Patterson-UTI Energy Inc (PTEN) 2016 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to your Q4 2016 Patterson-UTI Energy earnings conference call.

(Operator Instructions)

As a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference, Mr. Mike Drickamer. Sir, you may begin.

Thank you, Nelda. Good morning, and on behalf of Patterson-UTI Energy, I'd like to welcome you today to the conference call to discuss the results of the 3 and 12 months ended December 31, 2016. Participating in today's call will be Mark Siegel, Chairman; Andy Hendricks, Chief Executive Officer; and John Vollmer, Chief Financial Officer.

A quick reminder that statements made in this conference call that state the Company's or management's plans, intentions, beliefs, expectations or 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 for 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 call include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included on our website www.patenergy.com, and in the Company's press release issued prior to this conference call.

And 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 fourth quarter of 2016. We are pleased that you are able to join us today.

As is customary, I will start by briefly reviewing the financial results for the quarter ended December 31, and then provide an update on our pending merger with Seventy Seven Energy, before turning the call over to Andy Hendricks, who will share some comments on our operational highlights, as well as our outlook. After Andy's comments, I'll provide some closing remarks before turning the call over for questions.

Regarding the fourth quarter, as set forth in our earnings press release issued this morning, we reported a net loss of $78.1 million or $0.53 per share on revenues of $247 million. Total adjusted EBITDA during the fourth quarter was $44 million.

Turning now to our pending merger with Seventy Seven Energy. We continue to make progress towards closing this merger, which we expect to be completed late in the first quarter, or early in the second quarter. In January, we received early termination of the Hart-Scott-Rodino waiting period, and filed our initial Form S-4 registration statement with the SEC.

Recently, we also completed an equity offering of 18.17 million shares, including the exercise of the underwriter's over allotment option. We intend to use the net proceeds from the offering of approximately $470 million to fund the repayment of Seventy Seven's outstanding net indebtedness upon closing.

At September 30, 2016, Seventy Seven Energy had $475 million of gross debt, and $23 million of cash for a net debt of approximately $452 million. The proceeds received from the equity offering, along with our revolver assure that we have sufficient cash available to repay the outstanding debt at Seventy Seven Energy. Any proceeds from the equity offering in excess of what is needed to repay the debt of Seventy Seven Energy and the transaction expenses will strengthen our own balance sheet, and provide for increased financial flexibility.

As previously announced, we also entered into an agreement with certain lenders under our revolving credit facility to increase the aggregate commitments by $96 million subject to certain conditions, including the completion of the merger with Seventy Seven Energy, and the repayment and termination of the Seventy Seven credit facility. We are pleased with the increased financial flexibility afforded us by the increased liquidity. We believe the strength of our balance sheet will continue to provide us with a competitive advantage, a differentiator affording us opportunities that more financially challenged companies will not have.

While conditions are improving, the financial challenges for our industry are far from over. Reactivation expenses, upgrade CapEx, and increases in working capital will be uses of cash for the industry.

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

Thanks, Mark. In contract drilling, our rig count during the fourth quarter averaged 66 rigs in the US, up 6 rigs from the third quarter, while our rig count in Canada was unchanged at 2 rigs. As a reminder, our reported rig count is based on the average number of rigs generating revenue, which includes rigs on standby that are receiving a standby rate, but not actively drilling. In addition to the six rig increase in our US rig count during the fourth quarter, our average number of rigs on standby decreased by five rigs, therefore, the increase in our active rig count was in line with the US land industry rig count.

Total average rig revenue per day for the fourth quarter was $21,640, compared to $21,870 during the third quarter. This decrease is a function of rigs that were reactivated, as well as the recontracting of rigs that rolled off higher day rate term contracts.

With a five rig decrease in our standby rate count during the quarter, the proportion of days on standby decreased to 4% in the fourth quarter, from 13% in the third quarter. Rigs on standby have very low associated costs. As a result of the significant reduction in the proportion of rigs on standby, total average rig operating costs per day during the fourth quarter increased to $13,770, compared to $13,180 during the third quarter.

Without the decrease in the proportion of rigs on standby, total average rig operating costs per day would have decreased, as a result of fixed costs being spread over more operating days. As a result of these changes, total average rig margin per day decreased to $7,870 during the fourth quarter from $8,690 during the third quarter.

Included in average rig revenue per day and average rig margin per day in the fourth quarter is approximately $190 per day of early termination revenue, down from approximately $200 per day of early termination revenue in the third quarter. While we expect some early termination revenues in 2017, the impact to average rig revenue and margin per day is not expected to be significant.

At December 31, we had term contracts for drilling rigs providing for $417 million of future day rate drilling revenue. Based on contracts currently in place, we expect an average of 44 rigs operating under term contracts during the first quarter, and an average of 37 rigs operating under term contracts during 2017. Looking forward, during the first quarter, we expect our rig count will average 80 rigs in the US, an increase of 21% from the fourth quarter.

In Canada, we expect our rig count will average two rigs during the first quarter. Please remember that the rig count in Canada during the second quarter will be affected by typical seasonal factors.

Average rig revenue per day is expected to be $20,900 during the first quarter. This expected decrease is a continuation of rigs being reactivated, and the recontracting of rigs rolling off higher rate term contracts. Average rig operating cost per day is expected to be $14,100, reflecting a further reduction in standby days to about 1% of total rig operating days during the first quarter, from 4% in the fourth quarter.

Turning to our outlook for the US drilling market across the industry, we believe there are a limited number of super-spec rigs. We estimate approximately 375 of these rigs across the entire US, and we believe that most of the super-spec rigs in stronger markets such as Texas and Oklahoma are already contracted.

Within our own fleet, we have 65 super-spec rigs, of which 62 currently have contracts. Of the three super-spec rigs without contracts, one each is located in Appalachia, the Bakken and the Rockies. Absent upgrades or rig moves, we do not currently have any super-spec rigs available in either Texas or Oklahoma.

Where justified, we will further upgrade our fleet to meet customer demand for super-spec rigs. For a total upgrade cost per rig of between $1 million and $3 million, we have 39 additional 1,500 horsepower APEX rigs that can be upgraded to super-spec.

Given the strong customer demand for super-spec rigs, we have signed contract to provide for the completion of two new APEX rigs, the day rate for these two rigs are in the low to mid $20,000 range. The economics were favorable for these two rigs, as a substantial amount of the spend related to the components for these rigs were committed to prior to the downturn.

One of the new rigs being completed is a APEX-XK 1,500 that is expected to be delivered in the second quarter. This rig design has become very popular with our customers, given it's omni-directional walking capabilities, as well as our demonstrated ability to move this rig quickly between pads. In the Permian, we routinely move this rig from one pad to another in less than 48 hours.

The other rig to be completed is our new APEX-XC. This new design is the next step in the evolution of our original APEX 300 Series walking rig, and is complementary to our fast-moving APEX-XK. The APEX-XC offers a pad optimal design with greater clearance for walking over and around wellheads on a pad, larger drill pipe racking capacity for efficiently drilling longer laterals, and it will feature a higher torque top drive from Warrior, our rig technology company. This new APEX-XC is expected to be delivered in the second half of this year.

Turning now to pressure pumping. Pressure pumping revenues increased a stronger than expected 35% sequentially to $106 million in the fourth quarter, from $78 million in the third quarter due primarily to higher activity levels. Since mid December, we have reactivated two frac spreads that have since returned to work. Given the timing of the reactivations, the impact on revenue was minimal during the fourth quarter, but did add approximately $1.7 million to operating expenses.

Pressure pumping gross margin as a percentage of revenues was approximately 5.3% during the fourth quarter, up from 1.2% in the third quarter, and would have been higher, if not for the reactivation expenses. Our total cost to reactivate these two spreads was approximately $2 million per spread, which includes both capital expenditures and operating costs including labor.

Given the strength of our balance sheet, and the fact that our pressure pumping business was EBITDA positive for 2016, we were able to maintain our active equipment during the downturn, and did not cannibalize our idled equipment. Accordingly, capital expenditures to reactivate the idled equipment has been relatively low. We anticipate that the cost to reactivate idled spreads will increase in the future, but we expect to be able to activate the remaining idled spreads in our fleet for an average of approximately $3 million per spread, including both CapEx and operating costs.

In addition to the two spreads activated since mid December, demand has been strong enough that we are preparing to activate another frac spread, which will begin working early in the second quarter. Once this spread is active, we will have approximately 60% of our fleet of more than [1 million] frac horsepower operating. These spreads are being reactivated as a result of us having the confidence of steady work, and having met our previously stated price expectations. Looking forward, we expect pressure pumping revenues to increase 25% sequentially in the first quarter, and our gross margin as a percentage of pressure pumping revenue to increase into the low teens.

I would like to take a minute to mention some of our operational accomplishments during 2016, and to thank our employees for the significant amount of effort that was required to achieve these accomplishments. From the low in our rig count in late April, we have almost doubled our active rig fleet through reactivations, and since mid December, we have reactivated two frac spreads. I'm pleased that we were able to complete these reactivations while maintaining or improving our high level of execution.

Recruiting, hiring, and training the people for rigs in pressure pumping spreads is a large undertaking. While labor was generally available in 2016, the people are becoming harder to find. As a result, we significantly ramped our recruiting efforts in 2016 for 2017 activity.

During 2016, we hired over 1,200 employees, approximately 70% of which were returning Patterson-UTI employees. And I'm proud that once again Patterson-UTI has been recognized as a military-friendly employer. And with all of these new employees, we also ramped up our training efforts at the same time.

With our increasing activity and headcount, I'm pleased that our operational execution continues to improve, as non-productive time in drilling was once again reduced in 2016. As well, it's important to note that all these operational accomplishments were achieved while maintaining control of our costs.

Before I turn the call back to Mark for his concluding remarks, let me provide an update on several other financial matters. As a reminder, these comments are based on Patterson-UTI as a standalone company, and do not include the potential impact of the pending merger with Seventy Seven Energy.

CapEx for full year 2016 was $120 million, which was lower than our previous expectations, as some CapEx was deferred into 2017. For the full year 2017, we expect CapEx of approximately $350 million, including approximately $60 million of carryover spend. Excluding this carryover spend, CapEx includes $[115] million for rig upgrade and new builds, $80 million for rig activations and maintenance, $75 million for pressure pumping fleet activations and maintenance, and $20 million for E&P, Warrior, and general corporate CapEx.

We expect depreciation expense will decrease to approximately $155 million in the first quarter. SG&A during the first quarter is expected to be $18.5 million. We are currently projecting our effective tax rate to be approximately 36% in the first quarter.

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

Thanks, Andy. The pace of the recovery in our industry accelerated in the fourth quarter, and has remained strong through January. With industry rig counts having approximately doubled from the trough, we are encouraged, and believe that 2017 will be an exciting year for Patterson-UTI for several reasons.

First, after more than two years of scaling the business lower and cutting costs, we have been able to focus on growing the Company again. Second, we continue to progress towards closing the pending merger with Seventy Seven Energy. This merger further solidifies our position as a leading high-spec drilling company, and with this merger, we will have one of the largest fleets in the US pressure pumping business, a business in which scale provide efficiency.

Finally, we will further demonstrate that we are a leader in walking rig technology, with delivery of the first rig with our new proprietary APEX-XC rig design. This pad-optimal design incorporates greater clearance for walking over and around wellheads on a pad, and includes many of the features that are being sought by customers, as they remain focused on efficiency and high quality execution.

With that, I'd like to both commend, and thank the hard working men and women who make up this Company. We truly appreciate your continuing efforts. Also, I am pleased to announce today, the Company declared a quarterly cash dividend on its common stock of $0.02 per share to be paid on March 22, 2017 to holders of record as of March 8, 2017.

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

(Operator Instructions)

Angie Sedita, UBS. Angie Sedita, UBS?

Thank you. Marc Bianchi, Cowen.

Thank you. Nice work on the newbuilds, surprised to hear that the rates are up at that level at this point. Could you talk about where those are going, and maybe what it's going to take to get the rest of your super-spec rigs up to those kinds of rates?

Well, we certainly -- we talked about this at the last earnings call, that we see that rig rates are going to increase, as rigs continue to go out. And we've seen that. You see that in the numbers that we have discussed for the two new rigs that we're going to complete. And so, we were certainly encouraged with the favorable economics to complete these rigs. But I do believe that, with WTI in the range that it's currently trading at today that rig count continues to go up, and rig rates continue to go up as well.

Okay. Maybe switching over to pressure pumping. I guess, similar kind of question, you're seeing the 20% to 30% price increase on reactivating equipment that you had set previously. What's the mechanism to get the rest of the fleet that was already in the field to see those kinds of price increases? I'm just wondering if there's any sort of timing on customer agreements and contracts that we may need to wait for, or is it really just a function of what the market will bear?

It's really the supply and demand of the overall available active horsepower -- or the available horsepower in the market. And overall utilization is still not there for general pricing in pressure pumping. It's still at a level that we just don't consider sustainable.

We were very encouraged by the agreements that we worked out with customers who needed additional spreads, where we were able to get within that target range of 20% to 30% for that incremental spread. But it's -- we're still not at the level to push overall pricing in pressure pumping. But as we continue to activate spreads in the industry, we're pushing closer to those overall utilization levels in the industry.

Okay. Maybe just one more if I could. The margin improvement that you talked about for pressure pumping is also pretty impressive. And I know you guys -- incremental margins are probably not as useful these days, just because of all the sand everybody is pumping, but if we think about what that implies here, it looks like sort of a 60% type incremental in the first quarter.

Is there anything unusual going on in the first quarter that's contributing to that margin leverage, that would keep that from being the case going forward? Or how should we think about that, as we roll past first quarter?

In the first quarter, this is really a function of our increased activity with the new spreads that's coming out, and barring any operational delays based on things that are out of our control, we expect these margins that we're currently projecting.

Great. Thanks very much. I'll turn it back.

Kurt Hallead, RBC.

Hi, good morning.

Good morning, Kurt.

Let's see, where to start here? So in the context of the industry being short on super-spec rigs, and the fact you guys are able to get kind of a low [$20,000s] to mid [$20,000s] day rate on this activation, can you put that in perspective? Are we going to have to see a new round of newbuilds here going forward, from an industry standpoint, maybe start there? And does this kind of new day rate for these rigs act as a -- if you will, an upward pull on the rest of the industry? What's your perspective on those two things?

Certainly, we see it as a positive, that we were able to get these day rates for completing these new-build rigs. It's a positive for us, it's a positive for the industry. We don't have any plans currently to build any other new rigs. And overall, I think day rates have to come up further before we seek or complete newbuilds. But I am encouraged by the fact that the rig count continues to move up, and I think that because of that, pricing in high-spec rigs does continue to move up.

Okay. And then, the -- thanks for that. And then the follow-up I'd have would be on the frac side, and come around to the prospect to activate fleets at a $1 million to $3 million run rate. We obviously, have heard from a much larger player that, that number is going to -- for them, more like $10 million. So big, big discrepancy there, just trying to get a better feel for when you guys bring this out. I guess, your -- does it imply to us that your equipment is in great shape, and really doesn't take much to bring out of the yard, or is there something else going on, that enables you to have a lower cost?

I can't speak to anybody else, but our particular equipment is in good shape. The costs that we have associated with bringing out equipment, which has been $2 million so far per spread, and will be about $3 million on average for all of our spreads, is really based mostly on labor. But you've got some OpEx involved, you've got some CapEx involved, but in general our fleets are in good shape and don't require any change from the existing technology that we're using.

And then on the -- (multiple speakers). Yes, go ahead, Mark.

We also have a relatively younger fleet than some of our competitors, and that also helps us a little bit, too.

Okay. That's great. And then, one final follow-up on that front. You'd indicated in the past that you would need to see pricing 20% to 30% above whatever the prior points were for you to activate equipment. So clearly, I think we can infer that, that's what you're getting. Now in that context, is it also safe to assume that it's not only positive EBITDA, but it's substantially positive operating margin that you're getting, by activating these frac fleets?

It's certainly positive on the EBITDA, because we were positive for all of 2016. We're getting closer in terms of overall net, but I'll just say, in general, pricing is still not a level that we're happy at in pressure pumping. We're pleased that the economics makes sense for us to activate these spreads, but we would like to see pricing come up more.

Okay, great. Thanks for that. Appreciate the color.

Thanks.

Chase Mulvehill, Wolfe Research.

Hey, good morning.

Good morning.

So I guess, I had a question on pressure pumping. Once you close this Seventy Seven Energy deal, you'll have about 1.5 million in horsepower, so you got some really good scale. Is there -- we see some of these pure-play public pressure companies trading at some pretty racy replacement costs. Is -- would you entertain the idea of potentially spinning off the pressure pumping business?

Right now, we're trying to complete the merger with Seventy Seven, so the first focal point for us, really at this point, at this stage is, finish the merger. We will think about all the possible alternatives, but not certainly, until we get to a point where we've completed our merger.

Okay. All right. And then, we've heard a lot of anecdotes about increases in frac pricing over the last few months -- sorry, frac sand pricing over the past few months. Could you talk about your contracts, and when they -- if you have them, and when they might re-price, and things like that?

We're continuously discussing and negotiating with sand suppliers. We do see sand pricing moving up in 2017, and it's really specific on certain grain sizes. Without going into the detail, we're comfortable with the contracts that we have in place today. And our bigger concern in general is supply, but we're comfortable with the pricing we're getting, and we're comfortable with the supply that we have.

And so what are you seeing for price increases, how much are they up, off the bottom?

It depends on the grain size. It's varying by different sands right now.

Okay. You care to -- 40, 70, is it -- I mean, we talking 10% to 15% or more than that?

I would say that we have good contracts in place, and we're still very competitive in what we're buying sand for, and therefore what we're passing on as costs to the customers.

Okay. Awesome. That's all I have. Thanks, Andy, thanks, Mark.

Brad Handler, Jefferies.

Thanks, good morning, guys.

Good morning.

I guess, I'll focus on the drilling -- I'll focus on the drilling side. And yes, it's great to see, it's great to see that you're able to get something as high as the mid [$20,000s] for new-build contracts. And that can certainly speak to the demand for that super-spec, as you guys have been talking about for a long time.

I guess I'm curious what it should -- what it tells us, and what you are therefore anticipating about some of your older APEX rigs? So walk us through perhaps a reasonable rate disparity over time, or something that would make sense. I mean, we note that your APEX-SCR rigs are not just over 10% utilized. I guess, 5 out of your 42 are working for example. So what does it tell us about customer demand, and perhaps walk us through how you see a landscape for those, for the balance of your APEX fleet if you will?

Brad, I think it's very similar to previous cycles that we've seen in the industry, where the leading-edge technology will lead in the pricing, but it lifts all boats in general. And so, while we still have some APEX 1500 horsepowers that aren't back to work yet, we see that this leading-edge pricing on the completion of these newbuilds lifting the pricing on those APEX rigs when they do go back to work.

Presumably this is happening -- I don't know how you feel about this relative to other cycles, if you are seeing rate improvement before the utilization, it's obviously saying something about the preference for technology. Or at least so it would seem. And maybe that's a little bit different than prior cycles, or you would argue that's again, it's pretty much the same?

I would argue, the same argument I've been making for a couple of quarters now, is that when the rig count goes up in high-spec rigs that pricing goes up with it. It's just -- there's that type of market demand for the high spec and the super spec, of the high-spec rigs out there.

Fair enough. All right. A follow-up -- still on the rigs. But as you get deeper into your fleet, in terms of putting rigs back to work, do you expect we'll see the wobble of reactivation costs become more relevant? I understand you've taken care of rigs and all of that, but we have at least seen one of your competitors note that there are some costs, as it related to kind of getting them back to work. Is that something we might keep an eye out for, again, and maybe as you get deeper into reactivating rigs?

I would take you back to what we explained, in terms of our total CapEx projection for 2017. So of that, we said that $115 million was for the rig upgrades, and the newbuilds, and only a small part of that is for the newbuilds. A majority of that is for the upgrade. So we think that we have that budgeted for 2017.

And then, from an OpEx perspective again, just whether it's re-crewing, or if it's items that you're expensing in the process, is that -- again, is this something you think might weigh on the operating costs as you go forward?

Well, on the OpEx side, you certainly have the labor, and you're talking about adding rig crews, two to four weeks of carrying costs, before the rig starts up. But we've been seeing that, really, for the last two quarters now.

Anyway, so nothing different. Okay. Great. Thanks for the answers, Andy.

Sure.

Marshall Adkins, Raymond James.

Good morning, guys.

Good morning.

Just curious, we're building the two brand-new rigs here. Why not reactivate or upgrade some of the 1500s you have right now, rather than building brand new? Is it because you already have the parts around?

So I would say it's a combination of a few factors. So, one, we had inventory from 2014, when we had strong plans for newbuilds, so we had inventory that we had already spent cash on. So we were able to spend some incremental cash to get these rigs to work.

The other is, really just the demands for these two specific types of rigs. We were essentially booked out on APEX-XKs, and we had a customer who likes APEX-XKs, and was willing to help us finish off this rig. In the case of the APEX-XC, we had a particular customer that has a very large multi-well pad, a larger number of wellheads than a normal multi-well pad. And the APEX-XC, from a technical standpoint is a very good solution for his particular needs.

Okay. So the other 39 rigs you have to upgrade, are they going to be more like the XKs or the XCs, or something totally different?

Well, they're a little bit different from the XKs, and the XC is really the next step in our original 300 series, if you look at the rig numbers on our website. But we anticipate that these other rigs will eventually go back to work as well. And like I mentioned earlier, we think that the pricing that we're getting on the completion of these newbuilds lifts the pricing of these rigs as well, as the market continues to tighten.

All right. Last one on this. What happens to the SCRs you have left in the fleet? Do you see those potentially going back to work over time, or do we just use parts and pieces of those to upgrade and refurb the fleet?

No, we've kept rigs on our marketed list on our website that we believe can all eventually go back to work, depending on what the total industry rig count is at a certain time. We don't see these as parts for other rigs. We do see these as complete rigs that are eventually marketable. It's -- the SCR rig is going to be a different type of customer than an APEX-XK. But depending on what the future rig count is, there's certainly a market for these rigs.

So if we get back to 1,100, 1,200 rigs running, and those SCRs, you think are working again, basically?

Yes. Yes.

Okay. Thanks, guys.

Blake Hancock, Howard Weil.

Thanks, good morning, guys. Andy, I wanted to talk on the pressure pumping side a little bit. Last quarter, you talked about the incremental revenue you could have put through on the crew outside of the guidance. And just wanted to see, maybe help us understand the 1Q schedule on pumping. And given the two crews that you're reactivating, how much more could you actually put through, what you have active today, before the one crew comes active in 2Q? Just trying to gauge what the upside would be on 2Q, without the reactivation.

I think it's safe to say, that our calendar really doesn't have much open space in it right now. It's driven us to that point where we were able to activate -- in the process of activating and have activated three spreads since mid-December. So in terms of the calendar, and the open space, I don't think we have much left. There is always the potential, as the new crews get started, that their efficiency improves, and the number of stages per day per week improves over time, but I would say that's the upside right now.

Okay, great. And then on the drilling side, being sold out in Texas and Oklahoma, a lot of those rigs are still in the spot market per se. Are you getting the option to increase those rates at your will, or are you still having to wait for the industry to continue to catch up?

I believe that we have the ability to move rates on rigs, where we are not locked into contracts on pricing agreements that extend for long periods of time. And so, we will see that. The fact that we are essentially sold out in Texas and Oklahoma means that the industry is tight, and industry pricing is going to move up. Because rigs continue to go out, and so pricing is going to move up, as rigs continue to go out.

All right. Thank you, guys.

Timna Tanners, Bank of America Merrill Lynch.

Hey, good morning.

Hi, Timna.

Good morning.

I wanted to ask two things. One was, if you could, I didn't hear it, but was wondering if you could spell out some of the main components of the longer-term $3 million cost per frac spread, versus the $2 million that you're seeing now?

So in general, when we activate a frac spread, the largest cost that we have -- and remember the $2 million and the $3 million average includes labor, OpEx and CapEx, so labor is the largest cost there. As we activate spreads, we're activating the spreads that cost us the least amount to get out. And as we move through the fleet, we'll be spending a little bit more dollars in terms of CapEx, whether it be more fluid ins, or maybe a transmission rebuild. But that's where the differential in the dollar value comes.

So you're reactivating the ones that are the highest quality, the best ready to go. And as you reactivate further fleet -- further parts of the fleet, it will be the ones that are -- need a little bit more work, is that what you're saying?

That's correct, exactly. So we're activating spreads that are costing us the least amount in the beginning, and we'll move into the spreads that are going to cost us a little bit more, as we continue to have the opportunity to activate.

Makes sense, okay. And the other question was on the drilling side, I didn't hear if you mentioned on the contracts for the new rigs, if there was a duration amount? And in general, if you could comment? I know last quarter, you said that still customers were wary about signing longer-term contracts. If you could comment on contract duration in general as well?

Yes. So first of all, let me just comment on contract durations in general. We still believe that, in general, in the industry, as rigs continue to go out, that pricing continues to move upward. Therefore, we would like to avoid any types of long-term contracts. For the two new-build rigs that we're completing, we have one rig that has a 6-month contract, and one rig that has a 12-month contract. But we believe that this is still economically favorable to complete these rigs.

Cool. All right. Thanks, again.

Thanks.

Ken Sill, SunTrust.

Good morning. So I was a little surprised on the duration of those new contracts, but I kind of understand reactivating something you spent the money on, going into an up market. I'm wondering if you could give us some idea of where rates would actually need to go, to go out and actually order the parts and build a new rig? I mean, if you're kind of in the low $20,000 to $24,000 a day right now, I mean, do we need to see rates back in the mid to upper [$20,000s] to build new rigs, or do you think that is -- and what kind of contract term would you want to do that?

I think to build new rigs from the ground up, you need to have at least the mid [$20,000s], and the market's not there yet, but the market continues to improve. So as I mentioned earlier, we don't have any plans today to build any, or complete any new rigs, but we'll have to wait and see what the market does in the future as well.

And if we had mid-[$20,000s] rates, we'd be looking for some duration greater than the duration we accepted on those two rigs we talked about.

Mark, I would hope so. (laughter) Another question, pressure pumping is heating up. You guys are pretty satisfied with your capacity on sand. What about issues with what's going on in the Permian, are there going to be issues on the last mile, given some of the well sizes and sand volumes we're seeing out there, and how do you guys plan to address that?

In terms of the last mile, we're doing -- we have several different efforts in managing logistics. We use third-party trucks, we also have our own trucks. Now we're not using our own trucks in 2016, but as the activity has been increasing, we have started to reactivate some of our own trucks as well. So we believe that we're still managing that well, and I don't foresee any problems for us in particular in this last mile, with the combination of third-party trucking and our own trucks.

Well, that's encouraging, although my sympathies go out to whoever is managing the trucking fleet (laughter) on the labor side. Well, that's -- I'll drop, and let some other people ask some questions. But congratulations on making it through the tough patch.

Thanks.

Angie Sedita, UBS.

Thanks, guys. Good morning.

Good morning.

I'll try this one more time. So on the Seventy Seven [asset], I know you can't say much, but can you at least remind us how much of their equipment, both land and frac is in the field today?

I'm sorry, can you repeat that, how much their equipment is what?

Working --

Is in the field today, for both frac pressure pumping, and land -- how much is actually operating of your equipment?

I don't think we have an answer for that directly. That kind of changes week to week for that company.

I think you -- that information should properly come from Seventy Seven at this point.

Okay, that's fair enough. I understand. And then, on the rig count. Obviously, it's been very strong during the first half, and I think stronger than any of us would have expected. And I know you have limited visibility, but any thoughts on the pace of the rig count as we go into the second half of 2017, if you would actually think it would start to flatten and slow, as we seasonally see that slowing? Or is there any reason to believe that, that pace could continue to be strong, in the second half of 2017, based on any of your conversations?

Angie, we historically have only given some guidance for the next quarter. And your comments are correct, that we certainly see a strong -- that the trend continuing strongly in this next quarter. Looking out for the rest of the year, we're not seeing any signs of the trend changing at this point. And we do read analyst reports, some of which are more optimistic, some of which are less optimistic about the second half of the year. But frankly, from what we're seeing from our customers, we just see a continuing trend.

Okay. Okay. And then, on cost inflation that you're seeing, whether it be labor, logistics, can you talk about where you are starting to see some cost inflation, and where you think you could see incremental bottlenecks, as we go into 2017?

Yes. So there are some areas of cost, that I think the entire industry is sensitive to. In terms of labor on the rigs, we're not seeing the cost pressure yet. In terms of labor and pressure pumping, I think we're going to start to see some pressure on labor. And in general, we're going to have costs related to labor for the recruiting, the onboarding, and the training that we have to do to get people back to work. So that's kind of what's happening in the labor front.

In terms of materials, I think some of the materials and supplies that we use in both drilling and pressure pumping will start to move up, in terms of costs. But I'm also confident that we're able to manage those, but with activity moving up in general, and our pricing moving up, supplier's pricing is going to move up a bit as well.

In terms of sand, as I mentioned earlier, we see sand pricing moving up. We see it more so in certain grain sizes than others, where supply is tight. But I think at the same time, we'll also see mines improve production in those grain sizes as well, and the availability as we go into the year. And so, we have agreements, and we have discussions and negotiations with multiple sand suppliers in multiple basins to ensure that we have the supply. And so, that we could do our best to ensure that there's some cost competitiveness out there for us as well.

But, overall, the market is improving, the rig count continues to go up. I'm certainly encouraged by how fast things are moving out of the gate in 2017. In general, in the industry, I think that we can't activate frac fleets as fast as demand is out there. And so, that's allowed us to get the pricing improvements on the incremental spreads that we're activating. And the industry is likely building DUCs as a result of that. So that's kind of how I see things playing out right now.

Great. Thanks. That's helpful. I'll turn it over.

(Operator Instructions)

John Daniel, Simmons & Company.

Hi, guys. Thanks for taking my call. Andy, I will start with this one. What percent of your frac fleets work for customers who self-source sand and chemicals?

We do have a number of spreads that work for customers who source their own sand. We have also spreads that work for customers who may source their own chemicals, but not their own sand. But we don't, in general, get into the details of what those percentages are. And they do change month to month.

Okay. Will the two fleets that go to work, the ones you reactivate, go to customers that self-source?

Off hand, I don't believe they do.

Okay. All right. How about, for the Q1 revenue guidance for pressure pumping, can you tell us how much of the increase is associated with the two fleets that have been reactivated? I'm trying to distinguish what's price and what's new work?

Yes, I would say, the majority of improvement is coming from activity. And certainly, we've got two new spreads in Q1 that are adding accretive pricing there, but the majority of the improvement is coming from activity.

Okay. All right. One -- two quick ones, the last one, well, two. Rough estimate for fluid-in consumption, sort of either Q4 or 2016, either the dollar cost, or just the number of fluid ins consumed on the working fleet?

Without getting into the details of fluid ins, and the consumption -- we mentioned in the financials that pressure pumping, we're allocating $75 million for fleet activations and maintenance. And so, that maintenance will include fluid ins. And you've got our fleet activation costs out there, so you can kind of see what some of that might be.

I am encouraged by, for instance, the fact that in our move to using a certain percentage of stainless steel fluid ins for instance, the cost of stainless came down over the last couple of years, not in relation to oilfield or oilfield activity, but more in relation to the cost of nickel and the stainless blend. So as we move to, for instance, stainless, we're not paying large incrementals for those particular fluid ins.

Okay. All right. Just a last one here then, Andy, and going back to sand for a moment. Given the tightness that we're seeing in 40, 70 and 100 mesh, at this point are you -- is Patterson being approached by any start-up sand mines? Can you just talk to us about what you're seeing in terms of new people emerging, and discussions, if any, with -- in terms of sponsoring or working with potential startups?

I think it's safe to say, with us having 1 million horsepower, and then post-merger 1.5 million horsepower, that everybody calls us. So I don't think there's any sand producer in the US that doesn't contact us right now.

But I'm not talking about the existing ones, I'm talking about, what visibility you might have with respect to new mines emerging this year?

Yes, so we're getting contacted by individuals who are looking to start new mines as well. And so, that's why, while sand supply is a big concern of mine, we are hearing from individuals that are looking at starting production in sand that's not currently being produced. So, and I won't get into the details of what we might or might not do.

But it's happening, that's what I'm trying to drive at.

So, yes, we concur that it is happening.

Okay. That's all I needed. Thanks, guys.

Ken Sill, SunTrust.

Yes, it was interesting, your comment that the demand for frac is going up faster than you can reactivate fleets, and that's driving pricing. So how far out is your active fleet booked, and when should we expect to see pricing -- excuse me -- get better for those spreads?

Yes, my comment in terms of the reactivation of frac spreads, and it's hard for the industry to keep up, was really more of an industry comment, and not so much related to us. And it's based on discussions with customers. And it's what drove us to be able to get the incremental pricing on the incremental spreads that we're putting out. But overall, the utilization of the industry still has to improve before we get wholesale pricing.

When we look at our overall utilization, at the end of the first quarter, and going into the second quarter, we're going to be at about 60% utilization, and really pleased to see that number for a change. As rig count continues to go up in 2017, I think we will see further additions to active fleet, in terms of pressure pumping, and improvements in the overall utilization.

And at some point, at a certain rig count, you're going to see the ability for pressure pumping pricing to move up higher across the industry. So we're certainly encouraged that we're going to be at 60% utilization in Q2. We will have to wait and see what the rest of the year looks like.

And one final question on the pressure pumping side, how much of the work in the Permian in Oklahoma is 24 hours? I would assume they need to move that way, if they're not there already. But I was just curious as to where that stands now?

So I can only speak to us, and majority of our work, over 90%, is 24-hour operations. Now some maybe 24/five days a week, some maybe 24/seven days a week, but the majority of our work is 24-hour operations.

Thank you.

And, sir, I am showing no further questions in the queue at this time.

Okay. Well then we'll thank everybody who participated on the call for their participation, and look forward to speaking with you as we report first quarter in April. Thanks, everybody.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the call. You may now disconnect. Everyone, have a wonderful day.