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Good morning. My name is Jamie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson-UTI Energy, Inc. First Quarter 2018 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. Thank you.
Mike Drickamer, Vice President of Investor Relations, you may begin your conference.
Thank you, Jamie. Good morning, and on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss the results of the three months ended March 31, 2018. Participating in today's call will be Mark Siegel, Chairman; Andy Hendricks, Chief Executive Officer; and Andy Smith, 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 U.S. Private Securities Litigation Reform Act of 1995, the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements are subject to risks and uncertainties as disclosed in the company's Annual Report on Form 10-K and other filings with the SEC.
These risks and uncertainties could cause the company's actual results to differ materially from those suggested in such forward-looking statements or what the company expects. The company undertakes no obligation to publicly update or revise any forward-looking statement. The company's SEC filings may be obtained by contacting the company or the SEC and are available through the company's website and through the SEC's EDGAR system.
Statements made in this conference 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 first quarter of 2018. We are pleased that you're able to join us today.
This morning, I'll turn the call over to Andy Smith who will review the financial results for the quarter ended March 31. He will then turn 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 will provide some closing remarks before turning the call over to questions. Andy?
Thanks, Mark, and good morning. As set forth in our earnings press release issued this morning, we reported a net loss of $34.4 million, or $0.16 per share on revenues of $809 million. Our operational results were largely in line with our expectations. However, the financial results were negatively impacted by a non-cash valuation allowance recorded against certain deferred tax assets and larger-than-expected permanent book versus tax differences, which combined to result in a small book tax expense for the quarter. Despite these book adjustments, our expectation is still that we will have a negligible amount of cash taxes paid in 2018.
Adjusted EBITDA for the first quarter of 2018 was $188 million. Cash flow during the first quarter was primarily used to fund capital expenditures, dividends and share repurchases. The cash balance at March 31, 2018 was $304 million.
Late last year, we went to the credit rating agencies for the first time and were recognized with a BAA Tier rating from Moody's and a BBB from S&P, both investment grade. In January, we issued $525 million of tenure senior notes, which bear interest in the 3.95% range. The proceeds from the offering were used to repay the outstanding amounts under our revolving line of credit and the remainder increased our cash balance.
In March, we amended our revolving line of credit, increasing the committed facility to $600 million, while also decreasing the LIBOR-based borrowing rate by 175 basis points and extending the maturity until March 2023 with two one year extension options. In terms of our credit agreement are consistent with our investment grade credit rating. The net effect of these two transactions was to reduce our cost of debt also increasing our liquidity.
Before turning the call over to Andy, here are a few of modeling related items. Our projected capital expenditures for 2018 remain unchanged at approximately $675 million. Depreciation expense for the second quarter is expected to be approximately $210 million, and SG&A for the second quarter is expected to be $34 million.
Our effective tax rate for the second quarter is expected to be approximately 10%. However, as pre-tax results approach breakeven, permanent differences between book and tax accounting have an outsized impact on our effective tax rate making it very difficult to predict.
With that, I will now turn the call over to Andy Hendricks.
Thanks, Andy. Turning now to contract drilling, we have seen a strong start to 2018 in terms of rig demand. We exited 2017 with 163 active rigs in the U.S. and as of today have 173 operating. Across the industry, the U.S. land rig count has increased by more than 80 rigs since the end of last year.
For the first quarter, our total rig count averaged 169 rigs, up eight from the fourth quarter average. Average rig revenue per day increased $590 sequentially in the first quarter to a higher-than-expected $21,540. Average rig operating costs per day were also higher-than-expected at $13,970, due primarily to higher-than-expected labor cost. In anticipation of continuing growth in our rig count, we increased our head count faster than our rig count during the first quarter in order to train crews for future rig reactivations. Additionally, labor costs were impacted by the expected increase in payroll taxes. As a result our average rig margin per day for the first quarter was $7,570.
At March 31, we had term contracts for drilling rigs providing for approximately $600 million of future day rate drilling revenue, an increase from $540 million at December 31. Based on contracts currently in place, we expect an average of 110 rigs operating under term contracts during the second quarter and an average of 75 rigs operating under term contracts during the 12 months ending March 31, 2019.
Turning now to our contract drilling outlook. As mentioned, we are continuing to see further strength in our rig count and the market for super-spec rigs remains tight. Within our own fleet, we have 135 super-spec rigs, of which 134 have contracts. Our only super-spec rig without a contract is in Canada and is expected to go to work following the spring break up.
After two years of substantial upgrades to super-spec, the number of upgrades across the industry slowed substantially during the first quarter. We estimate the industry's super-spec rig fleet grew by only 20 rigs to 570 rigs, the smallest quarterly increase since we started tracking the super-spec rig fleet.
We believe there are now a very limited number of idle rigs available in the industry that can be easily upgraded to super-spec, and therefore drilling contractors are having to focus on major upgrades to meet growing demand for super-spec rigs.
These major upgrades take longer to perform and are much more costly, thereby reducing the rate at which upgrades can be delivered to the market and requiring better customer contracts. We expect demand for super-spec rigs will continue to exceed the available supply through 2018 and into 2019.
As day rates continue to rise, we continue to believe that rig upgrades are the most capital efficient manner in which we can meet the growing demand for super-spec rigs and maintain our position as a leading provider of drilling rigs in the U.S. Our major upgrades have substantially all the capabilities of a new build, super-spec rig, but at a much lower capital investment.
All 12 of our previously announced major upgrades have customer contracts. Of these 12, four have been delivered and are included in our active rig count. The remaining eight rigs receiving major upgrades are all currently idle and therefore would be incremental to our current rig count.
Additionally, contemplated in our CapEx guidance are other lower cost upgrades, such as high-pressure circulating systems and/or walking systems to meet the growing demand for super-spec rigs. Most of these rigs are already active and therefore we do not plan to upgrade these rigs without receiving incremental rates to justify the incremental capital investment.
For the second quarter, we expect our rig count will continue to grow to an average of 176 rigs. It should be noted that the increase in our total rig count is expected, despite the seasonal weakness in Canada. Average rig margin per day is expected to increase by approximately $400, with average revenue per day increasing $250 and average rig cost per day decreasing $150.
Turning now to pressure pumping. First quarter pressure pumping revenues were relatively unchanged with the fourth quarter at $407 million. Despite major headwinds in the first quarter, we made progress towards improving our profitability as gross margin increased $2.8 million to $85.8 million. With colder-than-normal temperatures early in the quarter, we had approximately $10 million of lost revenue with crews primarily in West Texas were shut down due to temperatures being too cold to pump.
Additionally, cold temperatures contributed to industry-wide logistical challenges as the ability of railroads to move white sand out of the north was impaired. The challenge with the various rail lines was exacerbated by the slower than expected start-up of regional sand mines in the Permian.
Despite these logistical challenges, I'm proud to say that our supply chain organization was able to source sufficient amounts of sand to meet our planned needs and therefore, we had almost no sand-related downtime. However, some higher costs resulting from locating and procuring replacement sand contributed to higher-than-expected operating costs during the first quarter.
Early in the second quarter, we created our 24th frac spread, utilizing already active horsepower. And this spread is currently working in the Permian Basin. We have made significant progress in optimizing our spread sizes and asset utilization and now expect to be able to activate our 25th frac spread late in the second quarter with a substantial amount of the horsepower for this spread coming from already active equipment. The creation of these two spreads, largely using already active horsepower, is expected to have an appreciable and positive impact on our revenue and our EBITDA per active horsepower metrics.
Earlier in the second quarter, we repositioned one active frac spread from the Mid-Continent to Texas where it is expected to generate better profitability going forward. We continue to expect to mobilize a second spread out of the Mid-Continent in the next few months.
Turning now to our outlook for pressure pumping, we are confident that the issues that affected the first quarter were largely transitory in nature and therefore, their impact on the remainder of 2018 is expected to be minimal. We are confident that demand will be strong for pressure pumping, giving the significant increase already seen in the rig count this year and our visibility into the increasing rig count, which is the best leading indicator of future pressure pumping demand. We expect our pressure pumping revenue during the second quarter will increase 8% sequentially to $440 million. Pressure pumping gross margin is expected to increase by 13% sequentially to approximately $97 million in the second quarter.
Turning now to directional drilling, revenues during the first quarter were $48.6 million compared to $45.6 million for the 81 days that we owned MS Directional during the fourth quarter. Gross margin as a percentage of revenues was 22.5% compared to 29.4% during the fourth quarter. This decrease was primarily due to an increase in third-party rental expenses as we have experienced delays in the delivery of equipment that was ordered in 2017.
Equipment deliveries are improving, though we do not expect to be fully caught up until the second half of the year. For the second quarter, we expect revenues to improve to approximately $50 million with a gross margin as a percentage of revenues in the mid-20% range.
Turning now to our other operations, which include Great Plains Oilfield Rental, Warrior Rig Technologies and our E&P business. Revenues during the first quarter increased slightly to $26 million and the gross margin as a percentage of revenues increased to 31.6%. The gross margin improved and was better-than-expected at both Great Plains and our E&P business. For the second quarter, we expect other operations to generate revenues of approximately $27 million with a gross margin as a percentage of revenues of 30%.
With that, I will now turn the call back to Mark for his concluding remarks.
Thanks, Andy. We remain confident in our outlook for increasing activity. Customer conversations are robust for 2018 and going into 2019. Commodity prices remain favorable for increasing oilfield activity. The strong year-to-date and forecasted growth in our rig count, which has historically been a good leading indicator of pressure pumping activity, bodes well for increasing demand for pressure pumping and our other services.
With our bullish outlook for 2018, we expect to generate substantial free cash flow in 2018. We had expected to buy back stock later in the year as we began to realize more of the expected free cash flow.
During the first quarter, we used the unique opportunity presented to us by a lower share price to accelerate plans to return capital to shareholders as we repurchased 924,800 shares of common stock at an average price of $18.28. We currently have approximately $170 million of remaining authorization under our stock buyback program. In total, we returned more than $21 million of capital to shareholders in the first quarter through share repurchases and our regular dividend.
I'm also pleased to announce that the board has authorized an increase in our regular quarterly dividend from $0.02 to $0.04. Going forward, we will remain both disciplined and prudent with our capital as we consider opportunities to maximize shareholder returns.
With that, I would like to commend and thank the hardworking men and women who make up the company. We truly appreciate your continuing efforts. Operator, we would like now to open the call for questions.
Your first question comes from Sean Meakim with JPMorgan. Your line is open.
Thank you. Good morning.
Good morning, Sean.
So great to see the opportunism on the buyback in the quarter and the dividend lump is being well received too. The rig upgrade decisions seem more straightforward compared to frac and it seems like from our perspective maybe there's not much left to be done in terms of optimization of the current horsepower. Can you just talk about how attractive you view your stock today against frac reactivations? And then specifically, at this stage what do you think you need to see in the marketplace in order to do more reactivation in terms of your stacked horsepower?
So first off, we're very pleased with the progress that our team at Universal Pressure Pumping is making in being more efficient with the capital and the horsepower that we have active today. We activated the 24th spread out of currently active horsepower. And then when we activate the 25th spread, that will come largely out of existing horsepower but will also require some horsepower to be unstacked to make up that 25th spread. So we're really kind of pushing the end of what we're going to do with the efficiency in terms of the active spread, other than some minor improvements here and there. But any further deployments of frac spreads would require us to unstack horsepower.
As I've mentioned before, the cost for us to do that is around $6 million, so certainly we need visibility and pricing agreement or contract with a customer that gives us a program that makes sense for us to invest the $6 million to unstack a full spread. So that's kind of how we see that right now. But we see strong demand throughout 2018 in pressure pumping, and it's really based on the visibility that we have in our drilling business and knowing what the rig count is going to do in the U.S. And rig count is going to continue to increase. And so we will see strong further demand throughout 2018 in pressure pumping.
Okay. Fair enough. And then on the drilling side, one of your peers has indicated that they're now securing contracts in the mid-20s on day rates. Are you able to corroborate that in the market? And how is demand per term at the leading edge, given all that you've laid out in your prepared comments, with respect to operators trying to secure the rigs?
So what we said before is that we're seeing the leading edge in the low to mid-20s and I think it's safe to say at this point in the market that range is pushing more toward the upper end, but it's still a range in the low to mid-20s. But the market continues to improve. Pricing continues to move up in the day rates for drilling rigs for the base rig and we'll see that pricing continue through mid-2018. As I mentioned, we see this is as undersupply. The demand is outstripping available super-spec rigs in the market. With the terms on the leading edge, we're signing one-plus year term contracts for the rigs that we're doing the major upgrades on. And we see this continuing to improve as well.
Very good. Thank you.
Your next question comes from Marshall Adkins with Raymond James. Your line is open.
Good morning, guys. And your shareholders thank you for giving them some capital back. Mark, I want to shift to your comments on activity. I've heard a constant theme, of you and Andy both on visibility into rising rig count; oil is now pushing $70 here in the U.S. E&P cash flow's presumably up sharply. Albeit many of those guys have argued they're going to live within cash flow, so maybe reduced spending relative to historical levels. Where do you think the U.S. rig count, for the 1,000 rigs overall today, roughly where can we get by the end of the year from what you're seeing right now?
Hey Marshall, good morning. One thing I'd like to start with is you mentioned the WTI is moving up and we're pushing $70 a barrel. We've seen this trend in increasing rig count with WTI above $50 a barrel. One of my concerns is that people will confuse the increasing rig count with the increasing commodity price but I don't think they're necessarily related because our rig count was moving up back when WTI was about $50 a barrel. Now certainly, there's going to be a stronger demand with WTI at the higher levels, but we didn't have to have these higher levels, just to drive the increasing rig count in 2018. We already had that visibility. So that's kind of an interesting situation. But I think that we're in direct discussions with a lot of customers on what their plans are for the end of 2018 and into early 2019 already. So when we say its visibility, this is visibility directly with customers. I don't think we want to call out where we think that rig count is going to go, but we certainly see, across the industry, that demand will outstrip supply in the super-spec market.
Marshall, I just want to add, I think one of the things that we concluded is that as oil prices rise, activity in terms of utilization number of rigs working is sort of lagging, and sometimes 60, 90 day, lagging thing. So in effect, people are just starting to react to this $60 price now. Obviously, as – if oil would have crossed $70, you'd see a greater level of activity, stay above $70 for some period of time. And then I think the question becomes how much – who has available capital to support increasing development of super-spec rigs, because as Andy and I both spoke to, the market's pretty well spoken for already.
Right. What I hear you saying, just to paraphrase, is if we stay where we are right now, looking down four or five months from now, that demand is going to probably be there, but you may not have the supply to match that. So we should see further upward pressure on pricing, Is that a fair way to paraphrase what you just said?
Yeah, that's a great way to paraphrase it.
Yeah. We would both agree with you. We're nodding with our heads.
Okay/
Again my concern is people think that the demand on the super-spec rigs and rigs in general is based on today's commodity price and we don't see it that way. The demand today is based on commodity prices from a few months ago.
Yes. Perfect. Shifting gears to pressure pumping for one questionnaire. There's been a lot of debate this quarter on attrition of pressure pumping versus new capacity on the capacity adds, and the corresponding pressure or potential pressure on pricing and pressure pumping. So could you comment on your thoughts on where you see pricing within pressure pumping going, given the outlook we just discussed earlier for the rigs, and let's just talk about it through the end of the year.
Yeah, I think the best way to talk about pricing in pressure pumping is to really go back to where we were in the fourth quarter. At the beginning of the fourth quarter, we had industry utilization pushing probably above 80%. And towards the end of the fourth quarter, we had some challenges with some E&P shutting down operations. We got into weather delays. There were some sand and logistical challenges that the company's had to managing the first quarter. And so fourth quarter and first quarter, created challenges but as we worked through the – as we worked through the first quarter, things improved. And so the exit from Q1 into Q2 is certainly looking better. And that market is going to see demand from this increasing rig count. And so we believe that throughout 2018, that that allows us to move pricing upward on pressure pumping through 2018.
Thanks you all.
Thanks.
Your next question comes from Tommy Moll from Stephens. Your line is open.
Good morning. Thanks for taking my question.
Sure
Sure
So just to follow-up on the attrition point, I wonder if you could offer your macro view on the industry. Some of your peers have commented that as much as half of the quote and unquote "new builds" are going to replace old equipment rather than toward incremental fleets, you guys have you a view on that?
You know, that's certainly the view for some. We have a constant maintenance program that includes capital items that we purchased to continually keep our fleet running. So there are components that we see attrition with every year as well. But I think what people are missing and looking at the equation and trying to understand what's happening in pressure pumping is people aren't looking at the demand. I think people are still underestimating what the rig count is going to do and what the demand is going to be for pressure pumping later in 2018. And that's really what's going to drive the market more than trying to figure out how much is coming in and how much attrition it's going to have. I think that the demand from the drilling operations will create a supply challenge in pressure pumping.
Yep. Okay, thanks. And then just a follow-up on pressure pumping, you called out that some operating costs were a little bit higher than expected, given some delays in the local Permian mines that are starting up. What do you see for 2Q in terms of the timing of some of those startups? And do you expect any impact on costs for the current quarter?
We see minimal impact going forward from where we are now. Things improved throughout the first quarter. And our percentage of regional sand usage increased through the first quarter.
Great, thank you. That's all from me.
Your next question comes from Chase Mulvehill with Wolfe Research. Your line is open.
Hey good morning. Andy, I guess a question for you. When we think about gross profit per fleet, it looks like you're about $15 million on an annualized basis in 1Q. And guidance implies about $16 million for 2Q. Where do you think this can go as things kind of continue to improve or if they improve in the back half of the year? Where do you think kind of a normalized gross profit per fleet would be for your – for PTEN?
Well, I think in some ways, we're going to have to wait and see how far it can go. But certainly we are making improvements. As you pointed out, the projections for the second quarter show us to continuing to improve that EBITDA per spread metric. And I think that the market will allow our teams to continue to push that higher through 2018.
Okay. And sticking on pressure pumping, and if we think about over the next 12 to 24 months, do you expect to see any attrition across your fleet?
You know, as I mentioned earlier, in terms of attrition, we – our capital maintenance program already calls for equipment purchases in terms of components that we buy, whether it be engine transmissions, et cetera. So that's already in our CapEx budget. But in general, I don't see any attrition in what we're currently working right now.
Okay, thanks. I'm going to squeeze one easy one in. Duration on rig contracts, has – is the duration flat, or is it extending out a little bit here as the market continues to tighten?
Yes. As I mentioned, the contracts that we're signing for the major upgrades that we're delivering in 2018 are in the 1-plus range. So we're starting to see some extension out as the pricing moves upward.
Okay, awesome. I'll turn it back over. Thanks, Andy.
Your next question comes from Marc Bianchi with Cowen. Your line is open.
Thanks. First one on the drilling side, you've got the cost per day coming down a little bit here in the second quarter, but still elevated from where we were towards the back half of last year. Can you kind of talk to the progress there over the remainder of the year, how you see that unfolding, or perhaps we're going to stay at this higher level for a little while?
You know in the drilling cost per day average, about two-thirds of that number is labor. And we are carrying a little bit higher head count as we activate more rigs and we spend more time on training people who are new to industry. We've been able to get it down a little bit, going from Q1 to Q2. But I wouldn't expect any big decreases in that – as long as we continue to activate drilling rigs.
Okay, so. But still sort of a transitory item as you're activating. But once all activated, we should be seeing it migrate back towards that 13, 13.5 range?
Yeah, in that 13.5 range. Although it's possible, we could see with the tight labor market, some increases in labor costs. But as you know, in the drilling contracts, that allows us to move that through.
Great. Okay. And then maybe over to pressure pumping, you've got the other MidCon fleet that you're looking to move and you also have the 25th fleet that you'd like to deploy. What is the – at this point, do you have any customers identified and any customers that are going to be taking those? Or are you still in the process of trying to line somebody up?
We're certainly in discussions. We haven't moved out of the MidCon yet just because of commitments we have. But we're in discussions right now with customers on where these spreads are going to be working.
Okay. Is it fair to think that those – when they go to work would be accretive to that $16 million gross profit that Chase mentioned?
You know I expect, overall through 2018 that, that number continues to push, and that we'll see that overall for our fleet average, that it'll continue to move up through the year.
Okay. Great, thanks. Maybe just one more real quick on the horsepower per fleet, you're getting this efficiency benefit of having less horsepower per fleet. Where does this stand right now and how do you see that progressing as we move forward?
You know, as we came out of the Seventy Seven merger and integration, we weren't quite as efficient as we needed to be. And we've been able to work on that. Our team at Universal Pressure Pumping has done a great job there, freeing up the 24th spread. And now the majority of the horsepower for the 25th comes out of active horsepower. But I think we're kind of pushing the end of what we're going to do in terms of horsepower per spread. As I mention, we'll have to activate some of the stacked horsepower to round out that 25th spread.
Okay. Great, thanks, Andy. I'll turn it back.
Your next question comes from Byron Pope with Tudor, Pickering, Holt. Your line is open.
Good morning, guys.
Good morning, Byron.
Good morning. In thinking about the 110 rigs that are contracted for the second quarter versus the guidance that you gave for rigs working, I mean you'll be north of 60% of your rigs on term contract. Just given the tightness of the super-spec rig market, is that percentage essentially where you want it, which is to say, keeping some flexibility for the well to well market given the upward bias to day rates, just how do you think about that?
I think what it says and the way I see it is that it's an opportunity for us that as pricing continues to move up in 2018 that we have that flexibility with that part of the active drilling fleet to continue to push pricing through 2018. We may decide to layer some of those into longer-term contracts as pricing moves up for those particular rigs. We'll wait and see. We manage that really in terms of a portfolio between how much we have on longer-term and how much is in the shorter term. But I see it as an opportunity. It's an opportunity to continue to move our average revenue per day for the drilling fleet upward in 2018.
Okay. And then one question for pressure pumping. There's so much noise in Q1 with weather and logistics, but your frac job count was actually up sequentially and the average revenue per frac job was down a little bit sequentially. I'm assuming that that's just noise or – but suffice the question is, is that potentially a function of customers moving more towards self-sourcing sand? Or is it just noise because of the factors that we're trying to re-frac that in Q1?
Yeah. I think its noise. There was some noise at the end of Q4. There was noise in the beginning of first quarter, so it's hard to really take those on a quarter-on-quarter. And I think that as we get into second quarter, for us and hopefully industry a lot of this gets cleaned up, because I think that the impact there is really minimal for the rest of the year. And so, you'll see for operational numbers and financial numbers should smooth out from that standpoint.
Great. Thanks, Andy.
Your next question comes from Scott Gruber with Citigroup. Your line is open.
Good morning.
Morning, Scott.
Hey, Scott.
Andy, I agree with your assessment of demand growth here in both drilling and frac. But I do want to focus on the supply side. One trend I just find perplexing is the penchant for pressure pumpers to order growth capacity on a speculative basis. You look at the land drilling side of the business, and you see much more discipline historically, generally the drillers, including yourselves, only ordering a new rig once a contract is secured with some good term. You operate in both businesses and have been more disciplined on the frac side, so kudos. But just in general why do you think we see different behavior patterns when it comes to de-risking growth CapEx between the rig side and the frac side?
I think different companies have different drivers depending on where they are in the cycle of their company. For us, on the drilling rig side, we have no plans to build new rigs. We're only going to upgrade with contracts that make sense for us, like the ones we've signed for all 12 that we've got planned on the major upgrades this year.
And on pressure pumping, we've been careful about the pricing agreements and the contracts that we entered into to make sure that when we're making the investments that we're going to make that we're going to get a return on that and there's some kind of program there. As I mentioned, its $6 million for us to activate spread number 26, and so we want to know that we have a program there before we hire 110 people.
Got it. And as you work through the rig upgrades and the frac spread restarts, we make it to the point here where you do start to contemplate new builds, would you be willing to commit to not building land rigs and more importantly, pressure pumps without a contract in hand? For growth purposes, not for replacement, but as you contemplate growth CapEx, would you make a commitment to not build on a speculative basis?
Scott, I think that our behavior over many, many years really demonstrates the discipline that we have always shown. So you asked for a commitment, I'm not quite sure what that means. But I do know that we've been very disciplined about it. Quite frankly, we have horsepower that we – frac horsepower that we haven't activated, so we're in a very different position than some of our competitors who are out there in effect increasing their fleet by building more horsepower or in some cases, replacing horsepower, whichever it is.
But in either case, the discipline that we've shown and our interest in returning capital to the shareholders I think over the last 10 years it's been close to $1 billion of capital that we've returned to shareholders. And so, yes, I think we'll be very careful about any new commitments of capital we make and always be looking to de-risk it with contracts that are long enough and at high enough rates to justify the commitment of capital.
Got it. And look, I agree that your history certainly suggests a much different pattern than any in the industry. The reason I ask and the reason I'm being a bit forward about it, is I'm just trying to build some momentum around a different approach to growth CapEx. So I appreciate the thoughts, but that's the reason behind the question.
Well we salute your efforts. We concur, obviously our behavior and your view is consistent.
You know, we talked about it in our last earnings call what our capital expenditures were for 2018. That remains unchanged. And now we've got all those 12 major upgrades signed up on term contracts for growth in the drilling business, and in the pressure pumping business. Our current growth is coming from our active horsepower, so it's minimal investment to do that and we're signing what we think are good pricing agreements and you can see that in our forward profitability projection for Q2 and the increase in EBITDA per spread. So we think we're careful with the capital expenditures and that we're managing the investor's cash in a reasonably wise manner this way.
Quite frankly, we're hoping that you're going to be converting others, we feel like we're already converted.
Very good. I agree. So, good job on the quarter and good job with the capital return, and the market certainly likes it today.
Your next question comes from Ken Sill with SunTrust Robinson Humphrey. Your line is open.
Yeah. It was good to hear your comments this morning because I thought I was the only person on the crazy train that didn't think the pressure pumping market was already peaking and over. It's kind of amazing that it's ended before it started.
One question on pressure pumping, the pressure pumping fleet costs more than a rig now if you look at everything that goes into a fleet. And it has been kind of surprising following up on the last question that people are willing to put speculative, but it seems like you and some of your other larger peers are being more disciplined. Now how do you think this plays out with some of these private equity back guys adding pressure pumping when you guys are trading at five and six times EBIT to EBITDA?
Ken, I think that's a question that you're better able to answer than we are. Quite frankly, we're surprised that the market rewards people who do things that don't seem to show so much capital discipline. But we're not in effect the buyers of stock except for our own. So, all we can say when we see that is to be surprised.
No, it's an interesting conundrum. Getting through the...
I guess I hope that, in effect, the message that we're hearing from some of the analysts today on this call is received by the people who don't seem to have the discipline.
We'll see how that plays out. But in terms of your customer interest, things are getting better. Are you seeing a change in the nature of people looking to put rigs to work, is it biased more towards private guys that have been out of the market since oil dip last fall, or majors or public companies or they're just still a broad spread of everybody?
Yeah, it's still a broad spread. You've got a mix. You've got some of the biggest operators that you buy gas from at the local gas station to small operators that you've never heard off. And I think that's where the public markets don't have that visibility of a lot of these smaller operators who are healthy and financially well backed but they're still relatively small privates who don't come up on a lot of people's screens. But some of these are adding rigs as well.
Yeah. And I think that's an underlying swell of demand that it does get lost when you're looking at all the big public guys. How much idle capacity do you guys have left? Has that number changed at all? How much you're going to have to put into this fleet?
You know in terms of pressure pumping, we're 1.25 million active now. When we activate the 25th spread it's around half maybe a little bit more than half of that horsepower comes out of that currently active which means half to less than half comes out of the stacked horsepower. So that's where will be once we activate that 25th spread.
So that's going to be 40,000-horsepower spread...
We're averaging around the 50,000, a little more than 50,000.
Okay. That answers that question. And then my last question it seems to me that one of the things are people are struggling with in terms of margins is utilization.
One of your peers complained about customers not getting pads ready when you sit around with a frac fleet being idle for a few days it really hurts your margin. I mean in a tight environment, how do you see that evolving?
I mean, it seems to me like we could be faced with an issue of just having intermittent utilization interruptions because everything's tight for the next couple of quarters.
The way we see it and with the spreads we're deploying and then our projections we have very little white space in our calendar. So we are almost fully utilized the spreads that we have ordered.
So I mean you're not seeing the customers are getting delayed on getting on pads which kind of pushes the schedules around a little bit?
Well, you know. As we saw in Q1 had a lot of moving pieces especially early in the quarter, but Q1 proved, I think for the industry towards the end of the quarter and that bodes better for Q2, but currently, we have very little white space on our calendar.
That's great. Thanks I'll let somebody else ask a question.
Your next question comes from Michael LaMotte with Guggenheim. Your line is open.
Thanks guys. Good morning. On – I'm curious with the demand outstripping supply for the super-specs. What's the pull-through, if any on the conventional ACs? What's happening in that market in terms of potential reactivations in day rate?
Well, it's a good question. That some of these are working today. Those that are working, if they're not on our term contract I think that the super-spec rig rates which are pushing upwards in 2018 will lift what we would call the high spec rig rates in 2018 for the rigs that we have working that aren't super-spec. We're working 173 rigs total right now.
Yeah. So it's a little bit of a rising tide effect...
Absolutely.
...on the entire fleet. Okay. And then on a lot of folks obviously, on the Permian, but I'm curious if you can talk about rig and services demand in Appalachia and the outlook more specifically over the next 1 to 2 quarters in the Marcellus.
For us, Appalachia remains strong. I mean you see the rig count that we have on the website. Be nicer if gas prices were a little bit higher but we're very pleased with overall the activity that we have in drilling and pressure pumping in Appalachia.
So steady state sounds like nothing's pushing it or pulling it in either direction?
Not neither direction, but that market doesn't fluctuate as much either because a lot of the plans that are made by operators up in Appalachia are based on deliveries that they have to do it a year from now. So you just don't see the same fluctuations there as you do in the oil markets.
Yeah. If I can squeeze one in, Mark, on the buyback. In past years, decades past, the industry's been through boom bust cycle. And the current environment feels different in terms of sort of more steady state growth, which gives you a lot better, I'd say visibility on free cash flow. So the buyback historically have been very opportunistic. I'm wondering if, given that free cash flow visibility that you have, if there are thoughts that you could share around perhaps excess cash, may be minimum cash balances to hold on the balance sheet and ways that we can perhaps model excess cash going to work on a buyback on perhaps on a more rated basis as opposed to opportunistic.
Sure. We've said at the start of the year and reiterated today that we expect to generate substantial free cash flow in 2018. We're – because of the nature of the demand that we're seeing from our customers in effect reiterating that and feeling even more optimistic and even more constructive about the demand that we're seeing this year and the free cash flow that we expect to generate. And again, people have commented before the discipline that we're going to use with regard to our capital expenditures.
So, all-in-all, we do expect to generate a substantial free cash. And we have said to shareholders repeatedly over kind of the 20 years, I think I've been in this position, that when we've had excess cash, we've returned excess cash to shareholders. If you ask me to put a specific on it, a percentage, I've always thought that, that strategy always backfires because no matter what number it is, someone thinks it's too low. And then it reverses when you do it, someone is disappointed that you only did that.
And so quite frankly, I don't see the real benefit to the company in trying to, in effect, put a metric there. We will generate free cash flow. We will return cash to shareholders. The specifics of it will be obviously, announced each quarter.
Fair enough. Thanks, Mark.
Your next question comes from Waqar Syed with Goldman Sachs. Your line is open.
My question relates around M&A. You've been pretty active in the M&A market the last 12, 18 months. Do you see – do you expect to pursue that strategy going forward as well? And if so, then what kind of assets are you interested in? Are you going to broaden beyond what you're offering currently?
You know, Waqar, we were active in 2017, as we saw two opportunities that were particularly speaking about the MS transaction and the.
Right.
Seventy Seven transaction, which were particularly opportune for us in terms of our strategic direction that we had set long ago. We remain careful and thoughtful about what acquisitions are available. Quite frankly, we think that in the current environment, pricing expectations are higher than they were in 2017. And we're not sure about what the strategic opportunities are that will come to us this year or will be available to us this year. So we're going to continue to look at a lot of things. I kind of always think about it as we kiss a lot of frogs to find a prince and that's what's going to happen, I suspect in 2018. We'll look at a lot of situations, whether there'll be anything that meets our price and strategic needs is a question that's open.
Some of your recent transactions have been more around improving the drilling process and offering more services on the drilling side. Should we see additional acquisitions and opportunities around the same kind of philosophy? Or do you also want to maybe look into the completions side and maybe expand the offerings that you have on the completions side?
You know when we see very, very good technology, and we think that technology can really improve the services that we can deliver to our customers and we can acquire that technology at a good price, we're going to be buyers of it. Those are sort of smaller acquisitions around a certain kind of technology. When we see those, we'll try to jump on them.
You know, Waqar, we look for opportunities that have synergistic elements to it for what we do. As we've talked about, we do mechanical and chemical activities in and around wells. We try to stay relatively close to that. Sometimes these opportunities, while it looks like its part of an M&A market or changes in M&A market, some of these opportunities have been multiple years in the discussion. And the timing of these opportunities, when they materialize, is not always aligned with necessarily what the markets do either. So I'll just add that.
In one of the recent conference calls, management remarked that some of the E&Ps are pushing back or at least one E&P has pushed back on the Permian sand owing to the quality of sand and voting more in favor of the northern white. Have you seen anything like that from your conversations with customers?
We pumped our first West Texas regional sand job in January and we've seen our percentages of use of regional sand increase through the quarter. Each customers' going to have to evaluate if it makes sense for their reservoir. And it's hard for me to qualify where it's going to work and where it's not. But I would say that I'd suspect we'll see increasing usage of the regional sands.
Okay. And you said increased usage, is it with the same customer or multiple customers? Or is it all Midland, or is it also Delaware and Midland?
I think we're going to see increasing usage across multiple operators, just because there's that potential for the savings there for the operator by taking that logistics piece out in terms of bringing it by rail all the way down South. Of course, Midland is the easier place to use it. But I think some operators will use it in the Delaware as well.
Okay. Thank you very much. Appreciate the answers.
Our next question comes from Peter Luppino with AllianceBernstein. Your line is open.
Hi, guys. I guess I'm a little confused on reactivating that 26th spread. Is it, the cost is $6 million and the leading rates on the gross margins are about 16 (00:52:41), what's the hesitation?
Well, we're just in the middle of activating the 25th. So we just haven't called out that we're activating the 26th yet. That's all. It takes us about 90 days to crew up the spread. Once we get past 25, we'll be looking at 26.
Okay. So there's no other reasons why you may not go forward with it? Or I should say, what could be other reasons why you may not go forward with it other than the price and the cost?
Yeah, I'm going to take it back to the macro. I think with the increase in drilling rig count that we have visibility on, that demand for pressure pumping in 2018 is going to be strong. And we said that we're likely to activate spreads during 2018. And we've activated 24. We've called out 25. We'll keep you posted on the timing of others as we go through the year.
Okay. Thank you.
Your next question comes from Chuck Minervino with Susquehanna. Your line is open.
Hi. Good morning.
Good morning.
Just wanted to ask a couple of questions on the land rig site. You guys said you had a pretty good outlook here for the remainder of the year for more rig additions. I was curious if you're starting to see it now with this next leg up in crude prices that we've seen. Are we seeing it beyond the Permian? Or is it really still just concentrated in that area right now?
Yeah. It's one of the points that I think is important for this call, especially at this time, is that this – the demand for rig increases in 2018 is not based on today's commodity price. This is based on discussions that started months ago, based on commodity prices from months ago. Now do I believe that increase commodity price will increase the demand? The answer is yes, but we're not seeing that yet today.
Okay. And I know you guys are pretty well utilized in the Permian with most of your AC assets. Are you looking to still move assets into the Permian to accommodate that demand? Or are some, do you still have enough available capacity there to take what's needed?
As we do the major upgrades that we've talked about that we said are going to be incremental to the rig count this year that we have contracts for, those rigs come through our Houston yard and the majority of those rigs will end up working in Texas.
Got it. Thanks.
Your next question comes from John Watson with Simmons & Company. Your line is open.
Andy, we saw a strong quarter from other services in Q1. And the guidance for Q2 looks pretty good as well. Can you give us some additional commentary on the strength in that business and what the outlook is for the coming quarters?
Yeah. It's a combination of improving market dynamics for our rental business and our team at Great Plains is doing a great job there. And we also get some lift from commodity prices in the E&P business as well.
Okay, great. And then on pressure pumping, we talked about profitability per fleet to some extent. Is there a large spread between your best-performing fleet and your worst performing? Or is it pretty tight at this point?
I wouldn't say we have a large spread, but we do have room to improve, as we talked about. And I think that we will see that improvement as we work through 2018. And it's not just things that we're working on internal, but there's going to be strong demand for 2018 for pressure pumping just based on the visibility on the rig count.
Okay. Could you quantify that spread or would you rather not say?
No, I'd rather not call that out. We're working in multiple basins right now, so there is some differentials but there's opportunities for it to improve.
Okay. Understood. Thank you.
There are no further questions at this time. I will turn the call back over to the presenters for any closing comments.
We'd like to just thank everybody for your participation in our first quarter 2018 conference call and look forward to speaking with you at the end of our second call – quarter conference call.
This concludes today's conference call. You may now disconnect.