Helmerich and Payne Inc (HP) 2015 Q4 法說會逐字稿

Good day, everyone, and welcome to today's program. (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 and welcome, everyone, to Helmerich & Payne's conference call and webcast corresponding to the fourth-quarter and fiscal year-end of 2015. 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 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. At the time of our last call in July the industry rig count was nearing the low levels reached during the 2009 recession and we were witnessing a second round of declining oil prices and increased volatility. The question on everyone's mind then was are things going to get worse from here. We know that the fundamentals have continued to deteriorate and today US land drilling activity is at the lowest level since January of 2003.

For many the major theme across the industry is survival. Service pricing continues to decline and this has led to sharp reductions in personnel, expenses and investments across the board. While no company is immune to these conditions, fortunately a cornerstone of our strategy has always been fiscal conservatism. Our strong balance sheet and long-term contract coverage continues to serve us well.

We also believe our advanced rig fleet, strong customer base and best-in-class reputation for customer service and value creation position us very well in this difficult environment. In many respects this downturn has been indiscriminate of rig quality as evidenced by the number of Tier 1 rigs on the sideline. Even with some of the best rigs idle there is still evidence the replacement cycle is ongoing.

A year ago approximately 41% of the active rigs were AC drive, and today approximately 58% of the active rigs in the US are AC drive rigs with the remaining 42% of the active rigs made up of a legacy fleet of SCR and mechanical rigs that continue to be less relevant as the cycle wears on.

H&P's fleet profile is a competitive advantage as it allows the Company to provide a family of solutions for customers. We provide FlexRigs that are suited for a wide range of well configurations and well complexities for customers today.

Perhaps more importantly, we believe our fleet provides what customers will need in the future. We have over 340 AC drive rigs in the US market, including more than 310 FlexRigs rated at 1,500 horsepower, the optimal horsepower for the more difficult and complex horizontal extended reach laterals being drilled today.

Over 180 FlexRigs are pad capable for multi-well locations and many of those rigs have additional capability like 7,500 psi pump systems. Our ability to design and build means that any FlexRig in our fleet is a candidate for an upgrade to meet a customer's needs. We have a long history of innovating during down cycles and having customers reward those efforts as conditions improve. That commitment to design and innovation continues to be a focus in this difficult downturn.

Another competitive advantage is the organizational infrastructure that we have built over the past 10 years. This infrastructure allows us to leverage the learnings we capture from the fleet and to partner with customers to provide greater efficiencies, reliability and safety, all aimed at drilling the lowest cost well for that customer and maximizing the number of wells they can deliver in a budget year.

We've extended these advantages to international markets and will continue to push to expand our footprint. In short, we believe that our people, our fleet profile and our systems are unmatched in the industry.

To summarize, we are in the midst of a very challenging market. Our efforts will remain focused on adding shareholder value by prudently allocating capital to provide innovative solutions that help our customers reduce their total cost and be more competitive in the global market. With that I will turn the call back over to Juan Pablo.

Thank you, John. The Company reported $422 million in net income for fiscal 2015 compared to $709 million for fiscal 2014. The average annual level of drilling activity for the Company declined by over 20%, but the decline is closer to 50% when we compare this fourth fiscal quarter for fiscal 2015, that is, with last year's fourth fiscal quarter.

This of course is the result of a market environment that, as John mentioned, presents serious challenges in terms of generating earnings for our shareholders as reflected in our fourth fiscal quarter results. Following are some comments on each of our drilling segments.

Our US land drilling operations generated approximately $64 million in segment operating income during the fourth fiscal quarter excluding abandonment charges related to old SCR rigs. The number of quarterly revenue days declined by a little over 5% as compared to the prior quarter, resulting in an average of approximately 147 rigs generating revenue days during the fourth fiscal quarter. On average approximately 118 of these rigs were under term contracts and approximately 29 rigs worked in the spot market.

Excluding the impact of early termination revenues the average rig revenue per day slightly decreased to $26,218 in the fourth fiscal quarter. And the average rig expense per day decreased to $13,823, resulting in an average rig margin per day of $12,395 in the fourth fiscal quarter.

The decline in average rig revenue per day was again attributable to softer market conditions. The decrease in the average rig expense per day was primarily a result of a reducing volume of rigs becoming idle and requiring attention as compared to the prior quarter.

During the quarter the segment generated approximately $33 million in revenues corresponding to early termination of long-term contracts. Given existing notifications for early terminations we expect to generate about $13 million during the first fiscal quarter, about $45 million during the remaining three quarters of fiscal 2016, and over $10 million thereafter in early termination revenues.

Since November of last year, and excluding some rigs working for customers that decided not to early terminate the contracts as per prior written notice to us, we have received early termination notifications for a total of 60 rigs under long-term contracts in the segment.

Total early termination revenues related to these 60 contracts are now estimated at over $270 million, approximately $88 million of which corresponds to cash flow previously expected to be generated through normal operations during fiscal 2015, $123 million during fiscal 2016 and $62 million after that.

As of today our 344 available rigs in the US land segment include approximately 132 rigs generating revenue and 212 idle rigs. Included in the 132 rigs generating revenue are 108 rigs under term contracts, 104 of which are generating revenue days. In addition, 24 rigs are currently active in the spot market for a total of 128 rigs generating revenue days in the segment.

Some rigs that generate revenue days are on standby type day rates. Rigs generating revenue and not generating revenue days include four new build rigs with deliveries that have been delayed in exchange for compensation from customers.

Looking ahead to the first quarter of fiscal 2016, we expect revenue days to decrease by about 11% to 14% quarter to quarter. Excluding the impact of revenues corresponding to early terminated long-term contracts, we expect our average rig revenue per day to slightly decline to roughly $26,000. The average rig expense per day level is expected to also decline to roughly $13,600.

Subject to additional early terminations, and excluding rigs that we have received early termination notifications for, the segment already has term contract commitments in place for an average of approximately 107 rigs during the first fiscal quarter -- let me repeat that, 107 rigs during the first fiscal quarter -- and an average of about 102 rigs and 77 rigs during all of fiscal 2016 and fiscal 2017 respectively.

Some of the mutually beneficial negotiations of long-term contracts that resulted in reduced day rates in exchange for additional term durations at fully priced levels have now transitioned back to those fully priced levels. As a result the average pricing per rigs that are already under term contracts is expected to slightly increase and remain strong during the next several quarters as some rigs roll off and new builds are deployed.

The average pricing for H&P rigs in the spot market declined by approximately 5% from the third to the fourth quarter of fiscal 2015 and is expected to continue to at least slightly decline during the first fiscal quarter. Average spot pricing today is over 30% lower as compared to spot pricing at the peak last November.

Let me now transition to our offshore operations. Segment operating income declined to approximately $12 million from $15 million during the prior quarter. Total revenue days slightly increased but the average rig margin per day declined from $14,265 to $13,296 per day during the fourth fiscal quarter.

As we look at the first quarter of fiscal 2016, we expect revenue days to be relatively flat and the average rig margin per day to decline to approximately $9,500 during the quarter. The expected average rig margin decline is primarily attributable to most rigs not performing operations and simply generating relatively low margins under standby type day rates.

Management contracts on platform rates continued to favorably contribute to our offshore segment operating income. Their contribution during the fourth fiscal quarter was approximately $7 million, but that is now expected to decline to approximately $3 million during the following quarters given that customers suspended a couple of projects.

Moving on to our International Land operations. The segment experienced a significant operating loss of $38 million during the fourth fiscal quarter primarily as a result of non-cash impairment charges of approximately $39 million related to several conventional land rigs and approximately $5 million in charges related to an allowance for doubtful accounts associated with customers that we are no longer working for. These charges were partly offset by early contract termination compensation of approximately $9 million during the quarter.

Excluding the impact of $4,658 per day and $5,535 corresponding to early contract termination compensation during the third and fourth quarters respectively, as well as the impact of $3,021 per day corresponding to charges related to the allowance for doubtful accounts during the fourth fiscal quarter, the average rig margin per day decreased sequentially from $13,086 to $7,856 per day.

The decline, as expected, was influenced by expenses corresponding to several rigs that became idle and to 2 rigs that were demobilized out of Tunisia. The decline was also attributable to day rate adjustments for 2 active rigs that rolled off long-term contracts. Revenue days sequentially decreased by approximately 12% to an average of about 18 active rigs during the fourth fiscal quarter.

As of today our International Land segment has 16 active rigs, including 11 in Argentina, 2 in the UAE, 1 in Colombia, 1 in Ecuador and 1 in Bahrain. 14 of the 16 active rigs are under long-term contracts. 22 rigs are idle including 8 in Argentina, 7 in Colombia, 5 in Ecuador and 2 in Bahrain.

We expect International Land quarterly revenue days to be down with an average of approximately 15 rigs active during the first quarter of fiscal 2016. The average rig margin per day is expected to slightly increase to close to $8,000 per day and no early termination revenues are expected during the first fiscal quarter in the segment.

Let me now comment on corporate level details. Our liquidity position remains very strong and we expect no change to our regular dividend dollar per share levels in the foreseeable future. We reported capital expenditures of slightly over $1.1 billion for fiscal 2015, well below our $1.3 billion estimate for the year.

Although almost half of the reductions relate to timing differences of spending that moved to fiscal 2016, we were pleased to see the effect of several capital preservation initiatives result in reduced spending during fiscal 2015. Including the spending that moved from fiscal 2015 to fiscal 2016, we expect capital expenditures for fiscal 2016 to be in the range of $300 million to $400 million.

Roughly 70% to 80% of this spending estimate includes the remaining commitments related to our new build program and other special projects mostly related to the further enhancement of our existing fleet. The remaining 20% to 30% of the spending estimate is related to maintenance CapEx and other miscellaneous items.

Our FlexRig construction cadence plan remains generally the same with 6 new FlexRigs to be completed between now and the end of March of 2016. As has been the case with over 330 new AC drive FlexRigs on average over the last decade or so, every new rig that we are scheduled to complete is sponsored with a three-year term contract that is expected to generate an after-tax payback of close to 90% during the duration of the contracted term.

Including these remaining contracts and combining all three of our drilling segments we have an average of 118 rigs under term contracts to be active in fiscal 2016, 93 in fiscal 2017, and 52 in fiscal 2018.

Given the soft market conditions and the mentioned early termination of long-term contracts, our backlog decreased from approximately $3.5 billion as of June 30, 2015 to approximately $3.1 billion as of September 30, 2015. 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.

Interest expense after capitalized interest is expected to be approximately $25 million for fiscal 2016. The effective income tax rate for fiscal 2015 was 36.6%, which was higher than originally expected as a result of adjustments mostly related to foreign taxes. The effective tax rate for fiscal 2016 is expected to be approximately 36%.

Our noncurrent deferred income tax liability as of September 30, 2015 was slightly under $1.3 billion, which is lower than previously expected as a result of non-cash adjustments related to abandonment and impairment charges and to the lower market pricing of our holdings of investment securities. We expect this liability level to remain in the range of $1.2 billion to $1.4 billion during the next couple of years. With that let me turn the call back to John.

Thank you, Juan Pablo, and before opening the call to questions I want to reemphasize our 2015 fiscal year has been a very challenging year, but even the most difficult of market conditions will provide opportunities. As the industry's high-grade process moves forward our ability to respond with the right rig, the best people and in a timely and efficient manner will position the Company for more opportunities and will ultimately allow us to provide greater value to customers.

Finally, I want to thank our employees and management teams for stepping up to the challenges that we have faced, embracing change in a positive way and responding in a remarkable fashion. We aren't finished with the work at hand. In fact, we won't ever be finished, it is a long march and I truly appreciate everyone for contributing to the efforts. And, Tanisha, we will now open the call for questions.

(Operator Instructions). Dan Boyd, BMO Capital Markets.

Your margins are actually holding in quite nicely. The one thing I wanted to ask about is in the spot market where there just seems to be a part of confusion on where rigs are being priced. But if I am doing the math correctly, the 25 rigs that you have in the spot market, is it correct that they are working at just under $20,000 a day?

Dan, this is Juan Pablo. I think that is a fair assumption.

And so, just so I understand --.

High teens in general would be our description.

Okay. So despite these tough market conditions you are actually still able to reprice in this current market at that rate, correct?

Dan, this is John. That is where our spot market pricing has been averaging. But clearly as this market has moved forward, I mean they are higher, high teens but they are in a range, $17,000 to $18,000. It is job specific, area specific. But clearly with oil pricing in the range that it has been, there is not any -- number one, there is not much of a spot market out there to compete in, but that is kind of the average pricing that we have been seeing.

Okay, thanks. And can you just give us some -- you still have a number of rigs on term contracts internationally and I believe a bunch of those are from -- in Argentina where you had some nice contract awards I think about a year ago. Can you just give us some color on the roll off schedule over the next fiscal year and how margins might progress? Because I believe those contracts were also at pretty attractive margins.

I will mention that the Argentina contracts were -- those 10 rigs were five-year term contracts. I think Juan Pablo has more details on the overall International fleet.

Sure. Dan, if you take a look at the next four years for International and determine what is the average number of rigs that we already have under term contract for those following years, the numbers would be respectively beginning from fiscal 2016 through fiscal 2019, 14 rigs, 13.2 rigs, 11.8 rigs and 10 rigs. Of course, as John mentioned, the base of that is -- represents the rigs that we have active in Argentina.

Yes, thanks. And then just last one, just how low are you willing to take the cash balance to maintain the current dividend?

Dan, this is Juan Pablo. We fortunately don't have to be worried about that at this point. As you can see, our level of liquidity is very high. We prefer to have a high level of liquidity over downturns, as we have mentioned in the past. We will just continue to monitor the cycle and make decisions as we go. But at this point, as we have said, we do believe that we are in a position to sustain the current dividend levels.

Okay, thank you.

Scott Gruber, Citigroup.

My back of the envelope math points to somewhere around $150 million in CapEx associated with upgrades, is that in the ballpark?

This is Juan Pablo. Scott, we are not providing that level of detail. I think that we have provided a broad range of $300 million to $400 million, a lot of that will be determined by market conditions and opportunities as they emerge. So, a lot of moving parts and can't give you a specific number on that.

That is fair. Is the upgrade portion though a primary driver of the delta between the low end and the high end?

Scott, this is John. There is a portion of that; there is also a portion related to just maintenance CapEx in general. As Juan Pablo said, there is a wide range of potential outcomes in terms of activity for 2016. And so, that is the reason for the broad range in the CapEx.

Got it. And how much of the planned upgrade spending is on active rigs versus idle rigs?

That is a hard one to nail. Obviously that is going to be a function of the type of environment that we see. I mean, the fact is we have very capable rigs that are sidelined right now that don't require any sort of an upgrade. But again, there is 7,500 psi, there is third mud pump, there is just other upgrade opportunities that we have as customers begin to exploit these -- some of these unconventional resources maybe in a little bit different way.

So, not a lot more color we can add to that. But it would probably be a little bit of an all of the above. I think we would probably have some upgrades for both rigs that are working and then, assuming that we were able to continue to take market share going forward, it would also be some rigs that would be coming out of idle condition.

And one last one. Earlier in the year you were performing some maintenance on the idle rigs in order to keep them ready for reactivation, this was leading to a bit of a rise in your daily OpEx. You guided for $13,600 which is down quarter on quarter. Where do you stand with this strategy in terms of spending some money to keep the rigs ready to try to take some share as -- when we see an inflection in demand?

Well, your description of maintaining, I mean it was -- mostly it was preservation. I think historically the industry hasn't done a great job related to when you idle a rig and performing some of the preservation that needs to happen and actually idling the rig in the proper fashion. And in a lot of cases because a lot of the expectation would be, well the rig is going to go to work in the next month or so.

So there was some additional costs upfront on that. Clearly there is some ongoing cost associated, some of it as a fixed cost that we really don't have much control over. That is most of the cost that you see today. I think we are in a really good position with the fleet status in that we are ready to go back to work at a moment's notice and we could put rigs back to work very quickly and I think at a fairly low cost.

Got it, appreciate the color.

Waqar Syed, Goldman Sachs.

If I heard you correctly there is about 128 rigs that are generating revenue days currently?

In the US land segment, yes, Waqar.

In the US land segment, yes, okay. And so -- and you are guiding to about 126 for the December quarter. So the exit rate in the December quarter you think is what -- 124 to 125, in that kind of range?

I am not sure what your assumption was to come up with 126. We provided a wide range of 11% to 14% decline, you may have taken the highest number there. I am not sure how you got to that number. But I think in general terms it is probably fair to assume that the number of rigs that we have active or generating revenue days, as you described it, 128, that is probably going to be flat to slightly down through the remainder of the quarter.

That is good, that is interesting. Now we hear a lot about industry just dropping rigs post-Thanksgiving and then sharp decline in the December timeframe. You generally get the first indication of the plans. Do you hear that -- what are your clients telling you about post-Thanksgiving activity for them?

Waqar, this is John. We don't have that indication. I have heard and read some of the same that you have described. At this stage we are not getting that indicator from our customer base. We have been successful on a few -- putting a few rigs to work. Our hope is that we could continue to have some -- put a couple rigs to work during the rest of the quarter.

But I think in general what Juan Pablo said is right on track. It is rig count flat to slightly down. But we don't see a dramatic reduction based on what we have heard right now in our rig count. I do, however, think that there are continuing to be other rigs that are in the industry that are on term contracts that are rolling off. And so, that could have an impact.

I think there is also obviously this possibility of customers just running out of budget dollars due to the low oil price environment. So, we have heard some of the same thing. We don't see it with our -- fortunately we don't see it with our customers at this stage, but I know that is definitely a possibility.

Okay. And then is it still too early or what are you hearing from your customers regarding the March quarter or first calendar year quarter, what the plans are? Do you expect the rig count to bottom around December then start picking up in the March quarter? Or you think the bottom is more likely to be sometimes in the first quarter or second quarters?

Yes, we sure don't have a good feel on that other than, again, just talking with our customers. Again, it is too early to call right now, but our hope would be that we would at least be able to maintain our activity set that we have today going into at least the first part of the first calendar quarter of 2016.

But of course that is not what we are hearing; we are hearing that overall the rig count, a lot of folks are expecting it to continue to decline. And again, back on the point I made earlier, we know there are rigs that are going to continue to roll off of term contracts in the industry. And our sense is that rollover rate seems to be gaining a little bit of steam.

So, it is hard to say. I mean, we don't know the answer to it. We sure don't see any indicators that it is going to bottom out and then respond and start going back in the other direction at this point -- not at $42, $43, $45 oil pricing.

Okay. And you mentioned that a subset of your rigs, AC rigs have 1,500 horsepower and 7,500 psi equipment. What is that number and what is the utilization of that fleet or otherwise how many rigs -- [such] rigs are idle right now?

Off of the top of my head, I don't know if you have --.

I am not sure if I follow your question, but let me give it a try in terms of answering at least part of it. We have over 180 rigs in the US Land segment that are pad capable and about 88 of those are active or contracted. So that represents close to a 50% utilization. As it relates to rigs equipped with 7,500 psi systems, several of those or a good number of those do have those systems. I can't give you a number right now, I don't have that.

Does that answer your question (multiple speakers)?

I was just looking -- I was interested in the utilization of such rigs that have 7,500 psi systems on them.

Yes, we have -- I think there's a few 7,500 psi systems on rigs that are idle. I think the majority of the 7,500 systems are active today. And we continue to high-grade rigs to 7,500 psi systems where needed. The fact is there is -- not all basins need 7,500, not all customers within the same basin require 7,500. It is a little bit of a mixed bag.

But as I described in my comments, that is one of the significant advantages that we have is this ability to add upgrade kits, if you will, to FlexRigs both rigs that are working as well as rigs that are idle that could respond to needs. I mean we are still seeing examples of high grading where we are putting rigs to work for customers and that rig is high grading or replacing competitors' older rigs or underperforming rigs. So that continues to be an opportunity for us.

In your International business you guided to about $8,000 a day margin. I suspect some of that margin decline has to do with extra costs that you are carrying as you maybe stack some equipment. Can we go back to kind of more normal kind of margins, even if the rig count doesn't go up internationally? And when can that happen and what is that kind of [normal] kind of margin?

Waqar, this is Juan Pablo, yes, you make a good point. When you have that many number or that number of idle rigs it does represent a burden. But in addition to that, we are down to I believe five countries where we are active and three of those only have one rig that is active.

And that -- the basic cost of maintaining an operation in a particular country is something that does impact the average rig revenue and average rig expense -- pardon me, the average rig expense per day, not the rig revenue per day. And of course the margin per day.

So going -- having a significant impact on that, while we can't spread those fixed costs, so to speak, among a larger number of rigs is challenging, we are certainly looking at ways to try to be more cost effective internationally, as you can imagine.

So, is $8,000 a day margin -- is that a good run rate then? Or where can we go up to like -- or is it still, this potential to still come down as we go into the March and June quarters?

As always, Waqar, that will depend on market conditions. If market conditions remain the same I think that is a fair assumption. But as we know, we are in very volatile times and hopefully we will have much better news in the following quarters if we see a recovery. But it is tough to tell at this point.

Waqar, we are obviously spending a lot of time and effort on this. And as Juan Pablo just said, we will have more to report and we will be more clear here in the coming month or so into the next quarter.

Great. And then just one last quick question. Do you expect working capital to be a source of funds going forward as well in the next -- let's say next fiscal year as well, like it has been this year?

It certainly has been a very significant source of funds over the downturn. Going forward it all depends on what happens in the market. It is going to be interesting to see that. But nonetheless, we don't expect that to be a driver in terms of liquidity for us and our ability to remain very strong in that regard going forward. And of course as we mentioned before, the ability of the Company to sustain the dividend we believe is very strong at least for the foreseeable future.

Thank you very much.

Rob MacKenzie, Iberia Capital.

John, I wanted to come back to some of your prepared remarks on -- and [good at that] on your historical propensity to innovate during cyclical downturns and being rewarded for that. Yet your CapEx budget doesn't seem to include anything along those lines this quarter. Can you give us some ideas to what you are thinking about and where that might take H&P?

Well, Rob, it is -- really it is an ongoing effort at the Company. We have -- it is a big part of our culture. We continue to work on a lot of things, most of which we are not going to go into any great detail and talk about it. But I can tell you there is a lot of things related to the organization, related to rig equipment and upgrades and just generally working on continuing this value proposition for customers.

So we are obviously working with customers on various things and trying to figure out how we are going to continue to provide the greatest performance possible in the safest way possible for our customers. So we obviously are spending a lot of time and effort on that.

I wouldn't -- if you think about what has really driven our CapEx over time is when we are building a lot of new builds. And of course last year we built -- we were building four rigs per month. And so, that was really what drove that initial, what, $1.3 billion CapEx. So you shouldn't see that CapEx range being something that is messaging that we are not investing in the business and we are not innovating.

Great, thank you. I will turn it back.

Robin Shoemaker, KeyBanc Capital Markets.

So Juan Pablo and John, I think you mentioned at the early part of your remarks that the AC drive now accounts for 58% of active rigs. And given how much the rates for Tier 1 rigs have come down, AC drive rigs have come down, and I'm sure that the differential -- pricing differential with Tier 2, 3 and 4 rigs has narrowed very substantially.

It is a little surprising that there is really still some lower tier rigs in the market. And just wonder from your perspective kind of what would account for that since -- or am I correct that the pricing differential has narrowed significantly from a year ago?

No, Rob, I think your sense is right. There is no doubt that the pricing differential has narrowed. I think a portion of those -- of the legacy fleet that is working -- of course we don't have any rigs in that category so we don't know the contractual situation. But our assumption is there is a portion of those rigs that are under term contract. And so, I think over time we could probably expect to see some of those rigs roll off.

And so, I think our expectation would be going forward is you are going to continue to see the legacy fleet being replaced by AC drive rigs. And obviously our vote would be FlexRigs. And we are going to see that happen over time.

You have heard us say this over and over for several years and that is these rigs are working harder than they ever have, they are delivering at a higher level of performance than rigs ever have, the cycle times are increasing dramatically. And that puts a lot of pressure on that older legacy fleet design. And so again, I think over time that will happen.

The question will be what about the pricing. But we have heard this for years. There is a level, you can't reduce the day rate low enough on that older legacy fleet in many cases to be able to save money for the customer. I mean at the end of the day it ends up costing the customer to go with that older rig fleet.

So I think over time we are going to continue to see replacement cycle play out, kind of like what we have described. And you look back over the last five years you can see it happening.

Yes, I would agree. Okay, thank you. So just one other question and it just relates to Juan Pablo's mention that there are a few cases where you have agreed to lower the day rate on a term contract in exchange for an extension of the contract, sort of like the blend and extend deals we hear more frequently of offshore contractors.

But then I thought I heard you say that some of those deals then reverted back to the original contract. And I guess my question is, is that kind of deal common? Or because you have -- it seems that by far the majority of cases where E&P -- the E&P companies just want to buy out the remaining term of the contract.

Robin, let me make a couple of comments and John may wish to add to that, of course. But what you refer to as blend and extend type contracts, what that typically implies is that the contractor that reduces the day rate or the pricing in exchange of increasing the duration of the contract, that is not the case in terms of what we refer to.

What happens in the type of deals that we refer to is that there is a period of time for which a customer can get a slightly lower day rate. But then after that the day rate goes back to the original day rate contemplated in the contract. And the duration once again begins to take into account.

In other words if you have a two-year term remaining -- two out of three years remaining and you have a six-month period where you have lower day rates, then the two years that remain move to the right. And once you get to the point where the customer is ready to go back to a higher day rate, then -- which is in a short -- in the short-term in general, then the day rate goes back to the original price, at the higher price.

So, we thought that that was a mutually beneficial type of arrangement. It is not necessarily very common, but we do all that we can to work with our customers.

Right, I see. Okay well, thanks for clarifying that.

Kurt Hallead, RBC Capital Markets.

I was just real curious about when you look forward into next year, difficult market conditions, etc. You have the -- how do you think about the dynamic? Will you be able to fund CapEx and dividends and basically come out in a cash breakeven position, free cash breakeven position in 2016? Or is your gating factor CapEx? If you kind of see what I am saying.

Are you going to reduce CapEx to maintain a positive free cash flow position? Or are you going to need to tap a debt market or whatever to keep paying out your dividend? How are you guys thinking about that tactically?

Kurt, this is Juan Pablo. I guess the last part of your question I would like to address first. We would not expect to borrow money in order to pay dividends. If we were to borrow money in the future it would probably be to pursue opportunities to expand the business. It would probably business related.

But to the first part of your question, the amount of cash flow that we will be able to generate will depend on market conditions. And of course we don't provide guidance in that regard, so we can't provide you a reference there. What we do have of course is a significant number of long-term contracts that ensure that we will get a very strong base in terms of cash from operations.

And then from that we think that we will be able to fund the CapEx level that we commented on and the current dividend level. We also have of course, as you know, a very high level of cash and liquidity in general. If there were to be a negative cash flow position in any of the following years we would certainly look at that existing cash at the beginning of the year to fund whatever may be pending or may be the difference there. So hopefully that helps to answer your question.

Yes, yes, that is very helpful. Now the -- listening to the entire commentary and having a variety of discussions heading into this fourth-quarter period, it is still not quite clear to me whether or not there is going to be or continue to be incremental pricing pressures above and beyond what we have seen. And I'm just wondering if you might have some general perspectives on that and maybe provide a little bit of color to where there is no color right now?

Well, Kurt, this is John. I said earlier there really isn't much of a spot market out there, so there is not a lot of active bidding for work. I think generally that is when you see a lot of pressure on pricing per se. I don't get the sense that operators -- at least our customers in general, there is not this continual request for a reduction in day rate because I think -- number one, because we are working together very well, we are delivering a lot of value.

The cost of their wells continue to come down. I mean you just look across the board in the E&P space and that is a pretty common theme that well costs are coming down. So I just think it is not something that is out there being talked about because we are really not out there bidding much in the spot market.

I don't have -- I don't get a sense that there is going to be this huge push to continue to reduce pricing. But we are making an assumption that the market looks like it is now and that oil prices are in the $40 range and something crazy doesn't happen and prices go lower. I am not expecting that, but in that event maybe you would see some additional pricing pressure. But that is about as clear as we can make it right now, Kurt. We just really don't have any more visibility on that based on what we see right now.

Right. If I may kind of sneak one follow-up in. The comment you mentioned about some new builds -- now I wasn't quite clear on whether those new build deliveries were being canceled or were putting on hold as your potential customers are deciding when they are going to be ready to take those new rigs. Can you help clarify that for me?

Yes, Kurt, and in some cases over the last several months we have had some customers that have requested a delay in terms of the delivery of the new build in exchange for compensation to H&P. And again, we try to work with customers as best we can and we have accommodated in a few cases. And I think those are the four new builds that we made a comment on that you are probably making reference to.

So, they are not to cancellations, they are just delays in delivery?

Correct.

Okay, great. Thank you.

I think we have time for one more question, please, operator.

Byron Pope, Tudor, Pickering, Holt.

John, you touched on the indiscriminate laying down of rigs irrespective of rig quality and we have certainly seen it in overall rig count. Your Flex 5s have held up remarkably well from a utilization point of view. My but would suggest that that part of that is a function of when new builds came on to long-term contracts. But I was just wondering if you could comment on that?

Well, no, that is exactly right, Byron. I mean, they're a great rig and the reality is most of the Flex 5s had a -- they have a large amount of term contract remaining on that so the early termination fee is significantly higher. If you look at the Flex 3s, we have been building new Flex 3s, but the majority of the Flex 3s that were on long-term contract, a lot of them weren't still on their original new build term contract, if that makes sense.

Sure. Okay, and then second quick question. Despite the decimation to the overall US Land rig count you guys still have the most rigs working in two key areas, the Eagle Ford and the Permian. So could you speak to at a higher level what you are seeing in terms of footage per day? Just trying to think through the order of magnitude of drilling efficiencies that we still might be seeing?

Yes, that is a great question, Byron. As we look back all the way to 2010-2011 we have had double-digit improvements in productivity footage per day year over year. Maybe with one exception and that was going from 2013 to 2014 I think because of the level of activity that the industry experienced.

But we are obviously seeing a lot of performance improvement this year. Obviously you would expect that with having all of your people you have a lot of experience on rigs. But we're continuing to see 15% to 20% performance improvement year over year in 2015 versus 2014.

And when you -- like I said earlier, these rigs are performing at the highest levels ever. There is still some opportunities ahead, but clearly it is -- when you start looking at, as an example, a seven- or an eight-day well compared to a 25-day well, the opportunity set obviously gets a little smaller every year.

Sure, okay. Thanks, guys, I appreciate it.

Before we finish the call we have a couple more comments to make, please.

Yes, I just wanted to thank you all again. I want to leave you with one last thought and that is we continue to work very hard to improve the capabilities of the Company. H&P has a solid track record of coming out of these downturns as a stronger company.

Our management team has experienced many downturns and each time H&P emerges on the other side in better shape. Our efforts will remain focused on adding shareholder value and we appreciate each of you for joining us this morning and thank you again for your support.

Thank you, everybody. Have a good 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.