Helmerich and Payne Inc (HP) 2015 Q3 法說會逐字稿

Good day, everyone, and welcome to the third-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 our Q&A session. (Operator Instructions). Please note today's call is being recorded.

It is now my pleasure to turn the program over to Juan Pablo Tardio, Vice President and CFO. Please go ahead.

Thank you and welcome, everyone, to Helmerich and Payne's conference call and webcast corresponding to the third quarter of fiscal 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 comment and calculations on the last page of today's press release.

I will now turn the call over to John Lindsay.

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

You may recall, at the time of our last conference call in April, the US land rig count was still declining at a steep rate and we were reluctant to call the bottom. There have been several indications since then that the trough was approaching and the rig count did appear to bottom out, but today, seeing oil prices decline by over $10 per barrel over the past several weeks, that bottom could soon prove to be false. This is unfortunate for all of us in the energy sector who had hoped to see at least some recovery in the back half of 2015.

The industry has idled over 1,150 rigs in the US since the peak rig count in 2014. That's made up of approximately 720 legacy SCR and mechanical rigs, and approximately 440 AC drive rigs. H&P alone has idled over 180 AC drive FlexRigs.

While cost management in this kind of declining environment becomes a Company-wide priority, the challenge is to initiate reductions with the right balance. That undertaking involves rightsizing the organization as well as preserving our FlexRig assets for the future. One important aspect in the process is avoiding indiscriminate reductions that unduly damage our capacity to readily respond to a reversal in market conditions.

Although Juan Pablo is going to address expenses in a moment, I want to mention that much of the quarterly expense per day increase is associated with our systematic approach to idling our AC FlexRigs.

During the 2008 and 2009 downturn, we identified several best practices for idling AC rigs and preserving equipment integrity. We put those learnings into practice when the downturn began. There are three points I want to underscore relating to this process.

First, our currently idled fleet is worth billions of dollars in terms of replacement value. We take great care to preserve that value.

Second, a portion of that preservation effort entails operating, maintenance and security procedures, which does add to our per-day expense. Could we delay that expense today? Perhaps some of it, but we see our approach as a long-term investment in our FlexRigs. It's the case of pay me now or pay me more later.

Finally, the replacement cycle will continue. As the industry's high-grade process moves forward, our ability to respond in a timely and efficient manner will position the Company for more opportunities and will ultimately allow us to provide greater value to customers. Our rig preservation process enables our FlexRigs to be prepared to work when the customer is ready.

We believe, in terms of speed and scope, our ability to place rigs back into service during the last recovery created significant value for our shareholders. That quick response capability remains one of our key goals today.

Our fleet profile is a competitive advantage. The FlexRigs design allows us to provide a family of solutions for our customers. We have over 310 AC drive FlexRigs with 1,500 horsepower rating, which represents over 90% of our US land fleet.

In many of the basins we work, the requirement is for longer laterals, multi-well pads and higher horsepower specifications. We have over 180 pad optimal FlexRigs with 1,500 horsepower rating, AC drive power systems, multi-well pad capability, and, to a significant extent, 7,500 psi mud systems. Today and in the future, our organization remains focused on supporting our customers through innovations to our service offering as well as upgrades to our fleet as needed. Not all rigs require multi-well pad and/or 7,500 psi systems today, but as we have outlined on previous calls, we are seeing preferences shift and more E&P companies are choosing AC drive technology for horizontal, unconventional resource drilling. AC drive rigs continue to replace legacy rigs, and today have over 50% of the US land industry market share. And that's up from 40% at the peak last year.

There are significant competitive advantages for H&P by having a standardized, modern fleet of AC drive FlexRigs. We are able to leverage the learnings we capture and provide greater efficiencies, reliability, safety, and savings for our customers. We have been fortunate to have picked up over 10 new customers this year, and that new customer adoption is a result of our performance and reliability.

Before turning the call back over to Juan Pablo, I want to address the outlook for activity for the rest of 2015. We know better than to try to predict oil prices or rig count, so I won't attempt that today. I will share a few anecdotal experiences from the past few weeks, the tone from the customer of what may happen assuming oil prices don't improve from here.

First, we have seen instances where some customers have, at least for now, backed off of plans for re-activations in the second half of 2015. Secondly, some customers believe it's reasonable to assume that the current US land rig count may not be sustainable with WTI oil priced in the $40s. Finally, operators remain disciplined with respect to their budgets, and they plan to spend within cash flow and lower commodity prices mean fewer wells drilled.

This remains a very challenging environment, but we believe the Company is well-positioned. Long-term contracts continue to protect our investments. The balance sheet is in great shape, our customer base remains strong, and our competitive advantages have positioned us to manage through this cycle and to capture opportunities when they emerge.

Now I'll turn the call back over to Juan Pablo and he will make a few comments regarding the results of our third fiscal quarter and some remarks related to the outlook for the fourth fiscal quarter.

Thank you John. The Company reported $91 million of net income, $130 million in operating income and $660 million in revenue during the third quarter of fiscal 2015. As expected, these quarterly levels were down significantly as compared to the prior quarter.

Following are some comments on each of our drilling segments. Our US land drilling operations delivered approximately $122 million in segment operating income during the third fiscal quarter. The number of quarterly revenue days significantly declined, resulting in an average of approximately 156 rigs generating revenue days during the third fiscal quarter and representing a 32% decline in revenue days as compared to the second fiscal quarter. On average, approximately 128 of these rigs were under term contracts and approximately 28 rigs worked in the spot market.

Excluding the impact of early termination revenues, the average rig revenue per day decreased by 3.4% from the second fiscal quarter to $26,634 in the third fiscal quarter, and the average rig expense per day increased by 5.5% to $14,130, resulting in an average rig margin per day of $12,504 in the third fiscal quarter. The decline in average rig revenue per day was attributable to softer market conditions and to mutually beneficial temporary day rate reductions for some rigs that are under long-term contracts. Those temporary day rate reductions were granted in exchange for additional term durations at fully priced day rates, also fully protecting the backlog for the corresponding rigs and effectively extending the duration of the corresponding work. The increase in the average rig expense per day was primarily a result of the high volume of idled rigs and related efforts to be cost-effective through the cycle and well-positioned for a potential industry recovery.

During the quarter, the segment generated approximately $76 million in revenues corresponding to long-term contract early terminations. Given existing notifications for early terminations, we expect to generate less than $4 million during the fourth fiscal quarter and about $23 million thereafter in early termination revenues.

Since November of last year and excluding some rigs working for customers that decided not to early terminate their contracts as per prior written notice to us, we have received early terminations for a total of 47 rigs under long-term contracts in the segment. Total early termination revenues related to these 47 contracts are now estimated at slightly under $200 million, approximately $87 million of which corresponds to cash flow previously expected to be generated through normal operations during fiscal 2015, $62 million during fiscal 2016, and $49 million after that.

As of today, our 342 available rigs in the US land segment include approximately 156 AC drive FlexRigs generating revenue and 186 idled rigs, including 179 idle AC drive FlexRigs. Included in the 156 rigs generating revenue are 124 rigs under term contracts and 32 rigs in the spot market. The 156 rigs generating revenue include some rigs that are on standby type day rates and some new build deliveries that have been delayed in exchange for compensation from customers. Note that these delayed newbuild rigs do not yet generate revenue days.

Since our last conference call in late April, the number of FlexRigs on standby type day rates has significantly declined, as over half of those have returned to work.

Looking ahead to the fourth quarter of fiscal 2015, we expect revenue days to decrease by about 3% to 4% quarter-to-quarter. Excluding the impact of revenues corresponding to early terminated long-term contracts, we expect our average rig revenue per day to decline to roughly $26,000. The average rig expense per day level is expected to decline to roughly $13,900 as we continue to manage the transition towards what we expect to be a more stable level of activity during the next few months.

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 120 rigs during the fourth fiscal quarter and an average of about 108 rigs and 82 rigs during fiscal 2016 and fiscal 2017, respectfully.

The recent and mutually beneficial negotiations of some long-term contracts that resulted in reduced day rates in exchange for additional term durations at fully price levels impacted the average rig margin per day level for all rigs on term contracts by less than 5%. This average for rigs that are already under term contract is expected to remain strong and roughly flat during the next several quarters as some rigs roll off and new builds are deployed. The average is expected to once again increase to previous levels when the mentioned day rate reductions expire and the remaining term contract durations from those contracts begin to once again apply.

The average pricing for rigs in the spot market declined by approximately 7% from the second to the third quarter of fiscal 2015 and is expected to continue to at least slightly decline during the fourth fiscal quarter. Average spot pricing today is about 28% 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 $15 million from $19 million during the prior quarter. Total revenue days decreased by about 8% as one rig was demobilized and became idle at the end of the second fiscal quarter. Also as expected, the average rig margin per day declined by about 24% to $14,265 during the third fiscal quarter.

As we look at the fourth quarter of fiscal 2015, we expect revenue days to be relatively flat as one platform rig that was expected to become idle was recently contracted by another customer and continued generating revenue days while being prepared for the new project.

We expect the segment's average rig margin per day to decline to approximately $10,500 during the fourth fiscal quarter. The expected average rig margin decline is mostly attributable to four rigs that are not performing operations but that are generating relatively low margins under standby type day rates and one rig that is earning a temporarily reduced operating day rate to accommodate for a special project that is expected to expand the total duration of the overall project. The latter arrangement is mutually beneficial as it extends the total duration of the project while fully protecting our minimum term contract duration at fully priced day rates.

Management contracts on platform rigs continued to favorably contribute to our offshore segment operating income. Their contribution during the third fiscal quarter was approximately $8 million and is expected to decline to approximately $6 million during the fourth fiscal quarter.

Moving on to our international land operations, segment operating income increased by approximately $10 million to over $16 million during the third fiscal quarter. The increase was mostly attributable to early termination compensation earned during the quarter. Excluding the impact of $373 per day and $4,658 per day corresponding to early contract termination compensation during the second and third quarters respectively, the average rig margin per day increased from $10,524 to $13,086 per day. This increase was the result of strong performance during the quarter in all of the countries where we have active rigs, even while dealing with several rigs in transition.

Revenue days sequentially increased by about 2% to an average of over 20 active rigs during the third fiscal quarter. As of today, our international land segment has 17 active rigs, including 11 in Argentina, two in Colombia, two in the UAE, one in Ecuador, and one in Bahrain. 23 rigs are idled, including eight in Argentina, six in Colombia, five in Ecuador, two in Bahrain, and two in Tunisia. Thus, we expect international land quarterly revenue days to be down by 10% to 15% for the fourth fiscal quarter. We also expect the average rig margin per day to decline by about 30% to 35% as compared to the third fiscal quarter, excluding any impact from early contract terminations. We expect to generate early termination revenues of approximately $9 million during the fourth fiscal quarter in the segment. The expected daily rig margin decline in the segment is primarily due to expenses corresponding to several rigs that have become idle and two rigs that are scheduled to be demobilized out of Tunisia.

Let me now comment on some corporate level details. Our liquidity position is very strong and we expect no change to our regular dividend dollar per share levels in the foreseeable future. Our capital expenditures estimate for fiscal 2015 remains at approximately $1.3 billion. Although we don't plan to provide a capital expenditures estimate for fiscal 2016 until our next conference call in November, at this point, we would expect the fiscal 2016 estimate to be significantly lower than the one for fiscal 2015.

Our Flex reconstruction cadence plan remains generally the same with 12 new FlexRigs to be completed between now and the end of March of 2016. Including the long-term contracts for these 12 new FlexRigs, we already have secured term contracts for an average of approximately 137 rigs across our three segments during the fourth quarter of fiscal 2015. In addition and also for all three segments combined, an average of about 122 rigs is already under contract for fiscal 2016, and an average of approximately 95 rigs for fiscal 2017.

Given the soft market conditions, our backlog decreased from approximately $3.9 billion as of March 31, 2015 to approximately $3.5 billion as of June 30, 2015. The value of our backlog is expected to continue to decline during the fourth fiscal quarter as we earn related income through operations or through any additional but at this time unexpected early contract termination compensation. We now expect our total annual depreciation expense to be approximately $580 million during fiscal 2015 and our general and administrative expenses to be approximately $130 million. Interest expense after capitalized interest is still expected to be approximately $[15] million for fiscal 2015.

The effective income tax rate for the third fiscal quarter was 28.9%. This reduced rate was mostly a result of a favorable adjustment to our US deferred state income tax rate caused by less activity in the states where we operate in as well as decreases to some of the state income tax rates. The effective tax rate for the fourth quarter of fiscal 2015 is expected to be approximately 34%.

Our deferred income tax liability as of June 30, 2015 was approximately $1.33 billion. We still expect this liability to remain in the range of $1.3 billion and $1.4 billion through at least the end of fiscal 2017.

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

Thank you again Juan Pablo. And before we open the call to questions, I want to make a few additional comments to frame up the challenges and opportunities ahead for H&P. The challenges are clear. Faced with a global oversupply of oil as well as other geopolitical and macroeconomic headwinds that intensify the supply-demand imbalance, the short-term outlook for the industry is unfavorable. However, a significant difference today compared to previous down cycles is that the US may be in a position to become a global swing producer. In such an environment, the energy services landscape would most probably become more competitive with even greater pressure to reduce well costs, enhance productivity, and add value for customers. We believe that type of a market is a great opportunity for H&P. Our long-term strategy has delivered a track record of innovation, performance and value creation for customers. Our people remain committed to this endeavor and we look forward to the opportunities ahead.

So Lindy, we will now open the call for questions.

(Operator Instructions). Chase Mulvehill, SunTrust.

Good morning fellows. So I guess in one of your recent presentations, you guys talked about renegotiating term day rates lower for additional term. Can you just walk us through the kind of details here and kind of when you expect those to step back up?

This is Jan Pablo. Those are relatively short-term type agreements. Within a year, we should be out of that type of arrangement, but we will see how the market goes. Again, we do believe that it is a mutually beneficial arrangement, and we have a fully protected de minimum duration of the term as well as that minimum duration at fully priced levels.

Okay. Thanks for the color. 3 And then if we kind of move to international real quick, is there any opportunities to move US FlexRigs to international markets? And without just kind of identifying markets, what kind of expectations do you think that you could have over the next 12 to 18 months kind of potential to move rigs to international markets?

Sure. This is John. I think there are several opportunities. I'm sure you recall we did send 10 Flex 3s to Argentina. Those were all existing Flex 3s. And that opportunity initially presented itself in I guess it was 2013. We had a little bit of a slow spot at the time. We had probably 20 idle AC rigs, and so we sourced those rigs out of the US. And so there's no doubt there is an opportunity. The FlexRigs have clearly performed well in every country that we've worked. The performance has been outstanding. So I think there's opportunities not only in South America but I think there's also continued opportunities in the Middle East. So I do think this slowdown in our capability and having those rigs available in the US does give us that opportunity to expand our international fleet.

Okay. All right. Last kind of follow-up for me. Maintenance CapEx, you talked about fiscal 2016 CapEx being down significantly. How can we think about maintenance CapEx for fiscal 2016, assuming a flat rig count environment?

This is Juan Pablo. We've said in the past that of the $1.3 billion estimate for fiscal 2015, less than 20% was expected to be in maintenance CapEx. And so that's the only parameter that I can refer to it at this point. Whether it's $200 million to $260 million for fiscal 2015, we will see what the number is in the end. We'll have -- if we -- as you said, assuming that activity remains stable, then we will probably have an even lower level of maintenance CapEx for fiscal 2016.

Great. That's all I have. Thanks John. Thanks Juan Pablo.

Kurt Hallead, RBC Capital Markets.

Thank you. Good morning. You guys mentioned a little bit earlier in your presentation about the day rates to remain flat over the next several quarters, and then the average would increase their previous levels predicated on a few different factors. I'm not sorry, but I was a little bit slow in trying to follow how you were trying to express that. So could you state that one more time?

Sure. This is Juan Pablo. We were referring explicitly to rigs that are under term contracts, so not to all rigs but only rigs that are under term contract. And we were referring to the average rig margin per day. And as we looked at the impact of these renegotiations on that average rig margin per day for term contracts, we determined that that impact was under 5%. So within the next several months, probably less than a year, we would expect those temporary reductions to expire and to go back to prior fully priced levels, which would yield, again, the type of margins where we were at before these reductions. So we would expect to get that approximately 5% back, again, once we have these temporary reductions expire. Does that bring clarity to your question?

Yes, that does help a lot. Appreciate that. The follow-up question I had, John, you indicated kind of early on, or had given some indications of tone and tenor of the customer base, and indicated that the rig count would be unsustainable at a $40 oil price. And I think we can understand that pretty well.

But maybe digging a little bit deeper into some of this tone and tenor, overall are you then getting the impression that the E&P mindset is that oil is going to remain around kind of current levels, $50-plus levels, and at these levels that there is no upside or no downside to activity? How would you characterize the viewpoints on that?

As always, when you start talking about these kind of things and using numbers, it's easy to get -- to not be as clear as you want to be. I really meant to say in the $40s. We are in the $40s. We are a mid to high $40 range. And again, I think, even in that price environment, we are more than likely going to see the behaviors that I mentioned, which is some rigs that were previously going to be reactivated on the back half of 2015 most likely won't be unless oil prices improve. The question is at what oil price?

And again, I think we saw the industry beginning to move. You saw the rig count begin to flatten and you began to see more discussions regarding rigs and the spot market. But in this pricing environment, I just don't think you're going to see that. In fact, I think you could see the rig count pull back some. So, again, it's a challenge. I think in order to see the rig count begin to improve, we're going to have to see a stronger oil price environment than what we have seen.

If you recall, I think it was in the last round of earnings calls, there were some that were expecting a 200-rig increase by the end of the year, and we said we just didn't see that. We couldn't see how there could -- that could happen. We weren't -- at that time, of course we weren't expecting oil to pull back into the $40s.

I mean the reality is I think if you went out and surveyed 10 different E&P operators, you would get a pretty wide range of expectation on pricing. And I think a lot of folks are thinking oil prices are going to be lower as opposed to moving higher.

Okay.

But again, I'm not here to predict the oil price. I'm just telling you what we've heard from customers and others in the industry. I think you guys have heard the same thing.

Yes. I appreciate that color. That's helpful. Thanks.

Byron Pope, Tudor, Pickering, Holt.

John, I just wanted to get your thoughts on average rig revenue per day trends, and understanding that you guys want to keep your fleet in quick response capability. And so if we -- so whatever recovery scenario we want to assume, is it fair to think that as we see some of your idle AC rigs go back to work over the next 12, 18 months, that that rig expense per day should gravitate back down closer to what it's been historically in call it the $13,000 or $13,300 range, just somewhere in that historical range is still the appropriate way to think about your true rig expense per day, again, putting aside the costs that you guys are temporarily incurring to get your fleet ready?

Right. And you saw that Juan Pablo had talked about our cost expectations for the next quarter. But you are right. Part of the challenge of course is the rigs that are idle have an ongoing expense and at the same time, your average number of rigs working in lower, so your denominator is smaller, so you just have a higher cost. But as rigs are idle longer, the expense is lower. We are not spending that same level of money that we are day 90 on as we are in the first 30 to 60 days. So I think your expectation is right. I think -- and again, we've talked about this and we are not going to throw a number out there, but $13,000 is achievable again in the future with more rigs running. I don't exactly know what that number of rig count is. But I think, as we begin to get more clarity over the next couple of quarters, we will see that.

I can tell you we are spending a lot of time and effort on the cost side, but at the same time, like I had in my remarks, we are going to make certain that we are spending and investing in the rigs in the way that we need to.

And then just a second quick question for me. It seemed as though, at the peak of your newbuild orders, the lion's share of the rigs were going to be headed toward the Permian and the Eagle Ford. So if you think about the 12 remaining newbuilds to be delivered between now and next March, is it reasonable to think that the geographic mix of those is similar to what it has been?

Yes, I think that's fair. I think about -- I believe nine of those are going to Permian, and I think the others are going into Oklahoma.

Okay, thanks guys. I appreciate it.

Brad Handler, Jefferies.

Thanks. Good morning guys. I guess maybe coming back to the inquiries in the conversation, to what extent is the high grading conversation therefore also kind of being put off? It sounds like it is, but even if an operator wasn't planning on taking more rigs, I think that you had some optimism earlier that perhaps a high grading process might have been relevant.

High grading is still very relevant. I don't have insight into the number of legacy rigs, SCR mechanical rigs that are running today that are also under a term contract. But I think there's a fair amount of rigs that are in that category. And so yes, those rigs, we are in discussion with customers with -- hopefully the intent would be to replace those rigs. So I think the replacement cycle is alive and well and in some respects even more so because of the types of wells that are being drilled today. So I think that's going to happen. Again, a lot of that is going to relate to the number of those rigs that are rolling off of term. Does that answer your question?

Yes. It absolutely does. Maybe I missed it, Juan Pablo, but in terms of the international in your fiscal fourth-quarter outlook, so I'm just jumping to international, perhaps I missed it, and so apologies. Could you describe again the basis for why the margins fall back to the $10,000-ish kind of day level? You mentioned very good execution in fiscal 3Q. Are you just hedging against that being able to repeat in fiscal 4 or was there something more specific that weighs on the margin internationally?

This is Juan Pablo. There are a couple of considerations that are most relevant in explaining the decline, and the first one relates to several rigs becoming idle. Unfortunately, we've had close to half a dozen rigs that have become idle in recent months, and so we are dealing with the process of stacking those and dealing with those. And of course, there's expenses associated with that.

The other consideration relates to rigs that are not contracted being demobilized out of Tunisia that do have an impact on margins, a relatively significant impact on margins. So, the combination of those two things are leading us to the type of decline that we are projecting.

Okay. Just a follow-up on that point. As I think maybe about the first fiscal quarter of 2016 then, can we imagine that the costs that you've just described in both of our -- you're finished spending them so there's a little bit lower rig count? I don't know if the two -- do the two relate -- so the two aren't working anyway. So are the costs out of the system then, and so you might -- one might naturally expect margins to rebound on the 17 active rigs in the first quarter of 2016? Is that logical?

I think it is. I think, everything else being equal, that is a fair expectation, for us to see an improvement in margins during the following quarter. However, and as everything else being equal, we'll have to see what else happens in the segment, and we will certainly comment on that during our next conference call.

Sure. Okay. Thanks guys. I'll turn it back.

Waqar Syed, Goldman Sachs.

Thank you for taking my question. On the rigs that are idle right now, the Flexes, could you provide us with a breakdown of rigs between Flex 4s, 5s, and 3?

Let us look at it right quickly. Let me get a better handle on those numbers. So, approximately 111 FlexRigs 3s, seven FlexRigs 5s and the rest are FlexRigs 4s.

Okay. And so the top number --

I think you were talking only about the FlexRigs. So we do have seven conventional idled rigs as well. Those are all 3,000 horsepower.

Okay. And so the FlexRigs number was 180 that you had given, right, the idle FlexRig number?

I think it was 179.

179? Okay. And then off these rigs, how many are pad-drilling capable? And could you give a breakdown between the three as well?

Well, of the rigs that are -- of the rigs, over half of the rigs are pad-capable. Of those particular, what's the number here? I think the thing that is a key, when you say they are pad-capable right now in that, as an example, if it's a Flex 3, many of the Flex 3s have pad capability, have had that upgrade installed, but many of them don't. But we continue to upgrade Flex 3s in the existing fleet to make them pad-capable. So the number we would be giving you right now is a snapshot today. If you ask us that same question three months from now, the number is going to be higher.

Juan Pablo, do you want to go ahead?

I think the numbers are about 36 FlexRig 3s, about 41 FlexRig 4s, and seven FlexRig 5s.

Are pad-capable of the ones that idled?

And idled, yes.

Okay. My understanding is, gosh, maybe like a $1 million investment to maybe make any rig pad-capable. Do you expense that cost? Do you capitalize that?

We capitalize that.

You capitalize that. Okay. Makes sense. And then what is the difference between, data difference maybe in percentage terms between rigs, in the last quarter, between the rigs on term contract, the data there or revenue per day there versus those on spot?

Let me give you a general answer for that. The day rates and pricing for term contracts has remained very steady except for what I mentioned earlier as it relates to these temporary renegotiations. That impacted margins by about 5%. So the day rates were only impacted by a few percentage points, a couple percentage points, maybe 2 or 3. So those have remained flat while, since November, as I've mentioned, we've had a decline in the average spot pricing for our rigs of about 28%. I think it is fair to assume that at the peak, the average rig -- excuse me, the average day rates or pricing for rigs on term was similar. I think it was maybe a couple of percentage points higher than the average spot pricing at that point. So, those are some data points for consideration.

Okay.

And of course now, again, I just want to make sure I clarify. The term day rates or average pricing that we saw at the peak last year has come down slightly, temporarily, and we expect it to come back up, as I mentioned in the previous answer. Right?

Sure. I understand that. John, just a broader question on costs. Like cost is -- obviously cutting costs is going to become a big theme. For a land driller, where is the opportunity to cut costs? How can you cut it in G&A? Is it at the rig level? Where is the opportunity to cut costs?

There's obviously efficiencies associated with the cost cutting savings. Let's face it. The cost increases we have had are transitionary in nature, as we have already described. Obviously, the labor cost is the largest portion of that cost, and as you know that's, a direct cost pass-through to the customer. So any wage decrease is going to be passed through, so there is an offsetting revenue reduction.

There's -- the maintenance and supply cost is the other side, or the other larger piece or largest piece of the cost. And again, I think we are in as good a position as anyone to be able to manage that as effectively as possible with the fleet that we have, the size that we have and the fleet uniformity. But the fact is, and you've probably heard me say this before, but the fact is the rigs are working harder and harder because they are drilling longer laterals at higher pump pressures and there's just more -- the rigs are drilling faster wells, faster well cycle times. So that's working against us, so to speak, on getting the maintenance and the supply costs down. So there's efforts that we have underway to work on that.

Juan Pablo, do you have anything else to add on that? I mean again, the biggest challenge we have right now is we've got costs associated with rigs that are idle that aren't earning revenue, and so that's the challenge. And there's fixed costs associated with that that there's not anything we can do about at this stage of the game.

Sure. Okay. Thank you very much. Thanks for the answers.

Sean Meakim, JPMorgan.

Good morning. So I just wanted to talk a little bit about newbuilds, the newbuild program. Historically, we've thought about the rigs as having pretty long lives, maybe 20, 30 years. And with the high-spec rigs that are coming out today, we're working on them a lot harder, the shift in technology demand from the client side. Do you think that the life of recent builds is going to be much shorter, something like closer to 15 years? And then how does that influence -- if you think that's the case, how does that influence your view on future demand for newbuilds as we look out the next call it couple of years?

We have of course our original 32 Flex 3s that we built from 2010 to 2014. And again, you've probably heard us say this before, but we have continued to invest in those rigs and we've continued to make certain that the technology that they have is up to speed.

The structures, we have an ongoing, very detailed structural inspection process. The structures are very sound. And so I don't know if it's a 15-year life or 20-year life or a 30-year life. Obviously, the market is going to dictate that. I would like to think that with the investments we are making in these rigs that they're going to continue to work. I sure don't see any evidence that those first Flex 3s that we have built are any less popular. Those rigs continue to work. Some have skid systems and some don't.

So Juan Pablo, I don't know if you have anything else to add on that.

I'll just add that the comment that for financial purposes we depreciate our rigs in 15 years straight line with a 10% salvage number, and that number or that approach we believe is a fair one.

I think the other thing, as I think about your question, you are right. The rigs are working harder. It's more wear and tear on the assets. And so again, that's one of the things that we pride ourselves in. I think we do a very good job in -- is in asset integrity and taking care of those assets and supporting our people, because it's not only the rigs side of the equation on these much faster well cycles. It's also personnel and what they are required to do in that given well cycle. So there's also the organizational support that we provide our people that allow them to better maintain that equipment. Again, I think that's one of our significant competitive advantages.

That's all very fair. I guess just sticking with the newbuild theme, as we look forward here, we are talking now about potentially some softening of demand, maybe some evaporation of incremental. But if the rig count doesn't take another leg down, if we flatline here for several quarters, let's say, is there an opportunity as re-fleeting runs its course that you could see incremental demand for newbuilds even in a world in which there are still other AC rigs that are still idle?

I think we're -- I don't know what the rig count is to have what you just described happen. I think it significantly higher than 850 rigs. I would think it would at least need to be 1,000 or 1,100, 1,200 rigs. But I think, again, to your point, not all AC rigs are created equal. And I think that's pretty evident. Over the last couple of years, there has remained 50 or 60 idle AC rigs that never worked. So those rigs obviously are not included in the equation.

And then as we trend more towards a higher number of rig drilling on pads at a higher number of rigs that require 7,500 psi that have greater depth requirements, a lot of those things disqualify. Some of those maybe describing as a lower tier AC assets. So again, it will be interesting to watch.

Now does the market -- the other part of your question is does the market get strong enough to have rates that will support newbuild economics? And we are a long way from that.

That makes a lot of sense. Thanks, John. I appreciate it.

Michael LaMotte, Guggenheim.

Thanks. John, if I could follow up on your very last comment, the market being a long way away from newbuild economics. Can you talk about just philosophically how you feel about the infrastructure you've built before new building as we go into 2016? In previous downturns, you've maintained a cadence of one rig a month (technical difficulty) integrity of that. How are you thinking about that into next year?

You know, you heard us say that our desire is to keep that facility or that capability up and running and operating. I think the lowest we've been is one rig a month over the last -- well, since 2006. And we had talked about going to one rig a quarter.

The great news right now is we don't have to make that decision now. That's part of the advantage of pushing our newbuilds out into 2016. But we will have some level of manufacturing capability. We wouldn't close the entire facility down. But I don't know what it looks like right now, Michael.

The reality is the outlook is pretty difficult. And again, we haven't -- we saw some improvement in oil prices and started to see a little pick up it appeared in activity, and now we are faced with what we are faced with. But again, I feel pretty good that we will figure out some way to keep that facility working in some fashion. I just don't know what that looks like today.

And maybe -- I know aftermarkets are long-term but if I think about your ability to do maintenance on rigs, prepare them for work overseas, you know, as opportunities emerge, is that the kind of work scope that we could see back-room filling if there were no contracts (technical difficulty)

There are several opportunities. That's one of them, international, just other upgrades to rigs. And again, I said before we continue to add pad systems to Flex 3s and other upgrades, 7,500 psi systems and those types of things. So there's a lot of things in a market that continues to evolve and has higher and higher expectations for rigs. That's one of the ways to keep the facility operating.

The last one for me, you talked about the competitiveness and the fact that 90%-plus of the US fleet is 1,500 horsepower -- obviously impacting. How do you think about automation penalties with Schlumberger now talking more about the next generation rig (technical difficulty) integration of downhole surface, more automation. Is the fleet sort of plug-and-play ready? Should that (technical difficulty)

I think we are probably as well-prepared as anybody with respect to automation. And I think it obviously has an opportunity to do more and contribute more in the future. Again, I like -- and you've probably heard us say I like our position. I like where we are in that space with the AC fleet that we have and with the footprint that we have and the knowledge that we have as an organization. So I feel pretty good about it, and I think it's got some likelihood, but it also has -- just because of the level of performance that we are delivering today, as you know, it's harder and harder to get other technologies that are involved. But again, I think there's some possibility there.

Thank you.

Jeff Spittel, Clarkson Plateau Securities.

Thanks. Good morning guys. I know we are getting towards the end of the hour now, so maybe just to look at that comment that you made about standbys and rigs being put back to work as we saw for at least a fleeting moment of recovery in oil prices (technical difficulty) and some other assets of the conversation. Is it fair to conclude I guess that you did see quite a bit of upside sensitivity to, all things considered, a relatively modest increase in crude prices as we went through the quarter? And obviously that isn't the case today. But maybe some cause for optimism there.

I want to make certain I understood your question. So if we see an improvement in oil price, we could see a corresponding -- a fairly quick corresponding response. Is that what you're asking?

Yes. That's kind of what I am getting, John, I guess from your comment that you did see a lot of rigs that were on standby rates getting back to work when we saw oil prices recover briefly during the quarter.

Yes, I think that's one element. That's one indicator. And again, just customer discussions and looking for rigs and high grades, in some cases it's a high grade. In other cases, it's an additional rig. And I think you probably would see fewer discussions on additional rigs and we'll continue to have discussions regarding high grading or replacing rigs that are older that are not performing as well.

Sure. Okay, that makes sense. Thanks guys. I'll turn it back.

Lindy, we may have time for one more question please.

Jim Wicklund, Credit Suisse.

Good morning guys. Thanks for letting me in. I appreciate it.

You guys mentioned on a conference call a couple of years ago that you have 57 customers who are just fine with the fact that your rigs skid, not walk. You talked about pad-capable rigs. Have y'all put any walking systems on any of your rigs? Do you feel any pressure to? And when you say pad-capable, what's the difference with you guys between pad-capable and not pad-capable?

Okay Jim. That was a mouthful.

Ha ha, last question. I won't do a follow-up.

Thank you. I don't really know how to address the last part of your question. With us, again, we've been utilizing skid systems on Flex 3s for quite some time, and of course Flex 4s and Flex 5s. You know the stats. Last year, we had 89 newbuilds and over two-thirds of those had pad-capable systems as part of the investment.

And you're calling pad-capable systems walking systems?

Well, no. It's interesting because a lot of people will reference a pad rig as walking even when the rig isn't a walking system. So I think there's some -- I think there's some overlap in there. Our experience has been we have a family of solutions with our Flex rig offering, and there's upgrade capabilities within that. We've had a lot of traction over the years utilizing it.

To answer your question, we don't have a walking system now. I think it's fair to say you've heard me say in the past that if and when we get to that point where it's a difference between having a job and not having a job, obviously it's not a breakthrough technology. The technology has been around for a long time. So we would put a walking system on a rig if it were the difference between having a large share of the market and not having. So that's really the bottom line for us, is that customer demand has been pretty significant. We continue to upgrade rigs with our system, our skid systems, and we have customers that love it. So --

Okay gentlemen. I appreciate it, and thanks for squeezing me in at the end.

Thank you Jim. And one more quick comment. I may have used a round reference of $130 million as it relates to operating income for the third fiscal quarter. A more accurate number would be $132.8 million. So with that, thank you everybody and have a great day. Goodbye.

That does conclude today's program. You may disconnect at this time. Thank you and have a great day.