue to upgrade the fleet to 7,500 on those that have 5,000 when the customer needs it we have added third mud pumps, we have added fourth engines, we have increased set back capacity on the rigs in order to handle lot of the rigs already have the capacity for 25,000 for the set back but not all of them do and so we are upgrading that there is various I kind of addressed a little bit of that in my prepared remarks that we we've continue to do that overtime and we're doing that in this cycle as well.

 

Tom Curran:

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.?

 

John W. Lindsay:

I don't think we have nailed it down to that Tom I mean it's a -- it's not a it's not a huge percentage I don't know that we've updated

 

Juan Pablo Tardio:

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

 

Tom Curran:

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

 

John W. Lindsay:

Sure Tom thanks. Thank you and --- we have time for one more question please.

 

Operator:

okay perfect we will go ahead and take our last question from Darren Gacicia. Please go ahead your line is open.

 

Darren Gacicia: KLR Group:

Hey thank you very much for -- at the end. My question is around rig margins and that progression that may take recovery. I realize I think you said the spot day rates in the --- around 13% I think you said over the course of the call that most of the rigs that they are going to work --- of a recovery will come from the spot. So I think about that seems to tell that even as you recover you day rates you average margins come down I guess the question really lies into the ---- thinking about the what the absorption offset is from a fixed cost perspective and just had a --- I realize you guys have taken a fairly conservative tax on the call but I'm just trying to sensitivity from process and how to think about that model.

 

Juan Pablo Tardio:

Yes Dan this is Juan Pablo. There are so many moving pieces that and I would has to say even start outlining those because there is not just one or two that I could I mention that, that would bring clarity to that I think your overall assumptions is true obviously were 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 relates 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 had a higher proportion of rig in the spot market going forward assuming of course that recovery. The only other fact that I mentioned is what John already mentioned and that is that as we put rigs back to work and then total number idle rigs begins to decline that in general will have a favorable impact on margins as some of those fixed cost related to the idle fleet we will start to reabsorbed. But I am sorry not to be able to provide more clarity, but hopefully that helps.

 

Darren Gacicia:

But maybe--- in terms of the margin degradation we have seen so far is there any way to kind of get a sense of that and what part of its been absorption and what part of that is --.

 

Juan Pablo Tardio:

Darren I am not sure that I understand your question. Could you replay this please.

 

Darren Gacicia:

Well big of this a pricing declines may roll through and that should impact margin line directly than there is kind of an absorption part of it. So is there way to think about things on the pricing versus absorption in terms of we have already seen.

 

Juan Pablo Tardio:

Not a simple straight forward way Darren I think pricing well depend the average rig revenue per day will be impacted by any by the proportional rates that are on standby and that significantly lower day rates as we don't the rigs working and what proportion that makes up in terms of the total, but that's one more moving piece as we go forward. I think what maybe an important part of the question is related the rigs that we already have under term contacts and what those margins might be and the answer to that is that the margins to the rigs that are under term contract that are currently operating or that are on standby type day rates. Those are as strong as we expected. We have not seeing 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 in way that 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 will turn it back to John Lindsay for some closing remarks.

 

John W. Lindsay:

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 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 and 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 phase of this adversity and their dedication to the company through these difficult times. And again thank you for listening and with us this morning and have a great day.

 

Operator:

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

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