Patterson-UTI Energy Inc (PTEN) 2015 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Patterson-UTI Energy, Inc. fourth-quarter conference call. At this time, all participants are in a listen only mode. Later, we will conduct a question-and-answer session, and instructions will follow at that time. (Operator Instructions) As a reminder, this conference may be recorded.

I would now like to turn the conference over to our host of today's call, Mr. Mike Drickamer. You may begin.

Thank you, Tonya. 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 12 months ended December 31, 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 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 comfortable.

And now, it is 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 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 December 31, 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 fourth-quarter, as set forth in our earnings press release issued this morning, we reported a net loss of $58.7 million, or $0.40 per share on revenues of $339 million. Total adjusted EBITDA during the quarter was $98.5 million and we remain EBITDA-positive in all three of our business lines.

Our financial position remains strong. Our cash balance at December 31 improved to $113 million from $76 million at September 30, and our $500 million revolving credit line remains fully available.

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

Thanks, Mark. In contract drilling, our rig count averaged 88 rigs during the fourth-quarter in the US and three rigs in Canada, compared to 105 rigs in the US and four rigs in Canada during the third-quarter. During the fourth-quarter, total contract drilling revenues were $202 million, including a $9.2 million of revenues from early contract terminations. These early contract terminations positively impacted our average rig revenue per day of $24,240 by $1,100.

Excluding early termination revenues, average rig revenue per day during the fourth-quarter would have been $23,140, which is unchanged from the third-quarter. Total average rig operating cost per day decreased $940 during the third-quarter to $12,640. Approximately a third of this decrease is related to cost savings, with the remainder due to a higher proportion of rigs on standby.

During the fourth-quarter, the average number of rigs on standby increased to 12 from 10 in the third-quarter. Rigs on standby have very little associated operating cost, and therefore, the increased proportion of rigs on standby during the fourth-quarter reduced our average rig operating cost per day. Excluding the positive impact from early termination revenues, total average rig margin per day was $10,500 compared to $9,560 during the third-quarter.

At December 31, we had term contracts for drilling rigs providing for approximately $710 million of future day rate drilling revenue. Based on contracts currently in place, we expect an average of 59 rigs operating under term contracts during the first quarter and an average of 46 rigs operating under term contracts during 2016.

Looking forward, we have limited visibility into activity beyond the current quarter. We expect the continued weakness in commodity prices will lead to further rig count reductions across the industry. As such, we expect our rig counts during the first quarter will average 70 rigs in the US, and 4 rigs in Canada.

Average rig margin per day, excluding early termination revenues, is expected to decrease approximately $900 per day in the first quarter, with the decrease equally attributable to a decrease in average rig revenue per day and an increase in average rig operating costs per day. The increase in average rig operating costs per day is related to the expectation of fewer rigs on standby, which have low operating costs, as well as a higher proportion of rigs operating in Canada. Early termination revenues in the first quarter are expected to be approximately $11 million.

Turning now to pressure pumping. Our pressure pumping activity levels fell during the fourth quarter, but were better than we expected. Pressure pumping revenues during the fourth quarter were $132 million compared to $154 million in the third quarter. Gross margin as a percentage of revenues improved slightly during the fourth quarter to 10.4%, and we continue to generate positive adjusted EBITDA for pressure pumping, which totaled $10.9 million during the fourth quarter, compared to $11.8 million during the third quarter.

With the better-than-expected activity levels, we did not stack horsepower during the fourth quarter. However, with the further weakness in commodity prices since the beginning of 2016, we have seen a decrease in the amount of work available. As well, the profitability of the available work has continued to deteriorate.

In response, since the beginning of 2016, we have stacked approximately 140,000 frac horsepower. And in total, we now have stacked slightly more than half of our fleet of more than 1 million hydraulic fracturing horsepower. We expect pressure pumping revenues will decline sequentially by approximately 25% in the first quarter.

While the stacking of horsepower will negatively impact pressure pumping revenues, gross margin as a percentage of pressure pumping revenues is expected to remain relatively flat at 10% for the first quarter, because much of the horsepower that we have stacked was working at low margins. We believe it is prudent to be disciplined in the use of our assets, and we believe some competitors are working at significant cash operating losses, which will result in further attrition across the industry.

Before I turn the call back to Mark for his concluding remarks, let me provide an update on a couple of other financial matters. In general, with both drilling and pressure pumping, we remain very focused on reducing costs and protecting our balance sheet.

With respect to our capital spending, we will be pragmatic, recognizing the importance of cash, but also acknowledging that our balance sheet strength affords us the opportunity to perform rig upgrades and inspections in a slow market, thereby better positioning us to react when conditions improve.

Our total CapEx budget for 2016 is $190 million, including $115 million for drilling, $60 million for pressure pumping, and $15 million for E&P and general corporate purposes. Included in the $115 million budgeted for drilling is $40 million for rig components, which were deferred from our 2014 rig fleet expansion program, and $75 million for rig inspections, maintenance capital, tubulars, and potential rig upgrades. Given our focus on protecting the balance sheet, we will be prudent with our spending and may not spend all the budget amount if market conditions do not improve.

Depreciation expense during the first quarter is expected to be $175 million. SG&A during the first quarter is expected to be $18 million. We are currently projecting our effective tax rate to be approximately 36% in the first quarter. Given current market conditions, we do not expect to pay meaningful cash taxes during 2016, and we expect to receive tax refunds during 2016 totaling approximately $45 million.

With respect to our dividend, there has been some discussion about a covenant in our 2015 term loan agreement that could restrict our ability to make dividend payments later in 2016. However, this covenant applies to only $185 million of our debt. And we believe that our strong financial position allows us various alternatives to address this restriction, including repayment of this debt.

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

Thanks, Andy. 2015 was a brutal year across the energy sector. Crude oil prices fell from a high of $105 in the third quarter of 2014 to a low of $34 in December 2015. The pressure on oil prices has not abated, as oil prices recently reached a low of $26 in January. Given current commodity prices and the pursuant expectations for reduced E&P capital spending, 2016 is likely to be even more challenging, and we do not expect this to change until commodity prices improve.

Last quarter, we discussed that the industry had reached a point where it was Darwinian and the weak may not survive. We believe the industry is becoming increasingly bifurcated between the financially weak and the financially strong. The financially strong, such as Patterson-UTI, are seen as survivors, while those that are financially weak may not survive, at least in their current form. We expect that asset sales and reorganizations, as well as equipment attrition due to the lack of maintenance, will impair the ability of some companies to respond during a market recovery.

Despite market conditions, we remain confident in the long-term prospects for our Company. With 161 APEX rigs and more than 1 million horsepower of pressure pumping equipment, we have the kind of high-quality equipment that we expect to be in greatest demand during a recovery.

With that, I would like to both commend and thank the hard-working men and women who make up this Company. And I want to tell them that I appreciate your efforts during this challenging market environment.

I am also pleased to announce today the Company declared a quarterly cash dividend of -- on its common stock of $0.10 per share to be paid on March 24, 2016 to holders of record as of March 10, 2016.

Operator, we would now like to open the call to questions.

(Operator Instructions) Byron Pope.

It feels like we're going to get a really good feel this year for what acreage is really core to E&P operators. And so, as I think about -- it seems as though the utilization for your APEX rigs has held up much better than the overall US land rig count average. And so as we think about the 59 and 46 rigs that you have term-contracted for Q1 and for 2016 respectively, is it fair to think that it is largely concentrated among your APEX-XKs?

You know, it is really by basin, and certainly a number of the XKs are working, but also some of the earlier APEX are working as well.

Okay. And then on the pressure pumping side -- I think I know the answer to this, given that you guys don't like to really split out details on the two regions -- but of your -- half the fleet that is currently idled or stacked, is it skewed toward one of the two regions? Or fairly balanced between them?

You know, it's a mixture of both. You know, we have the challenge of commodity prices in both regions, whether it is WTI in the Texas region or natural gas prices in the Northeast.

Okay. Thanks, guys.

James West.

Andy, I know we talked about this on the last call, but the -- in the market, at least the big four companies had maintained at least mostly price discipline as of -- you know, through I guess the end of the third quarter. Has that continued as we've had this next round of oil prices coming down, and with a lot of term contracts starting to roll off? Are you starting to see your main competitors on the AC rig side becoming, say, less disciplined to try to hold market share and becoming more -- I guess, more willing to take much lower rates?

You know, James, I wouldn't say there has been any real change other than it still remains a very competitive market. We have the situation of term contracts. And certainly as we progress through 2016, some of these term contracts will be rolling off. And we would like to think that a portion of these are going to work at whatever the market rate is at the time. But we do expect it to still be very competitive.

Okay. And then, I know, Mark, you talked about the bifurcation of the industry right now, both in the pressure pumping and the land rig side, between financially-sound companies and those that are becoming or will become distressed here shortly. Are the customers also bifurcating their work and shifting more work towards -- to companies like yourself, which have a better balance sheet?

I think I will turn that to Andy.

So, I wouldn't say that the balance sheet per se of a Company impacts who is getting work right now. It is still a highly competitive market, especially in the pressure pumping business. There is still a number of companies out there.

What we said before and what still holds true is the pricing in general in pressure pumping industry is just really unsustainable. It is too low. And that is why you see us stacking 140,000 horsepower since the beginning of the year. But I wouldn't say people are looking at balance sheets per se. I think pricing is the primary driver of most operators' decisions right now when it comes to services.

But there is also an element of service quality. And that is partially what is driving our results as well. Our teams have shown, historically over the years, that they are very competitive when it comes to operational efficiencies at the well site. And I do believe that is one of the reasons why you see our margins holding up, relatively speaking, in a very difficult market.

Okay, great. Thanks, guys.

Marshall Adkins.

The thing that jumps out at me is how well you all are doing in the pressure pumping side from a margin perspective. So, Andy, give me a little bit of color on why you think that is? I mean there is a lot of guys that are negative margin, negative EBITDA at this stage in that area, and you are still putting up respectful margins, given the conditions. How is it you are doing that?

And again, you guided to margins holding in. How can you continue to put up this much better-than-average result in that space?

So I will give you what I believe are a few different reasons why our teams have done so well. And the first is you have got to kind of roll back the clock to when times were busy, and how well we performed even when times were busy and the margins that we were posting then.

So our margin degradation from the peak may have been relatively the same as others, but we were doing better back when the industry was doing better as well at the same time. But part of the reasons our margins were doing better, and part of the reasons they are doing better today, is the concentration of our scale.

We have 1 million horsepower in total. Now granted, we stacked a little over half at this point. But, with 1 million horsepower, we are in the Texas region and in the Permian Basin, and we are up in the Northeast. And we compete against companies that are similar in size who are in multiple regions and maybe even multiple countries. And I think that scale helps us out in the region logistically, cost structure, various reasons.

Is it a difference in equipment as well?

You know, our equipment is relatively young. The average age of our equipment is still only about four years. That probably helps a bit. And we continue to maintain our equipment. We still invest maintenance capital in our equipment to make sure that we are providing the absolute best service quality that we can for the customers.

One last unrelated follow-up for me. We are looking at an oil recovery going into 2017, and we think cash flows will be there for the rig count to potentially double in 2017. I am curious as to how you think the industry could possibly do that? Are we going to be able to re-attract the people? And is the industry set up to see a doubling in activity if the demand is there in 2017?

So, we certainly would like to buy into your view. It is difficult from where we sit today to know if that is actually going to happen. But we are planning for an eventual recovery. Just because we've tried to maintain some of the key positions of leadership in the Company and because we have the balance sheet, we can do that.

And, by maintaining some of the key leadership positions, it makes it easier to put the Company's growth back into place when an eventual recovery does happen. But I think let's also speak about the labor market. It's a -- if we look at the labor market that we had back in 2009, 2010, it was very different in the country. Today, I think -- we talk about all the equipment that's on the sideline, but I think it's going to be tougher to pull some of the labor back in. And we are going to see tightening on the labor side before we see tightening on the equipment side, in an eventual recovery.

Makes sense. Thank you all.

Thanks.

Jim Wicklund.

Does -- again, we don't know how long this is going to last, we don't know how long it's going to -- of this is going to be and all that kind of stuff. Does consolidation make sense in any of your markets in this type of environment?

You know, Jim, we are always looking for opportunities. And, as you know, we've had a long history of doing consolidations. And so, we expect that with this downturn, and kind of the more prolonged and the deeper it is, the larger the number of those opportunities there will be. That said, whether those opportunities are ones that we are going to find attractive is really a question I don't think any of us can answer at this time.

Would the consolidation potential for the industry, do you think, be better for the rig side or the pressure pumping side of the businesses?

I couldn't really -- I don't have a view about that.

Okay. And my follow-up, if I could, you guys have been opened an office a couple years ago. Internationally, you looked at some other different stuff a couple years ago. Andy, you had said a lot of the future of the Company is probably going to be international. Are there any opportunities that you see that are coming up internationally because of the slowdown that might not have been before? Is that market looking more encouraging or less encouraging to you?

Well, we haven't made any change to our plans for international expansion. We are very pleased with our position in North America today. And so we just think that international is part of the future growth of the Company, but it is long-term plans. So we are not making any changes to the plans. But certainly, as everybody knows, the international markets are experiencing some of the same challenges that the North American market is right now, too. So it's still a long-term plan.

Okay. Thanks, guys.

Ole Slorer.

So let me ask my friend James a question for him. So are you going to merge with your neighbors? (laughter)

(laughter) Ole, such a nice question. Thank you so much.

Okay, let's move on to the next one. So you are in pressure pumping and drilling, and you're doing pretty well in both. As you look into the trough of the cycle, and God knows what it looks like on the other side, but which one are you the most comfortable about, or where do you see the greatest -- where are you the most different to the consensus view in terms of your sustainability or your APEX rigs or your kind of -- or what you see on the pressure pumping side? Some of that goes a little bit also around what you see on spreading versus a completion and a duck trend that is building up at the moment.

Interestingly enough, Ole, I am kind of optimistic on both sides, frankly.

Which one? Come on. (laughter)

Let me try to give you the reason why. On the rig side, drilling side, I don't think there's all that many of the very high-quality performance rigs that are going to be required, especially when you start to differentiate 1,500 horsepower rigs with all the bells and whistles that are going to be required.

So the first point is, I think that market, if you go back to Marshall's question about if the rig count doubles, it is not so easy to get that many good-quality, high-quality rigs. We think we are really well-positioned on that, and plus we have the term contract coverage that we have discussed in our prepared remarks. So that's the reason on that side.

On the pressure pumping side, I know a number of the people on this call have written about the attritions going on in the business. And the financially weaker players who are going to be unable to continue to operate at fundamentally unsustainable prices. And so we think, with our disciplined approach, we will be survivors and be in a strong position to capitalize on our market that will return.

Andy, do you want to --?

Yes, I will just add to what Mark said. We think we are good at both of these businesses. So it is tough to choose between one or the other. But the way the markets are today, it is difficult and challenging in both. However, if you look at, let's say drilling, if there is an eventual market recovery at some point -- which we do believe there will be; we just don't know when -- and you look at the specifications on drilling rigs that are going to be required by the market, we see that as 1,500 horsepower, pad-capable, 7,500 psi, and maybe a number of those are three pumps instead of two pumps.

When you get into those kind of specifications on the rigs, the number of rigs that are available, as a percentage of the total rig on the sideline, is much smaller. And that could drive pricing up sooner in drilling.

Pressure pumping, we think we are good at this business as well. We think that we have shown good operating statistics with the customers that we work for. And we think we will continue to produce good margins in that business as well. But there is many more players. Pricing may not come back quite as quick in pressure pumping, but it also could depend on the labor market. And that labor market tightening could drive pricing in pressure pumping as well.

So, if you'd -- just a little clarification on the rig side. Are there any rigs owned by yourself or either your competitors of that quality that you just highlighted that are idle today?

Yes, we have those idle today.

Okay. So there is some absorption there. And on the pressure pumping side, or the rig side for that matter, when it comes to consolidation, clearly -- how do you think about the challenge of debt that in many cases is trading at $0.10, $0.20, $0.30 on the dollar, and the change of control clauses that would require full refinancing of debt? Is it possible to do something? Or are these companies just going to be zombies?

Ole, I think that anybody who is trying to go through that has to go through it on a one-by-one, case-by-case basis. Because it depends on what the lender has in it and who the lender is, and what they are willing to do. And fundamentally, giving sort of a long overview of that is hard to do.

My experience in the 1980's at prior companies in the oil patch was that it depended on each particular case. We actually think that our management team is well-situated, based on its experience and our balance sheet, to potentially take advantage of those circumstances if they do arise. But trying to figure out which one and tell you -- and predict it to you folks, is almost impossible.

Okay, thank you very much.

Scott Gruber.

Andy, you did highlight that you have options to eliminate the covenant on the 2015 term loan that may restrict cash distributions. Can you just speak a little bit further about your appetite to sustain the dividend in the current environment? We are just getting a lot of questions from investors on that point. And specifically, whether you would utilize the revolver to pay off the loan even before the underlying market improves?

You know, just speaking in terms of the dividend at a high level, this is something that we evaluate on a quarterly basis. And, of course, in a market like we have today, the discussions are maybe more pronounced. But it's an ongoing evaluation on a quarterly basis.

Mark, would you like to add anything to that?

Yes, Scott, I guess I would say I am happy for you to recognize -- and we have put it in the prepared remarks just so that we could perhaps allay the investor concerns about the covenant -- that there was financial flexibility with respect to how to handle that covenant if we decide we want to do so.

The second point I would make is that the covenant doesn't really go to the question of, is the Company financially strong? With our cash position, our undrawn revolver, our cash flow, et cetera, the Company's fundamental strength is there. And so, the question is not whether we can pay the dividend; it's whether that is the best use of our resources. And that is a decision that we make every quarter, along with the question of should we buy back stock and to various other kinds of questions.

And that is one which I think we've shown a long-term history of, I think, pretty much getting it right -- not to pat ourselves on the back, but I think we've done a pretty good job of being stewards of capital and buying back stock, and making dividend payments, et cetera, over the long haul for the benefit of the shareholders.

And so, when I see the question asked, I think sometimes we are getting grouped with the people who are unable to pay their dividends because of their financial position, as compared to the people who might make a decision as to what the right thing to do is. I want to make sure that that distinction is very carefully drawn.

No, you are clearly in a stronger position. I guess just to hit the point home a little bit further, though, it's -- would you be willing to reduce your liquidity near-term for a few quarters to sustain the dividend --?

You know, Scott, I think that that question -- I would have to ask you five more before -- and you would have to give me five more assumptions or something like that, before I could answer that question. Because it depends on what you see as opportunities in the marketplace.

I mean, what -- you are paying a dividend in order to reward the shareholders based on the profits of the Company over the long-term. That is the basis of the dividend. But you are also saying to yourself what do I think will do -- benefit the shareholders the most over the long-term? That's, I think, the correct way to see it, and that is a decision about allocating capital.

And you would have to tell me what the price of oil is, the price of natural gas, the number of rigs running, the amount of pressure pumping activity, margins, and then a few more things. And then I could give you the answer about the liquidity. I mean, liquidity is not the be-all, end-all. It is good what's good for the Company.

No, I think that is very fair. No doubt you guys will be thoughtful and strategic about it. A follow-up on average day rate for rigs under contract. Where does that stand today?

We haven't called out the average dayrate for rigs under contract. Only the average revenue per day.

Has the number, though, been changing based upon the mix of contracts in place or any efforts by customers to maybe utilize blend and extend to reduce their rig expenditures? Is that number moving?

You know, in general, as you look across 2016, as the number of term contracts reduce, you have got -- because of the timing of when they were signed, the average revenue per day for those rigs under term contracts is actually going to go up. But you also have to take into account rigs that may be on standby, which is allowed through the contract. So, we continue to work within the framework of the contracts, but you have got a blend of the standby in there as well.

Got it. Thanks for the color.

Thanks.

John Daniel, Simmons & Company.

First, I guess I would like to touch on just the whole attrition debate. Andy, as I'm sure you know, there are varying estimates out there regarding frac fleet attrition. Some have called for 4 million to 6 million of horsepower this year. Last week, on its earnings call, RPC seemed to agree with that estimate, but it doesn't expect any attrition within its own fleet.

First, do you agree with the fleet attrition thesis of 4 million to 6 million horsepower? And just if so, can you also comment on how much horsepower you guys might retire this year?

So, first off, when it comes to attrition, we can really only speak about our own fleet, and we don't expect any real attrition out of our own fleet. We stacked 140,000 horsepower at the beginning of this year, and we stacked horsepower last year. But this is all horsepower that can be maintained, can be brought back to work.

When it comes to attrition in the industry, I don't think we have the best view. We work in two regions. We are working in the -- in Texas in the Permian and we are working in the Northeast. With the road trips you make, you've probably got a better overall view of this than we do. So, I certainly could concur with your numbers and the estimates that you come up with, but it is harder for us to get a view of it.

Yes, fair enough. Okay. Can you just walk us through or just explain how complicated, expensive it is, to add that third pump and make a rig 7,500 psi capable? And just what percent of your fleet have that attribute?

So, in terms of -- let's talk about the 7,500 psi first. All the rigs we built last year have the piping for 7,500 psi. Around half the rigs we built the year before had the piping for 7,500 psi. So it just becomes in addition to the fluid end. If a rig doesn't have the piping, it is a matter of a couple weeks to install that piping. So it is certainly all upgradable. But we have a number in the fleet.

If you look at our spec sheets online, it may not always call out the 7,500 psi piping, if the 7,500 psi fluid ends aren't on the pumps. So, it's not always visible in our spec sheets online. But we do have a number of those rigs and it doesn't take us long to upgrade one in the basin if it doesn't have it.

In terms of the third pump, it is a matter of plumbing. It is a matter of electrical control systems in the drive bays, and we have a number of rigs that could be upgraded to that third pump.

Okay, fair enough. And then last one for me, just on the -- given where the CapEx budget is for this year, it looks like depreciation to guidance is flat quarter-over-quarter. John, any -- at what point do we start to see it roll off, given the lower CapEx spend?

We expect it to begin declining sometime this year. Still a little unclear as to what quarter we will see that in.

Okay, thank you.

Kurt Hallead, RBC.

Great summary so far. Kind of curious -- you made comments very early on about the stacking of frac horsepower kind of to date, and you may have mentioned something about attrition industrywide, but I might have missed that. What do you expect? Do you think we are at the absolute trough with respect to the need to stack frac equipment at this juncture?

So, just to kind of recap where we are on stacking of equipment, at the end of the third quarter, we had around 38% of our equipment stacked. We didn't stack any in the fourth quarter just because our activity levels remained better than we expected. But since the beginning of the year, along with commodity prices and slowing of activities, we just saw a deteriorating market and we decided to stack another 140,000 horsepower.

Our choice to stack the equipment is not about us losing work. What we see is -- we are trying to protect our assets. We don't want to see any unnecessary attrition in our own assets. And we can continue to maintain them when activity levels come back; it's easy to bring this equipment back off the sidelines again.

In terms of industry attrition, because of the regions we work in, it is hard for us to have a view across the US of really what attrition looks like at other companies. So I just don't think we are in a good place to talk about industry attrition. I think others do more work than we do in terms of that. But we are just trying to protect our own assets and be disciplined about how we are using our own assets, and stay margin-focused as best we can.

Great. I've got a --

In terms of are we going to see further stacking, I think it just really depends on the market right now.

Okay, great. And then there's this perspective in the marketplace that the frac services market is going to tighten well before the land drilling market will tighten when the ultimate recovery does occur. Do you guys share that view?

I think there are several variables there. I think people are looking at the drilled and uncompleted wells that are out there, and therefore some of those could come back, but not everybody has ducks in all the regions. Then, there is attrition on the equipment. And I think that continues to get more pervasive in the industry because of the negative cash flows that a lot of companies are operating at, and they are just not necessarily maintaining their equipment.

And so, I think attrition is likely speeding up in the industry, but we just don't have a good view of how much. So it is very difficult for us to quantify that. And then, in an eventual recovery, I think the labor market is going to be a bit challenging and I think you're going to see a tightening there. So, that is how I see it playing out.

Appreciate it. Thanks.

Chase Mulvehill.

So, I guess first question, I know you guys have done a fabulous job with the design and the technology of your APEX rigs, especially kind of the APEX-XK. But how do you see Schlumberger's acquisition of CAM, and the likely entrance into the land rig market, playing out over the medium to long-term?

I think we have to go on our own track record. The APEX rigs have done very well in overall utilization over the years. The APEX-XK is a very high-performing rig in the basins that it works in, and we just have a solid track record when it comes to our own operations. And we'll remain very competitive.

Okay, all right. And a quick question on the OpEx per day, came in at $12,400. And just trying to adjust some things for standby rigs. And so, did you say that you had 12 standby rigs in the fourth quarter? Is that right?

Yes.

Yes. That's correct.

And are the -- is the cash CapEx on these standby rigs effectively zero?

Pretty close to it.

Okay. So if I do that calculation, I am getting something a little -- something a little over $14,000 a day. So as we kind of move forward and these standby rigs start working, is that something we should be modeling as we kind of get into 2016?

It is hard to say in the market today if I'm going to be able to put standby rigs back to work. So it's -- there is still a lot of moving parts in there, in the overall numbers between rigs on standby, rigs on term contracts, rigs that are working at market rates. There's just -- there's a mix.

Chase, I think that is fundamentally a call on what you think the timing is of the recovery.

Okay, but these standby -- do you think these rigs stay on -- under current market conditions, these stay on standby through 2016?

Some of the standby rigs are under term contracts, which could be finishing up, too. So, some rigs could be coming off standby because the term contracts are ending.

Okay, all right. I guess kind of follow-up on that real quick, could you talk about where you think your term contract coverage will be at the end of this year? You have given us the average for the year, but maybe if you will give us an exit number.

Today, we are just giving you the average for the year.

Okay. I will try one more. (laughter) So what about the average term dayrate for the 46 rigs under term contract this year?

We just haven't called that out. We give you what the average rig revenue per day is, the cost per day and margins, of course, but we just haven't called out what the average term contract rate is. But what I have -- there is a progression in 2016 where the term contract rates go up because of the timing of when those rigs were signed.

Okay, so it goes higher from here throughout the year?

Except for rigs that could be on standby.

Got it, got it. Okay, that is helpful. All right, thank you.

Robin Shoemaker.

I wanted to ask you, of the companies that have reported so far, the public companies, basically everyone says that they prefer to stack their pressure pumping equipment and not wear out their equipment for no margin and that is the policy. And of course, you add all those companies up, they account for the vast majority of pressure pumping equipment in the US. So that leaves the others.

And I just wondered -- is there any -- do you think there is anything there regarding either those that are in the lowest -- working for the lowest rates, that they have some kind of lower wage rates or lower some other costs at G&A or other that actually gives them some kind of advantage?

No, I don't see that there is any real advantage, especially with some of the smaller companies. I think they're trying to survive. And one scenario that is potentially playing out right now is you have companies who are working at negative cash flow because they are still going through bank evaluations and working with bankers.

And if that equipment is not working, then the asset value goes to near zero. But if the equipment is working, even though they are at negative cash flow, they get more valuation on the asset. And so I think this is that part of the cycle where you have companies that are just fighting to survive in that respect as well.

Yes, I can appreciate that. That makes sense. Just -- on your comment on the labor market, I mean, it certainly, with all the people who have lost their employment in the last year, it certainly would seem to be a very large pool of people out there for -- who may have found alternate employment, but probably would come back because the compensation is higher.

But are you referring to a labor market that tightens in the first year of a recovering market? Or more like the second or third? If you put back 200,000 or 300,000 horsepower to work or 30 APEX rigs, would you already feel it then?

I believe you would feel the labor market tightening up within the first year. I think it is hard to know, but it is going to be in that first year or less. Because I think a number of employees, unfortunately, we have had to release, have found work elsewhere. And we recruit nationally. We have people that rotate across the country. And in their hometowns, which aren't necessarily West Texas or places where the rigs work, they found other employment in some cases, because there is a labor market around us.

Yes, okay. Interesting. Appreciate it, Andy.

Thanks.

Sean Meakim.

So I wanted to drill a little bit on dayrates in the recovery. And some of your comments earlier, it sounded like you were -- your view is that pad optimal rigs are a more discreet market that can get pricing in a recovery faster than perhaps into the rest of the AC or horizontal market. Is that your assessment? Or do you think we need higher utilization across the kind of broader horizontal fleet to get improvements in pricing for each of the subsets within the AC fleet?

So, first off, pricing, dayrates, are still very competitive. It is going to remain very competitive in 2016 because of where activity is. But in the scenario when we do start to get a recovery, the rigs that are going to go back to work first are going to be the 1,500 horsepower with the walking systems, 7,500 psi circulating systems, maybe three pumps on the rig, 75 -- or 750 [tips mast] load. So, it's those kinds of specifications that we think the customers are going to want first.

And those are going to go back to work first. I don't think you get immediate pricing power with a rig like that, just because utilization is low in the market, and we all have rigs like that that are stacked on the sideline. But I do think you get some pricing power relatively quick after that, maybe relative to other segments -- even relative to pressure pumping. And pressure pumping, I think it is going to take a little bit more to get the pricing back up in that market where there is a number of competitors out there.

So we don't necessarily need 80% utilization across, say, all AC rigs in order to get pricing power within that subset of pad optimal rigs?

No, not at all. In fact, when you look at the fleet of AC rigs that are stacked on the sidelines today, if you start to dissect that fleet, you see a number of less capable rigs, whether they are 1,000 horsepower, whether they are super singles. They are not pad-capable. So, you have to break those out of the fleet that's stacked on the sidelines.

Okay, yes, thank you. And then I guess to switch over to the bifurcation that you mentioned between competitors, and just thinking about the potential for asset sales, we saw a pretty strong bid for pumping assets recently. And so I was just curious how you think about competition from private capital that is on the sidelines, and in terms of potential consolidation as we get through the downcycle and into a recovery?

Any consolidation in pressure pumping is positive for that sector of the business. Whether it is somebody else doing the consolidating or ourselves doing the consolidating, any consolidating is a plus. There's too many companies in pressure pumping and the pricing is unsustainable.

Sean, I would just add one additional thought, which is that, over the past, say, 10 years, you saw a lot of new money come in to build assets in that marketplace. What I think this downturn has caused is that there is not money going in to building new assets. And so, what we are going to see is a decrease in the amount of available assets, not an increase, probably consolidated among fewer holders, and that the likely buyers are going to be people who already have investments, who are making investments that they see as strategic.

Yes, that is what we are seeing here, too. Thank you very much.

Marc Bianchi.

I just wanted to ask first on the standby rigs, it looks like -- I think you said that there were two more standby rigs in the fourth quarter, and that affects -- doesn't affect margin, but it does affect dayrate. If we were to normalize for that, what would have been the sequential dayrate change, just trying to remove the impact of the standby rigs?

Yes, there are so many moving parts, I don't have that number in front of me. It is more than just the standby there.

Okay, okay. Would it have been up sequentially if it were unchanged?

We just don't have that with us right now.

Okay. And the other question is as it relates to the rigs on contract, it looks like the average for 2016 went up by one, but you talked about some early termination in the fourth quarter and some expectation for early termination here in the first quarter. So, can you help reconcile that? Did you put some rigs -- new rigs on to contract? Or take some rigs off the sidelines and put them on contract?

So we did in the fourth quarter. We did sign a couple of term contracts, very short-term, and at what we consider a reasonable market rate. We are still margin-focused, but we did sign a couple of very short-term contracts.

Is there any -- can you talk to the types of rigs and what the work was? Are they these 1,500 upgraded rigs that are replacing something that was of lesser quality? Or any other color you can provide on that?

They were APEX rigs, because that is pretty much all we are working right now. And, of course, being a APEX rig, they are very good quality. They had good performance metrics in the basins that they were working in previously, which is why we were able to get the -- keep the rigs working. And the short-term contract that we signed gave us a commitment on the rigs. So, it was mutually beneficial for both parties.

Got it. Okay. Thanks, Andy. I will turn it back.

Waqar Syed.

Andy, I have a question on ability to or intent to provide additional services from a rig. Some of your competitors are looking to provide additional services, to maybe generate more revenues per rig, like casing and tubing services or any other additional services. Is that something that you would look into?

You know, Waqar, today, we are just very focused on the businesses we are in, in drilling and pressure pumping, and just trying to maintain the margins that we have. I think we have said before, we are open to looking at opportunities to do other things, whether it could be organic, it could be through acquisition.

We are going to look at opportunities. But this has been a pretty challenging downturn, and we've had to really stay focused on what we do best right now.

Okay. And then on -- something you have discussed in the call as well, but I just wanted to maybe dig deeper, what do you think would be the reactivation cost if you have to reactivate your drilling rigs past maybe the first [30 or 40]? And then again, on the pressure pumping side, what do you think the reactivation cost would be if you have to bring back equipment, both on the equipment side, and perhaps you will address some of the wage issues, but on the equipment side.

So, in a reactivation scenario -- which we are hopeful that eventually we'll get to, but we are not there yet -- we are going to have costs associated with labor. In drilling, it could be two to four weeks of labor costs as we get the rig back out. In pressure pumping, I am anticipating maybe a month of crude labor to get the equipment back out.

And therefore, because of that, the cost -- or the pricing to get the equipment back out is higher than equipment that is already working. So when we talk about reactivation equipment, we are talking about equipment that we expect to go out at a higher price than maybe equipment is working today.

Okay. But in terms of the rigs that -- you know, if the rig has been stacked for about a year or so, and then you have to reactivate that, is there any cost associated with actually moving the equipment in terms of finding spare parts or just painting it or running the engines or things like that? Is there any costs involved there?

You have the transportation to mobilize it out, but outside of that, we don't expect any major expenditures to mobilize a rig or even the pressure pumping equipment.

Okay, great. Thank you very much.

Darren Gacicia.

Thank you for squeezing me in. I appreciate it. When I put out my initiation a couple months ago, I had the 1,500 (technical difficulty) AC fleet at a little over 800 rigs. I am kind of curious what you think about that number, whether it is a little low or a little high? And then, a little bit of a sense of -- if your crossover point on pricing is probably 80% utilization and [maybe] higher, what does that have to be from a rig count standpoint to maybe just start to see pricing coming back if the first entrants back are basically only kind of traffic (technical difficulty) in those rigs?

So, let's start with the first part. The number of 1,500 horsepower rigs that are stacked on the sidelines is probably less than 800. I don't have that in front of me right now, but that seems a little bit high.

Well, I am just talking like the total fleet, not the stack number.

The total fleet -- it just seems a little bit high. But also, what I want to get to this, in the 1,500 horsepower rig category, what you don't see in a lot of the macro data that circulates is not all these 1,500 horsepower rigs have the 750,000 pound rated mast.

And so, there are some older rigs that are mixed in with that, that might have a lighter mast, that are just going to be less marketable when we get to eventual recovery and when people are looking at rigs. So, you have really got to kind of dissect what that rig fleet looks like, more than just the horsepower.

So is that -- I mean, so if you look at it in terms of the adjustments you're saying, is it off by an order of magnitude of 50 rigs, 100 rigs, 200 rigs? I mean, what's -- just to kind of get me order of magnitude to think about that comment.

Yes, so Mike just called the number and we believe there is approximately 700 1,500-horsepower AC rigs total in the industry. And then, I don't have the number of -- that breaks down into what I have described before, but it's probably in the 200 to 300 range, but I don't know for sure offhand.

But the other part of your question was really about pricing and utilization. What we have seen historically is, there was pricing power in high spec drilling rigs below 80% utilization. We saw that in 2013 and 2014.

Got you. So, when you look at your fleet, I know that there is a ton of cold stack, there could be warm stack, and then there is sort of -- what's the amount -- given the fact that you probably have to train new people and do some work on the rigs to bring that out -- what would be the pace at which you could probably bring single rigs back on? And can you elaborate a little bit on the process that is to happen there?

Well, we will have to bring people back if we are reactivating rigs. The way that we've structured how we are operating today is we have kept as much of the experience as we can in key leadership positions. So, when we do bring people back, we are talking about bringing back the entry level people, more the floor-hands. And so, the training time to get people back is not as much as maybe people think. So, I think we can put out and we can reactivate rigs within two to four weeks.

Also the fact is that during this downturn, what has happened is people take lesser positions and go from one position on the rig to a lower position on the rig. And that person can be promoted back up as we bring in the skilled -- the less skilled people. So, the way we have done it sets us up to go the opposite direction as well.

So if there is any one parabolic on you, just hypothetically speaking, like how many rigs do you bring on the floor, do you think? And do you really want to put the pedal to the metal?

I think that no one can give you that bit of information, because you'll have to tell us what the demand is, what the pricing is, and so on and so forth. Because all those factors will be implied.

Got you. I was just thinking from a really far extreme example, if you really wanted to bring everything you possibly could back on. And everything was pricing to the extent that allowed you to do it, et cetera.

You know, there's -- in general, there is no limit to how many rigs we can put back to work that are stacked on the sidelines. The equipment is in good condition; it is just a matter of putting the labor force back in place. But that labor force is going to tighten up. And so, it is really a labor issue more than just the equipment issue. But that is all very market-dependent, as to how many rigs we would put back and how fast that would happen.

Great, this is super helpful. I appreciate it.

Brad Handler, Jefferies.

A lot of good questions, and a lot of optimistic questions, and I appreciate that. Mine is a little less so, so I guess forgive me. But, I guess nearer-term, I am trying to get a -- I', trying to understand a couple of things better in terms of what you can see.

So I think if we look at your rig count outlook for Q1, if we are doing sort of math right based on the visibility you give us through the course of the quarter, it looks like you are sort of expecting to exit the quarter at around 60 working rigs in the US. Is that --?

That's close. That's not too far off.

Okay. So basically there would be a handful of rigs working in the spot market relative to a contract rolloff, as it kind of proceeds the pace?

Correct.

Okay. So -- and is that a pretty good measure? I mean, how much -- I know this is sort of an obvious question, but are there -- is there opportunities perhaps to -- for that to be higher in some ways? Are you seeing -- is there quoting activity that might allow that to actually -- the spot market to be a little bit larger at quarter-end? Or just --?

That really turns on your macro call, Brad.

Yes, fair enough. But it is so short, I mean, we are talking about a month or two or three -- a month or two away, so it feels like a little less of a call and more what operators are doing right now.

Yes. You --

I'm just trying to line up somewhere.

Q1, I think it is safe to say, because of commodity prices, got off to a very difficult start. And that is why we are projecting that the average rig count is going to go to 70 in the US. And your number for an exit is probably not too far off. But I wouldn't say we had visibility on what I would call opportunities right now. It is still a difficult market.

Right. I appreciate it. I know it sounds a little -- probably sounds a little silly to ask it that way. But how much -- maybe you can help us understand. If something has gotten early terminated or turned on standby, can you generalize how much visibility you had before that happened? Is it a long conversation with you back and forth? Does it tends to be -- sneak up on you and you -- how have they worked?

It is in the range of weeks to 30 days. We just don't -- it is certainly not within a -- it's not -- we don't get a quarter's notice on some of these things right now. There are customers who are reacting to commodity prices. They pick up the phone, they call us, we have a discussion. But some of these things are happening relatively quick.

Right. Right, yes, certainly that makes sense. Okay. Okay, very good. Well, I know it is running late, so thank you. I will turn it back.

Thanks.

Mark Brown.

I know it is running late. I will -- wanted to see if you had any comments on the supply chain management efforts that you've run so efficiently, and you've talked about PropLogic sand management and such in the past. Any trends in terms of sand costs, sand hauling, chemical costs that you can point to in Q4 or early 2016?

You know, in 2015, I give a lot of credit to our operations, working with our supply chain teams, and then working with our suppliers to get our costs down, which -- in terms -- especially in terms of products like sand and chemicals, gets the cost down for our customers.

But in 2016, I am not sure how much more we can get out of this supply chain, whether it's from the mines, whether it is from the chemical suppliers -- we worked hard in 2015 to take cost of the system. It is getting more challenging in 2016 to take cost out of the system.

Understood. And then finally, just curious on Canada. Only three rigs over the quarter, very small scale. Just curious. Is that a region where you think the recovery is going to be lagged relative to the US? And does it make sense to maintain a presence there?

So, we have been in Canada for a while. We successfully put a new APEX rig up there under a term contract, and very pleased with the performance of that rig. So, we anticipate that, long-term, we will be successful in Canada, but Canada is in a very difficult situation as an industry right now. And their market reacts a little bit different from the US market, both in terms of magnitude and timing, just because their take-aways move in different directions, whether it is natural gas or oil in Canada.

All right, thank you very much.

(Operator Instructions) Our last question comes from Jason Wangler. Your line is open, Jason.

(Operator Instructions)

Yes, sorry about that. I just had one quick one. Just -- you did a great job of walking through a lot of the stuff. I'm just curious more specifically in the first quarter, as you have had those conversations about the standbys, how those have gone with the drop in oil prices and obviously the activity coming down? Have you seen a lot more of the standby contracts come up?

I wouldn't say it has been a big change. It only increased from 10 to 12 in the fourth quarter, and then we are likely to see some of those roll off in 2016. But I wouldn't say it is a big shift.

Okay. I will turn it back. Thank you.

Thanks.

And I am showing no further questions. I would now like to turn the call back over to management for closing remarks.

I would just like to thank everybody for their participation and look forward to speaking to them after the end of the first quarter. Thank you, everybody.

Ladies and gentlemen, this concludes today's conference. Thank you for your participation and have a wonderful day.