Patterson-UTI Energy Inc (PTEN) 2015 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Patterson-UTI Energy third-quarter earnings conference call.

(Operator Instructions)

As a reminder, today's conference is being recorded. I would like to introduce your host for today's conference, Mr. Mike Drickamer, Director of Investor Relations. Sir, please go ahead.

Thank you, Michelle. Good morning, and on behalf of Patterson-UTI Energy, I would like to welcome you to today's conference call to discuss the results of the three and nine months ended September 30, 2015. Participating in today's call will be Mark Siegel, Chairman; Andy Hendricks, Chief Executive Officer; and John Vollmer, Chief Financial Officer.

Again, just a quick reminder that statements made in this conference call that state the Company's or management's plans, intentions, beliefs, expectations of predictions for the future, are forward-looking statements within the meaning of the US Private Securities Litigation Reform Act of 1995, the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements are subject to risks and uncertainties as disclosed in the Company's annual report on Form 10-K and other filings with the SEC. These risks and uncertainties could cause the Company's actual results to differ materially from those suggested in such forward-looking statements or what the Company expects. The Company undertakes no obligation to publicly update or revise any forward-looking statement. The Company's SEC filings may be obtained by contacting the Company or the SEC, and are available through the Company's website and through the SEC's EDGAR system.

Statements made in this conference include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included on our website, www.PatEnergy.com, and the Company's press release issued prior to this conference call. Now it's my pleasure to turn the call over to Mark Siegel for some opening remarks. Mark?

Thanks, Mike. Good morning, and welcome to Patterson UTI's conference call for the third quarter of 2015. We are pleased you are able to join us today.

As is customary, I will start by briefly reviewing the financial results for the quarter ended September 30. And then I will turn the call over to Andy Hendricks, who will share some detailed comments on each segment's operational highlights, as well as our outlook. After Andy's comments, I will provide some closing remarks before turning the call over for questions.

Turning now to the third quarter, as set forth in our earnings press release issued this morning, we reported a net loss of $226 million or $1.54 per share on revenues of $422 million. The financial results for the third quarter include pretax, non-cash charges totaling $280 million or $1.28 per share after-tax. These charges include $125 million from the impairment of pressure pumping-related goodwill, and the write-down of assets, including $131 million of drilling equipment, $22 million of pressure pumping assets, and $1.9 million related to certain oil and natural gas properties.

The $131 million write-down of drilling equipment is primarily related to the reduction in the carrying value of our mechanical rig fleet, as well as related spare components. We retired 33 rigs, including 24 mechanical rigs and non-APEX electrics rigs. These 33 rigs were among the oldest in our fleet, and it had an average drawworks horsepower rating of less than 1,000 horsepower.

The 19 mechanical rigs remaining in our fleet, net of their write-down, have a net book value of only $13.1 million. The $22 million write-down in pressure pumping was related to the write-down of certain closed facilities, equipment and spares, including nitrogen pumping equipment, and less than 10,000 horsepower of older hydraulic fracturing equipment.

Turning now to our balance sheet, our financial position remained strong during the third quarter. Liquidity was unchanged during the quarter and ended the quarter at $576 million, including $76 million of cash and $500 million available under our undrawn revolver. Total adjusted EBITDA during the third quarter was $127 million, and we remained EBITDA positive in all three of our operating segments.

With that, I will turn the call over to Andy.

Thanks, Mark. In contract drilling, our rig count averaged 105 rigs during the third quarter in the US and 4 rigs in Canada, compared to 122 rigs in the US and 2 rigs in Canada during the second quarter. During the third quarter, total contract drilling revenues were $262 million, including $28.9 million of revenues from early contract terminations. These early contract terminations positively impacted our average rig revenue per day of $26,010 by $2,870.

Excluding early termination revenues, average rig revenue per day during the third quarter would have been $23,140, compared to $24,330 per day in the second quarter. Total average rig operating costs per day decreased $140 during the third quarter to $13,580. Excluding the positive impact from early termination revenues, total average rig margin per day was $9,560, compared to $10,600 during the second quarter.

At September 30, we had term contracts for drilling rigs providing for more than $800 million of future day rate drilling revenue. Based on contracts currently in place, we expect an average of 71 rigs operating under term contracts during the fourth quarter, and an average of 45 rigs operating under term contracts during 2016. Looking forward, we expect current commodity prices will lead to further rig count reductions across the industry during the fourth quarter.

For the month of October, we expect our rig count will average 92 rigs in the US and 4 in Canada. We expect our fourth-quarter rig count to average 85 rigs in the US and 4 rigs in Canada. With the further reduction in our rig count during the fourth quarter and an improvement in the fleet mix towards more APEX rigs under term contract, we expect total average rig margin per day to improve modestly to $9,700, excluding the positive impact of early termination revenues.

Early termination revenues in the fourth quarter are expected to be approximately $9 million. Our total rig fleet now consists of 220 rigs, including 160 APEX rigs, 41 non-APEX electrics rigs and 19 mechanical rigs.

Turning now to pressure pumping. Pressure pumping revenues and margins were negatively impacted as pricing and activity levels were lower than we expected. Pressure pumping revenues decreased 13% sequentially to $154 million, and gross margin as a percentage of revenues fell to 10% from 19% in the second quarter. Importantly, we continued to generate positive EBITDA in this business, as adjusted EBITDA totaled $11.8 million.

We continue to focus on managing the aspects of our business that are within our control. We are continuing to work with our vendors, although we expect our largest cost reductions were already achieved in the second and third quarters. Further cost reductions from suppliers will likely be smaller in scale.

We have reduced our pressure pumping headcount, and have closed and consolidated several districts. Given market conditions, we have stacked another 5% of our horsepower over the last three months, and we have approximately 38% of our more than 1 million frac horsepower stacked. Looking forward, we expect total pressure pumping revenues for the fourth quarter to decrease to approximately $120 million. Gross margin, as a percentage of revenues, is expected to be approximately 6%.

Before I turn the call back to Mark for his concluding remarks, let me provide an update on a couple of other financial matters. Our total CapEx for 2015 is projected to be approximately $700 million, of which we have already spent $608 million through the first three quarters. We've not yet completed our 2016 budget, but given current market conditions, we do not expect to build any new rigs or purchase any new frac horsepower.

We currently expect CapEx in 2016 will primarily consist of maintenance capital, in which case we expect CapEx would be less than $200 million next year. Depreciation expense during the fourth quarter is expected to be $175 million. SG&A during the fourth quarter is expected to be $19 million.

We are currently projecting our effective tax rate to be approximately 35% in the fourth quarter. Given current market conditions, we do not expect to pay meaningful cash taxes through 2016. In general, with both drilling and pressure pumping, we remain very focused on reducing cost and protecting our balance sheet.

With that, I will now turn the call back to Mark for his concluding remarks.

Thanks, Andy. A popular saying is, the cure for low prices is low prices. This axiom refers to economic theory and the law of supply and demand, but it is also Darwinian. The rebalancing process, and more specifically the required rationalization for low prices to cure low prices, is a painful process whereby the weak may not survive.

Across the industry, evidence of this has already started to appear, with some companies reporting financial distress and others having thrown in the towel and shut the doors. The level of maximum pain has not yet been felt, as we believe industry activity in both drilling and pressure pumping will fall further into year-end and continue to fall into 2016, absent a recovery in commodity prices.

Pricing and pressure pumping has already reached a point that we believe is not sustainable. At current pricing levels, we believe many companies are not generating sufficient cash flow to cover maintenance capital. Under these circumstances, we believe some companies are deferring maintenance, and some equipment is being cannibalized.

While we are not immune to the evolutionary changes being forced on the industry, we are well-positioned it a market being driven by survival of the fittest. We have demonstrated our strength in terms of quality equipment, superior execution, and importantly, financial stability.

We believe our overall fleet in both drilling and pressure pumping is of the highest quality. We believe that high-spec rigs such as our APEX rigs are still the rig of choice for E&P companies. In a recovery, we expect our APEX rigs will be among the first rigs to go back to work.

Similarly, our fleet of modern pressure pumping equipment has an average age of only four years, and has been well-maintained so as to provide a high level of service to our customers. In drilling, we have efficiently managed this business, scaling our operations both up and down as needed. As labor is our largest input cost, we have scaled our US drilling headcount proportionate with the decrease in our rig count. In pressure pumping, we have scaled our business and worked with our vendors to reduce input costs to soften the impact that lower activity and pricing has had on our margins.

While this downturn is painful, I am encouraged that we continued to be EBITDA positive in both of our core businesses during the third quarter. Most importantly, we're financially strong. The rationalization during the rebalancing of the industry does not occur overnight.

We do not have any visibility into the timing of a recovery, but history tells us that the deeper the downturn, the healthier the industry is on the other side of the downturn, and the stronger the recovery for the companies able to make it to the other side. The strength of our balance sheet and the level of our liquidity give us time to weather this challenging period. With that, I am pleased to announce today that the Company declared a quarterly cash dividend on its common stock of $0.10 per share, to be paid on December 24, 2015, to holders of record as of December 10, 2015.

Operator, with that, we'd like to now open the call for questions.

(Operator Instructions)

Marshall Adkins with Raymond James.

Let's, if I could, spend a little time on the pressure pumping side. You know, the margin the last few quarters has been all over the board. Despite the fall-off this quarter, you are doing meaningfully better than your peers. But I want to understand what's driving the sequential decline. Is it geography? Is it something else that happened? Give us a little more color on that decline quarter to quarter.

In terms of how the decline played out for us in the third quarter, especially versus what we had discussed in terms of projections, there were some moving pieces there. One of the challenges is, as we've had to stack some of our equipment -- we were at 33%, and then by the end of the quarter, we were at 38%. When you get down to those lower levels of frac crews, when a frac crew gets delayed on a pad for any reason, it all of a sudden becomes a big impact. Whereas, a year ago when a frac crew gets delayed, the impact is muted just by the overall activity and the revenues we were generating.

So with the work that we still have, there's still movement in a typical frac schedule, but the impact is larger for us when we get those delays on a pad. There's some level of activity that you can predict, but some gets a little bit more challenging, especially in today's environment. The commodity price changes haven't help that either. I don't know if that helps you out any.

That helps a bunch. We've heard a lot of your competitors talk about cannibalization of their fleets as things -- just cutting off all CapEx, even maintenance, and letting the fleet size dwindle. What's going to be your approach to that? And assuming there is an upturn, as we think there will be later in 2016, how are you going to be prepared for that?

As Mark said, we are still EBITDA positive in this business. We're very pleased with that. We're very focused on the margin and controlling the cost today, trying to reduce costs further as we work through this into next year. And we're still maintaining our equipment. We think that there are other companies out there that are more stressed than we are. So therefore, we do believe there is some cannibalization of equipment that's happening.

With the equipment we've stacked, we've just parked it, we preserved it, we are not touching it. We're still maintaining equipment through maintenance capital and through OpEx. I'm pleased with the high level of service quality that our crews are still able to provide out there in the field, because of the way that they're running the operations today. It makes us competitive in this environment, and you have to stay competitive in this environment.

Your fleet size, in essence, you don't see deteriorating meaningfully over the next year, 18 months? Is that what I'm hearing?

That's what you are hearing. We go through a preservation process, whether it's drilling rigs or pressuring pumping equipment, when we stack the equipment, just to make sure everything is tight and it's going to be there when we need it in the future. Don't know when that's going to be. But we are not pouring fluid ends off of pumps that are parked on the back side of the yard.

Last one for me. You are still putting up better margins, better performance than most of your peers. What's allowing you to do that? I just want to understand. Is it the type of pumps you have? Or the geography? What dynamics do you think are allowing you, even in this ugly environment, hold up margin and performance better than the average guys?

That's a good question. We don't always know what is in everybody else's margins. But let's kind of back up to how this downturn began to play out early in the year. We have a drilling business and we have a pressure pumping business. We had a lot of market knowledge from our drilling business, as to the first three to four months, a lot of discussions with customers as to how quickly rig count was going to come down. And I think because of that, we were fast movers on the pressure pumping side to scale that business quickly and keep the size of that business in line with the activity levels. We could see, with the visibility that we have, through the market knowledge of the drilling business, how fast things were going to move in this downturn. We all saw that rig count move really quickly in the beginning.

Okay. Thank you all very much.

Sean Meakim with JPMorgan.

Starting out on the drilling side, as we look at 2016, are the contract expirations fairly steady throughout the year? Could you give us a rough sense of the cadence?

Offhand, I don't know what that looks like. But that's a safe assumption if you are working that into a model.

Okay, fair enough. Have you seen any further day rate pressure in, if you can call it, a spot market? As we look into 2016, are there any material levers to cut cash costs on the drilling side?

On the drilling side, when it comes to the market, there's not a lot of trades out there to actually call what a spot market is, and things vary from region to region for various reasons with different customers today. But there's just not a lot of trades on drilling rigs. You're seeing that rig count continue to go down. So it's safe to say there is some pressure on pricing in that market.

When it comes to the cost side, if you look at our daily cost in contract drilling, two-thirds of that is compensation and the people that we have out there working on the rigs, and then one-third is our variable. We continue to work on that variable piece. We're certainly going to stay focused on trying to reduce that where we can. And overall, we're going to continue to scale the business, whether drilling or pressure pumping, with any changes in levels of activity.

That's fair. And one last question, just to take that over to the pumping side. It looks like completions activity will take another leg down. You mentioned most of the cost reduction efforts were in the second or third quarter, understandably. Is additional stacking the last major lever, as we take another leg down activity in 2016?

Well, first off, what we were trying to explain is that our achievements in working with our suppliers and reducing our input costs in that equation on the P&L for pressure pumping, most of that occurred in the second and third quarters, but it doesn't mean we are done with that either. It just means that any further cost reductions aren't going to give you the same double-digit percentages that we got earlier in the year. They're going to be more in that single-digit percentage range. But we're going to continue to try to work costs out of the system. And in terms of stacking any equipment in the future, if you look at what we are guiding for the fourth quarter, we could possibly stack a similar percentage in the fourth quarter that we did in the third quarter. We just don't know yet.

Okay, fair enough. Thank you.

James Wicklund with Credit Suisse.

Mark, I'm going to be in your neck of the woods on Saturday, if I can buy you lunch, by the way. You never return my emails, so this is the only avenue I've got. (laughter) On the quarter, it's obvious that things aren't good and they are getting worse. You guys are going to survive. People is always a big issue. I know you are still cutting people, so it's premature to ask. But when things do turn, what is the likelihood or the difficulty of the challenges to getting people back to the industry? And will that be a constraint to the eventual recovery?

I will take that this morning, Jim. I will start by saying, it's unfortunate we've had to scale the business. Patterson-UTI Energy was in great shape, in terms of the people that we had in the field last year. So we certainly don't like how we've had to scale for this particular downturn. But that being said, we've got a lot of great people still left in the Company. As we eventually work our way out of this, when you are trying to get people back, if they've only been gone in that first three to six months, there's a good chance you get some of those people back in the oil field.

But after that, it gets more challenging. But as we've seen in other cycles, when we've exited these down cycles, it is that people equation that gets tight. While we talk about equipment a lot, whether it's rigs on the sideline or the stack pressure pumping equipment, at some point, the people equation is going to tighten up on us -- and possibly sooner than the equipment piece of that equation.

Okay, that's helpful. Mark -- opportunities. You note that you are in a better position with your balance sheet and positive EBITDA than a lot of other companies. I know on the Q2 call, everybody talked about the eventual M&A. We're still not seeing it particularly happen, but we're one quarter closer. Can you talk about what might happen strategically in the drilling markets and pressure pumping markets over the next year and half as we go through the bottom of this bathtub?

Well, Jim, I'm happy for you to call it the bottom. (laughter)

Long bathtub bottom.

Okay. But in any event, the way I think we are seeing it is that, as we've seen downturns before -- and admittedly, this one is deeper and more protracted -- you want to think about when the best opportunities arise. Frankly, at this point in the cycle, as we see it, protecting our balance sheet is one of the most important things that we can do, and so one of the things we have focused on. That's obviously something that was said in our prepared remarks before we started.

As we look at the M&A landscape, the way I see it is that there's a number of companies that are in some distress of one kind or another. I suspect those will turn into opportunities. Whether they will be opportunities for us depends on whether the quality of their equipment is such that we would find it attractive and it would really add to Patterson, and whether we could do so in a way that would be positive for our balance sheet. So as I look at it at this moment in time, I don't see it. But that's not to rule it out.

Is there a strategic benefit to being significantly bigger in drilling or pressure pumping, somehow?

I think that being bigger is never the objective. Being better is always the objective. That's the way we've run the business for the past 20-plus years. Better is real important, but bigger is sometimes a benefit.

Okay. Thanks. Appreciate it.

Thanks.

Kurt Hallead with RBC Capital.

I was curious on two fronts. Andy, not too long ago, when we were on the road on this investor road trip, there were questions about reducing costs further. And you went through everything that you've gone through on the call so far, but then there was also a reference to that there could be a possibility to finding ways to reduce, labor costs further if you felt that there was going to be an extended downturn. I don't know, it kind of feels like an extended downturn to me. Was looking to get some updated viewpoints from you as to how you are assessing the downturn now.

The downturn certainly is extending, I think, from what people had talked about a few months ago. But in terms of cuts to individuals' compensation and wage cuts, especially for people that are working hard for us out in the field, we're just not quite there yet. And it's a little bit different scenario than the downturn that we had 2009-2010, where the general labor market around us evaporated as well. But in this particular case, there still is a labor market around us. And we have to make sure that we're relatively competitive in the labor market. We also want to make sure that we're retaining the best people we can for the eventual outcome of this down cycle.

Okay. And a follow-up to that would be in the context of your comment, Terry, about stacking equipment. And just want to make sure that I understand the way you are looking at it correctly. Effectively, you are ring-fencing the equipment and not cannibalizing it. I want to make sure I understand that correctly. And if that is true, I'm a little bit puzzled, because isn't it one of those deals where, if you are not cannibalizing equipment, you're going to have to pay to maintain what you've got? So you're either going to pay now or pay later? And if things are tight now, why put the money forth to maintain stuff when you could just take it from the yard?

The way you stated it is correct. We're essentially parking the equipment, we're doing a preservation process, we're ring-fencing it, and then we're not touching it. In other words, when it's time to replace a fluid end on a pump, we're not taking a used fluid end off a pump that's at the back of the yard and putting it on a pump. We are taking the new fluid end, as we would normally do. We're still running a high-quality operation out in the field. We still have customers that expect high service quality, even though it's a very challenging market and the pricing has gotten very competitive.

But we're still spending maintenance capital and OpEx because it's the right thing to do to run a high-quality business. The cannibalizing, it's inefficient. You're taking used components off of pumps or engines, and then you're using used components. And then all you're doing is deferring the maintenance. You're going to have to buy that part down the road anyways. We're still EBITDA positive, and it's still the right thing to do for our customers to keep our service quality up.

Okay. On the context of the maintenance and everything else, it seems like there's been a big deal made of this transaction between Schlumberger and Energy Recovery, and everybody is extrapolating that it's going to mean obsolescence of the way things are being done right now. I know it doesn't necessarily happen that way in this business, because it's more evolutionary than revolutionary. But do you have any perspectives on that kind of technology and some things that you may be looking at to reduce maintenance cost and extend the lives of the stuff that you are using?

I think from our standpoint, all we know about that technology today is that it had some early trials up in the Bakken, had some good results, and certainly, obviously was interesting to Schlumberger to go after that. I think we'll just have to wait and see how that works out, in general. The market for pressure pumping is very large, and any disruptive technology would certainly take a long time to work its way through the market.

I appreciate that color. Thanks.

Byron Pope with Tudor, Pickering, Holt.

On the contract drilling side of the business, just trying to think through in an environment where you've got 200 marketed rigs now, and if we are in an environment where you're working maybe 5 to 90 for a while, can you help us think through your approach to maintaining the idle rigs so that they are in a position to go back to work? And in the context of your overall fleet daily average cost, I'm just trying to figure out if there is some potential to see those gravitate lower when the eventual recovery does take hold? If you could provide some color on that, that would be helpful.

I will answer part of that, and I just want to make sure I understood your question. With the rigs that we are stacking and that are idle, we go through a very basic preservation process, but we're not spending anything in terms of maintenance. There's no carrying cost there. There is no cost associated with an idol rig, in general.

So there's nothing to do in that particular case until the market actually starts to move in that direction and we get into direct discussions with customers, that we would want to look at an idol rig and decide what to do with it. Was there anything in particular that you wanted to know about that?

And then when you get to that point, assuming that there wouldn't be much in the way of incremental capital required to basically put that rig back to work?

That's correct. There's no real incremental capital there. They were working rigs when they were stacked, and you make some very minor things, but not much, to get that rig back out and get it back to work.

Okay. Then a quick question on the pressure pumping side. Just thinking about what I heard so far with regard to the asset write-downs. It doesn't sound as though you've taken any steps with regard to your logistics infrastructure. I'm assuming that is staying intact so that you can service both of your geographic regions whenever well completions activity does start to tick up?

That's correct. No change to our logistics infrastructure. On the equipment side, on that pressure pumping write-down, we had some older nitrogen equipment that we used to use in the Northeast, but there's not much of a market for that anymore. In terms of hydraulic tax rate horsepower, it was less than 10,000 horsepower of older pumps.

Okay, thanks. Appreciate it.

Thanks.

James West with Evercore ISI.

Andy, on the rig side of the business, I know you mentioned earlier there is still pricing pressure, even on the high spec side, with your AC rigs or your APEX rigs. But has anybody -- are you seeing your competitors -- I know you're not going to give me a number or anything, but have you seen the major suppliers of rigs started to break ranks here and really lower day rates significantly? It seems to me like the big four had said: all right, we are not going much lower, we're going to keep it margin. Is that still the case, or are you starting to see some guys become undisciplined?

As the rig count inches its way down, it is getting a little bit more price-competitive. The good news about that market is, the players in that market, although we're highly competitive, there is still a little bit of discipline. Again, you know, it is getting more price-competitive. I think that is about the most I can say on that.

Okay, fair enough. And then Mark and Andy, probably for both of you, but on the M&A side -- I know the question has been asked, and I've been pushing for a couple quarters on M&A. But my view has probably changed recently, given that we are about to see two horrific quarters in a row in the fourth quarter and the first quarter, and a slow recovery here. Why even look at buying companies at this point? Why not just let these assets go away and just leave the market?

I don't think we said anything different from what you've just said. (laughter)

Fair enough.

I mean, the short answer is, we understand that the outlook is not particularly favorable for the next quarter. You went further, but we're certainly agreeing with you for next quarter. That's clearly driving a lot of people's thinking, or certainly our thinking, about what kind of activities there are on the marketplace.

Got you. Okay, great. Thanks, Mark.

Robin Shoemaker with KeyBanc Capital Markets.

Most of my questions have been answered. But I was just wondering if, at this point, although it's only late October, you've had any indications from your customers about the 2016 budget process, as we reload the budget cycle and go into next year? Clearly, you see it's going to start out low. But is there any light you can shed on that? Have you had any kind of indications at all about what some of your customers are thinking or planning for the next year's budget cycle?

No, and I think it's just too early. I think you're going to see the E&P companies defer some of these decisions as long as they can. I think most of our customers, in that respect, have just been quiet. We just don't expect a lot of visibility on some of their decisions for a little while to come.

Right, okay. The question I had was on, with the very low level of investment, you're talking about not building APEX rigs or building new frac fleets. Did you give a figure as to what your CapEx would look like next year under those assumptions -- which is basically a maintenance level for rigs and fracking fleets?

Yes, what we said was that we haven't completed our 2016 budget. Like you mentioned, we don't expect to build any rigs or buy any pressure pumping equipment, in terms of frac horsepower. We currently expect that the 2016 CapEx budget will be primarily maintenance capital, and we expect that it would be less than $200 million.

Okay, all right. Thanks.

Scott Gruber with Citigroup.

Andy, you just mentioned there's an overall lack of clarity with regard to customer budgets, which we all know about. But we did hear from the diversified service companies their expectation that the rig count here in the US would recover over the course of 1Q to offset the 4Q drop that's underway. How are you thinking about that dynamic? Is that possible, is that unlikely, in your view?

The most visibility we have today -- we've given you the projections that we see the rig count continuing to go down in Q4. We also see a downward trajectory in the rig count as we enter 2016. Don't really know what the timing of that's going to look like or certainly when we get to any inflection point. So that's really about all the visibility we have today.

Got it. And then the APEX SCR rigs that are still operating today despite the low level of activity -- are all those operating under term contracts? Or are there some of them that are simply competitive with AC rigs, given the quality of the asset and the crew?

Yes, it's a mix. And all of our APEX rigs compete as high-spec rigs, and there is very little difference in what they command in day rates, whether it's term contracts or in whatever spot market we have today.

And then if I could just ask another on frac. I believe Universal was operating about 100,000 frac horsepower before the shale revolution hit. How much of that remains today, even if it's in a cold stack mode?

Of the original horsepower from pre-2010? I think, there might be some. But it would be a very small amount.

But have you been retiring some of that legacy equipment?

Yes, and we have over the years. You've seen that in some of the numbers when we've done write-downs over the years. If you look at the average age of our total hydraulic fracturing horsepower today, it's right around four years.

And the assets impaired during the quarter, I assume those are sent for scrapping?

They will be, yes. It was under 10,000 horsepower of frac horsepower.

Got it. Good for me, thanks.

Thanks.

Chase Mulvehill with SunTrust.

On your term day rates, how should we be thinking about that? You talked about the pricing pressure that is starting to come back into the market as activity is declining. Are your customers coming back to you and asking to renegotiate term contracts?

You know, the term contracts are still holding up. We're going to work with the customers wherever we can within the boundaries of that term contract, but the term contracts are still holding up.

Okay. And could you walk us through the components of your gross margin per day guidance? What's the revenue per day and the OpEx per day imply?

I don't have that in front of me.

Okay, all right. Moving on to pressure pumping, what are you seeing for frac sand pricing? Has that stabilized? And if it has, what do expect frac sand pricing to do into the fourth quarter?

I wouldn't expect, given the projections that we've talked about this morning, that any of these input costs have stabilized for us. It's just that the challenge is, we've got the majority out of the cost, out of the system, in the second and third quarters. But I expect that we will get more concessions, but they're going to be much smaller than they were earlier in the year.

Okay. And how much our of your horsepower is currently working 24 hour?

It had been as high as 90%. It's probably still close to that level, but I don't have that number in front of me.

Do you expect that the 24-hour will be the first place that you see utilization come off? Or do you think it will be on your non-24 hour stuff?

What we've seen in terms of utilization is, we've seen operators to take a 24-hour crew and take that to 16 hours or 12 hours a day. And it's really just a function of the frac inventory, with just less wells per month to frac. We've seen that already, which is why -- I know we've had a decrease in that percentage of 24-hour, I just don't know what it is offhand.

Okay, all right, that's helpful. Last one. Let's see, so maintenance -- you talked about CapEx potentially for next year being mostly maintenance, which would be less than $200 million. I think in the Barclays presentation, you guys talked about $100 million of carryover CapEx? Is that now not going to happen?

I'm going to hand that over to John.

Just to clarify a little bit on the CapEx, Andy's comments of less than $200 million, that's correct. But probably about one quarter of that is carryover items, projects that started earlier in the year that are of an upgrade nature, et cetera. In a true maintenance mode, it would be -- if we just called it $200 million -- although it's less than that -- it would be much less. And if the drilling activity or the pressure pumping activity further deteriorated, it would go even lower.

So we're not meaning to suggest that maintenance capital is $200 million; that's activities-driven. On current levels of activity, we think that is something less than $200 million, with about a quarter of it being carryover for non-maintenance items.

Got it. All right, thanks, John. Thanks, Andy.

Thanks.

Marc Bianchi with Cowen and Company.

If I could just follow up on Chase's question about frac sand pricing. Could you put some numbers around that, what you've realized through that second quarter, third quarter, and what you are seeing quarter to date?

I think we said early on that -- and even in the last presentations we've given at conferences -- that we've seen frac sand pricing come down in that 25% to 35% range since the beginning of the year. Just what I'm trying to explain today is, there could be some further price reductions for us on sand, which is great pass-through for our customers, but it's probably moving into that single-digits.

As our projections show, rig count is going to come down, which tells you that overall frac activity is going to come down, and you've seen that in our numbers. So I do think that there's probably room to get some more of the input costs down. It's just that the majority of these percentage decreases that we've received were earlier in the year, and it's just probably not going to be double-digits moving forward.

Sure, makes sense. Thanks for that, Andy. With the pressure pumping guidance you are offering for fourth quarter, and the revenue and margin, it looks like decrementals are pretty small. So I suspect there's not much pricing expected in there? That's all activity? Or maybe that's wrong. Could you give a little bit more color on the top line there?

I would say it's more towards the activity. Pricing is still tough; it's very challenging right now. But looking at our projection relative to Q3, some of our numbers for Q3 were the result in activity that we thought we were going to have, where a pad just got delayed. And when one pad gets delayed today, it hits the numbers pretty big. And we also had some pricing declines in the third quarter. But I would say it's more toward the activity side in the fourth quarter.

Have you gotten any indication from your customers -- and this could go across frac and land drilling -- where there's holiday slowdowns activity being stalled, but some sort of expectation that a portion of that will be resumed in the first quarter? And is there any way to put some numbers around that?

It's hard to say exactly how it's going to play out into the first quarter. But I mentioned earlier that in terms of rig count on the drilling side, we're seeing the rig count go down for the fourth quarter. And we see that trajectory going down entering the first quarter. So there is a little bit of extrapolation there to pressure pumping activity.

Got it, okay. Thanks, Andy. I'll turn it back.

[Ry Drizzen] with Victoria Advocate.

I just wanted to ask you, in this price environment, where are you seeing the most activity in demand for your rigs still emerging from? Especially when you're talking about Texas, are you talking about places like the Eagle Ford and the Permian? And if you can go into detail, what sorts of areas or counties are you talking about?

We work in all the major basins across North America in drilling, with the exception of California. And in pressure pumping, we work in the Northeast across multiple states, and then we work across Texas and New Mexico today. We're seeing pricing pressure in all these regions. I wouldn't say that it's -- that there is any pricing any better in any one region. Because in this level of downturn, where you've got -- since the peak, we've had roughly 59% of the rig count drop. We've just got pricing pressure across all basins today.

Okay, thank you.

John Daniel with Simmons.

Just a quick one, Andy. On the $9,700 cash margin guidance, is that including or excluding the contract termination payment?

That would be excluding the contract terminations, and we are estimating about $9 million right now in potential contract terminations in fourth quarter.

Okay. Follow-up on the CapEx questions. But adjusting for the carryover, it seems like the maintenance number is more like [$150 million] for next year. What percent of that CapEx is tied to pressure pumping?

We haven't even worked up the full budget yet for 2016, and we're just trying to give everybody some round numbers, because we know there's a lot of questions around potential cash flow. So I don't have that offhand in front of me. But it's going to be roughly about half.

Okay. And would that number include any rebuilds on the equipment?

We continue to maintain the equipment, and where a transmission rebuild is required, it's going to be part of maintenance capital. We're still running a high-quality service.

But this would be just replacing the component parts, as opposed to a full-blown rebuild, correct?

It depends on what it needs. We're not changing the maintenance schedules. We're still maintaining engines, transmissions, pumps, as we normally would.

Okay. A question on M&A. The consolidation you mentioned, it's not about the need to get -- it's the need to get better versus the need to get bigger. So specifically as it relates to pressure pumping, but if the industry is cannibalizing equipment and deferring maintenance, and you guys are not, would acquiring any of your pressure pumping peers make you better?

I think the answer is, we don't know. It would all depend on what it was, and the quality and conditions of the equipment at the time.

It certainly alters the valuation equation when you're looking at the equipment.

Okay.

But John, we've always taken into account the quality of the equipment every time we've ever looked at an asset that we've been interested in acquiring. So it would naturally follow that under these circumstances, we would do the same -- particularly, this time, I suspect, with heightened sensibility.

Okay, fair enough. On the 10,000 frac horsepower that was --

Hello, John?

Can you hear me?

We lost you for a second.

Okay, sorry about that. The last question for me is just on the pumps that were written off, the 10,000 horsepower. Was that damaged equipment, or was there a financial calculation that triggered that write-off? Just any color, because it seems pretty small, given the size of your fleet.

They were just older, smaller pumps, that's all.

Okay, all right. Thanks.

Jeffrey Campbell with Tuohy Brothers.

In your major operating regions, do you have any visibility concerning which ones have the most significant DUC inventory currently?

No, and it's really by customer, because different operators have different levels of DUC inventory versus others. There's a lot of discussion around how that plays out as we come out of a down cycle. Does pressure pumping go back to work quickly, based on those DUCs? I think it really depends on the operator. I think certainly for us, we will be fracking some of these drilled but uncompleted wells that are in inventory, when we come out. But I think at the same time, you will see our rig counts start to inch up, as well.

Okay, thanks. The press release said that there was still value in maintaining Patterson's 19 mechanical rigs, even though they won't contribute much to future earnings power. Could you just give us a little color on what the tactics are there?

Sure. We don't expect these rigs to make meaningful cash flow. But we still have customers that are working in a difficult market environment right now, and we still want to be able to service a few of these customers. And these rigs may help some of these customers out as we work through this. This allows us to meet some of their needs. It also would potentially allow us to keep some people busy. We want to do that where we can. I think the main point on these rigs is that the valuation is down to $13 million.

Right. So really, the idea is just to keep some things going and hope that that will matriculate up to better equipment at some point in the future?

That's it, yes.

Okay, perfect. I'd like to return real quickly to the preservation process for the stacked pressure pumping equipment that we've been talking about. I just wondered, is that an ongoing part of your maintenance budget, or is it a one time spend when you stack? And what level of costs are we talking about here, anyway?

It's certainly not ongoing. Once equipment is stacked, there's no need to spend any money on it, and preservation is very basic. We're just talking about making sure that systems are sealed up so that weather doesn't interact with things, and then you put it away. That's it. There's not much to it.

Okay, great. And finally, just returning to the energy recovery question, but a different way. I was just wondering if there's any other technologies out there that you are aware of or considering that might initially reduce the cost of pressure pumping in the future? I think one reason we're all interested in this is because we hear E&Ps talk a lot about trying to successfully reduce cost on the drilling side. But we hear a lot less about it on the completion side, except maybe input costs, like lower sand and stuff like that. Just wondering what you thought about that?

There's ongoing projects in these areas. In our particular case, we're looking at chemistry on fluid ends. We continue to trial different material chemistries, different types of forgings, different blends of nickel and chrome in the material, to try to see how we can reduce corrosion and extend the life of fluid ends. There's various things that are happening all the time in that area. And we're doing what we can to extend the life of these components and get our costs down so we can stay competitive.

Okay, thanks very much. I appreciate it. Thanks for getting me in.

Jason Wangler with Wunderlich.

Just had one quick one on the early terminations obviously coming down pretty significantly in the fourth quarter. Can you just comment -- I assume it's a lot of just rolling over of some contracts. But as you look into 2016, is that really going to become something that even gets more minimalized?

At this point, it's hard to say how that's going to look in 2016. We're just trying to give you a little bit of feel for how we think it might play out in the fourth quarter. We had them in the third quarter. We've had them in every quarter this year. But right now, it's a little bit early to know what's going to happen in 2016.

Okay, well, that's helpful. I appreciate it.

Judson Bailey with Wells Fargo.

I wanted to ask a question, either Andy or maybe John. Help us think about your margin per rig day on the land rigs side, maybe beyond the fourth quarter? Andy, you indicated margin per rig day is going to be up in the fourth quarter, just primarily from mix. If your rig count is down again slightly, say, in the first quarter, does margin per rig day go up a little, just because you are getting rid of -- you still have most of your higher-priced rigs under term contract? And then as things start to improve, is there any guidance you can help us with to think about how that margin per rig day may progress if things stay down for a while?

I think you are getting a little further ahead from the visibility that we have. We're certainly pleased that our mix on the APEX rig is improving towards the APEX in the fourth quarter. It's helping us out. That's a great rig for us. I did mention the trajectory would continue down into Q1. But as terms of what the total mix will look like by the end of Q1, it's just going to be too early to know what that is right now.

Okay, that's fair. My follow-up would be just that the rigs you have under term contract for 2016, is it fair to assume that most of those, if not all of them, are going to be your most recently built APEX rigs in the last couple of years, the term contracts at peak rates?

That's correct. These are mostly APEX rigs built in the last two years, at this point.

Yes, okay, thanks.

Thank you, and I'm showing no further questions at this time. I would like to turn the conference back over to Mark Siegel for any further remarks.

Operator, thank you. And to all who participated in our third-quarter 2015 call, many thanks. We look forward to speaking with you after the fourth quarter. Thanks, everybody.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may all connect disconnect. Everyone, have a great day.