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Patterson-UTI Energy Inc
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Good morning. My name is Bonita, and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson-UTI Energy Second Quarter 2019 Earnings Call. All lines have been placed on mute to prevent any background noise. Afer the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions]
Thank you. I will now like to turn the call over to Mike Drickamer. Sir, please begin.
Thank you, Bonita. Good morning. And on behalf of Patterson-UTI Energy, I'd like to welcome you today's conference call to discuss the results of the three and six months ended June 30, 2019. 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 and 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 statements. 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 the 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 second quarter of 2019. We are pleased that you can join us today. This morning I will turn the call over to Andy Smith, who will review the financial results for the quarter ended June 30th. 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. As set forth in our earnings press release issued this morning for the second quarter we reported a net loss of $49.4 million, or $0.24 per share, which included certain charges totaling $16.3 million pre-tax or $13.5 million after-tax. Excluding these charges, the net loss for the quarter would have been $35.9 million, or $0.17 per share. Included in these charges is $3.6 million of bad debt expense, the first time we've recognized bad debt expense since 2012, and the charge of $12.7 million to reduce the carrying value of a deposit placed in 2017 on future sand purchases.
As you may remember, in 2017 the sand market was much tighter than it is today as pressure pumping activity was increasing and the industry was moving to finer mesh sizes. In order to increase our access to these finer mesh sizes, we placed the deposit as part of the sand capacity reservation contract. We have been amortizing this deposit based on discounts received on the sand purchases. However with a substantial decrease in sand prices, it makes good economic sense to purchase lower cost sand outside of this capacity reservation portion of the contract and thus we have revalued the deposit at its expected realizable value.
Excluding these non-cash charges, adjusted EBITDA for the second quarter would have been $177 million, which was used in part to repurchase $75 million, or 6.3 million shares of our stock. For the first half of 2019, we have repurchased $150 million of our stock representing 5.5% of our shares outstanding at the beginning of the year. Subsequent to the end of the second quarter, our board of directors increased the share repurchase authorization to $250 million.
In addition to the share repurchases, we have also paid dividends of $8.3 million in the quarter. Our balance sheet remains strong. Even after more than $165 million of combined share repurchases and dividends in the first half of 2019, our cash balance at June 30th improved to $256 million, an increase of just over $10 million from the $245 million at the end of last year. Additionally, our $600 million revolver remains undrawn and we remain modestly levered with a net debt to capital ratio of 20.9%.
Cash capital expenditures for the second quarter totaled $96.9 million down from $118 million in the first quarter. We now expect to spend $400 million in 2019, a decrease from our previous forecast of $465 million. This new forecast breaks down as follows: $235 million for contract drilling, including $115 million of maintenance capital; $110 million for pressure pumping, which is primarily maintenance related; $15 million for directional drilling; $30 million for our oilfield rental technology and E&P businesses; and $10 million for general corporate purposes.
While we are not prepared to give specific guidance for 2020 CapEx, we expect the 2020 capital spending would be lower as if drilling and completion activity remains around current levels. For the third quarter, depreciation expense is expected to be approximately $212 million, SG&A is expected to be $32 million and our effective tax rate is expected to be approximately 20%.
With that, I'll now turn the call over to Andy Hendricks.
Thanks, Andy. Before we get into our second quarter results, I wanted to give everyone an overview of what we're seeing in the market. The second quarter began with a sense of cautious optimism as oil prices rose throughout the first quarter and started the second quarter in the mid $60 range. Unfortunately, this optimism faded as concerns about trade, inventory levels and overall demand pushed oil prices into the low $50 range.
With the commodity price volatility and the increased focus on spending within budget, E&P companies are being extra vigilant in monitoring their spending. Historically, E&P companies would slow activity in the fourth quarter if they had reached the point of budget exhaustion, but this year operators seem to be slowing the spending run rate much sooner, so as to avoid reaching the point of budget exhaustion, which would put them at risk of exceeding their budget. The slowing of the spending run rate is expected to lead this to lower levels of drilling and completion activity in the third quarter.
In contract drilling, our rig count during the second quarter averaged 158 rigs down from 175 rigs in the first quarter. Average rig revenue per day increased to $24,200 and average rig margin per day increased to $10,170 both of which include $280 per day of benefit related to $4 million of early termination revenue we have received in the second quarter. At June 30th, we had term contracts for drilling rigs providing for approximately $720 million of future dayrate drilling revenue, an increase from $650 million at the end of the first quarter due to long-term contract extensions on several rigs with a major E&P. Based on contracts currently in place, we expect an average of 92 rigs operating under term contracts during the third quarter and an average of 58 rigs operating under term contracts during the 12 months ending June 30, 2020.
Turning now to our contract drilling outlook, we expect our rig count to average 142 rigs for the third quarter. Our super-spec rigs continue to have high utilization. However, within our fleet, our non-APEX rigs are the most likely to be released. And by the end of the third quarter, we expect that our active fleet in the U.S. will be comprised solely of APEX rigs. Average rig revenue per operating day is expected to be approximately $23,700 including early termination revenues similar to the second quarter level of $4 million. The decrease in average rig revenue per operating day is primarily a function of an increase in the number of rigs on standby whereby the rig receives a lower dayrate, but also has minimal operating costs. Average rig direct costs per operating day is expected to be approximately $13,900, which reflects lower costs for the rigs on standby, partially offset by lower fixed costs absorption and costs associated with STACK and rigs.
Turning now to pressure pumping, as expected our financial results for the second quarter were similar to the first quarter. Despite 2.5 fewer spreads on average during the second quarter, pressure pumping gross margin of $44.9 million was unchanged from the first quarter level while revenues increased to $251 million from $248 million in the first quarter. We averaged 15.2 active spreads in the second quarter and ended the quarter with 15 active spreads, the same level we had at the time of our last conference call in April. Our EBITDA per spread represented an 18% increase over the first quarter level. Since many of you adjust our reported EBITDA per spread for the capitalization of fluid-ins through the first half of this year we spent approximately $15 million in total on fluid-ins placed into service. On an annual basis, we expect to spend between $1.5 million and $2 million per active spread for fluid-ins placed in service. We have made significant progress extending the operating life of our fluid-ins, thus contributing to our lower pressure pumping CapEx forecast.
Before reviewing our outlook, I would like to take a minute to commend the crew of frac spread 113 in the Permian basin. We received orders from our customers on a regular basis and don't ordinarily mentioned them, but we are especially proud that this crew was recognized for operational excellence during the second quarter by the customer, a major oil company, and received an award for being its best contractor in the Permian. This is quite a distinction for universal pressure pumping. I would also like to recognize the crew of frac spread 108, which recently safely and successfully completed the well with the longest known lateral in the Permian basin. With a lateral length of 17,935 feet this well was completed with 52 frac stages using 2,200 pounds of profit per lateral foot.
Turning now to our third quarter outlook, we expect that lower drilling activity will negatively impact completion activity across the industry. Within our own fleet, we expect to maintain 15 active spreads throughout the third quarter though we expect a mix shift to more single well pads. Additionally, pricing continues to be challenging. Accordingly, we expect third quarter pressure pumping revenues of $225 million with a gross margin of approximately $35 million.
Turning now to directional drilling. Gross margin for the second quarter improved to $8.1 million from $7.4 million as a continued focus on margins and efficiency offset lower revenues due to decreased horizontal drilling activity during the second quarter. For the third quarter, we expect directional drilling revenues of $49 million with gross profit margins similar to the second quarter level. Turning now to our other operations, which includes our rental technology and E&P businesses. Revenues during the second quarter were $26.4 million compared to $31.2 million in the first quarter. Gross margin as a percentage of revenues was 33% during the second quarter compared to 30% in the prior quarter. The lower revenue was largely a function of the seasonal decrease in demand for certain rental fleet items. For the third quarter, we expect financial results in our other operations to be similar to the second quarter.
With that I will now turn the call back to Mark for his concluding remarks.
Thanks, Andy. Like many of you, we had expected drilling and completion activity to have reached the bottom by now, but that doesn't appear to be the case. Lower activity is affecting the entire industry, but one way in which we are differentiating ourselves from other energy companies and the entire market for that matter is in terms of cash flow generation. Through the first half of 2019, we have generated adjusted EBITDA excluding non-cash charges of a total of $368 million, which exceeded our CapEx by $153 million. When looking at our cash flow conversion relative to either EBITDA or revenues, we believe that we are a leader in the energy sector. When you look at our cash flow relative to our market cap, we have among the highest cash flow yield in not only the energy sector but also in the broader market in general and we are not just sitting on the cash.
We have been investing the cash we’re generating in our stock and have bought back more than $300 million worth of stock in the past 18 months or 9.5% of our shares outstanding at the end of 2017. Through the first half of this year, we have already repurchased $150 million of stock or 5.5% of the shares outstanding at the beginning of the year. We have also paid more than $16 million of dividends this year bringing the total amount of cash return to shareholders through the first half of the year to more than $166 million.
One reason we've been able to dedicate our cash flow to buybacks and dividends is the strength of our balance sheet. Whereas some companies with higher debt loads are being forced to restrain CapEx to generate cash in order to survive, we are able to fund the maintenance of our equipment, thereby preserving our future earnings power, while also being disciplined enough to take advantage of our public market equity valuation, which we believe does not adequately reflect the value of the underlying assets.
We fully understand the concerns that have may energy stocks uninvestible for many people, but therein lies the opportunity. We're not willing to settle for being the best house in a bad neighborhood and therefore we are doing our best to restrain spending, generate cash, and buy back stock.
Going forward we expect our focus – we expect to focus our cash flow on buying back our sock, while also prudently repaying some debt. Our cash balance at the end of the second quarter was $256 million, which is more cash than we need to maintain our daily operations given our $600 million line of credit and expected strong cash flow.
Therefore, we intend to use a portion of the cash through to some of the outstanding – of our outstanding debt with a primarily focus on the $300 million of private placement notes that we have that are coming due in October 2020. I'm pleased to announce today the company declared a quarterly cash dividend on its common stock of $0.04 per share to be paid on September 19, 2019 to holders of record as of September 5, 2018.
Without, I'd like to both commend and thank the hardworking men and women who make up this company. We appreciate your continuing efforts.
Anita, we would like to now turn the call over to questions.
Thank you. [Operator Instructions] Your first question comes from the line of Sasha Sanwal with UBS.
Good morning.
Thank you and good morning. So maybe to start just on drilling, as we think about the Q3 rig count guidance, can we get some color on what you’re seeing from different types of customers? You saw the contract extension with major – and maybe what indications are customers giving you about the rig requirements for 2020 if any, if rigs are being released?
So you can look at the different types of customers that we have across the U.S. North American landscape. As we looked at the major international oil companies that operate in U.S., they seem to be in whole – just kind of holding steady in their operations and therefore we were able to recontract a number of the rigs, we’re one of the majors.
When you look at the public independence, whether large or small, they seem to be exerting a lot of discipline in their budgets right now and trying to manage how that's going to look for the rest of the year. That's why we're guiding down on the recount the way we are. With some of the private players you still got some sitting on the sideline waiting to see what's going to happen with pricing volatility. So we're seeing a shift in the rig count where it's going to continue to move downward, but also you have to remember that we operate both super-spec AC rigs along with SCR rigs and we're seeing a shift in that mix.
But one thing I'd like to point out is that, in terms of our market share, which we don't chase market share, we're very focused on margins. But just looking at the numbers and what we believe is happening in the market, in terms of super-spec rigs, we believe that we're holding share and that's what's important in the market, and that's what generates free cash flow for us.
Okay, great. That's helpful. And then maybe just also touching dayrates, can we get your views on where leading edge eventually dayrates off to super-spec rigs today, and have we seen a divergence in rates determined [indiscernible] in the last few weeks?
I think it's hard to call out if there's been any diversions in terms and spots over the last few weeks. With rig count coming down, there is pressure on pricing, but also remember on super-spec rigs utilization is still relatively high. So, while there is some pressure, utilization is still relatively high.
Thank you. I'll turn it over.
Your next question comes from the line of Sean Meakim with JP Morgan.
Thank you. Hey, good morning.
Good morning.
So Andy, the E&P behavior seems to indicate that they are more concerned around the impact of dropping rigs than dropping frac crews, at least last year and into this year. Frac crews seem to be more how they are managing their budgets. So as some of the up rigs in both those markets. Does that give you any confidence going into the fourth quarter in terms of your rig fleet, particularly once you're only running on APEX rigs?
And I guess just on the pumping side, in that same time period what – something you wish to get more challenged in the UN, how do you think about decision making around stacking more fleets, the perimeters that could lead you to making those types of decisions?
You know I think it’s hard to have a visibility on what's happening in Q4 at this time. We're still working through what Q3 looks like. But, the way it seems that E&Ps are trying to manage their budgets right now, they're ahead of just the normal Q4 challenge. In other words, where budget exhaustion might happen later in the year, it seems that they're trying to get ahead of that managing it earlier.
So I think there's a chance that rig count may level out, may not drop as much as previously anticipated or activity in general, may not drop as much as it normally does in the fourth quarter relative to third quarter. But there's still not a lot of visibility yet on what’s going to happen in the fourth quarter.
I think in terms of frac activity, across the industry, frac activity will decrease just based on the rig count. And I think that our recount is one of the proxies on overall activity in North America. So I think there is a bit of a slowdown. We're going to see it in our schedule, but it doesn't warrant us dropping a frac crew at this point.
So for the third quarter we expect to maintain the same level of crews at roughly 15 throughout the quarter. But our frac spreads are generating positive free cash for us after CapEx and so this is still a good business for us, even though it seems like a challenging market.
Understood. I appreciate that feedback. So we don’t have much visibility on 4Q, why not talk about 2020. So you talked about what – the move in the CapEx budget down to $400 million and Andy also outlined the breakdown of the split, how you sort of spend it. So based on prior commentary, it sounded like your maintenance capital, which obviously going to have activity estimates on what that number looks like, but something south of $300 million seems where you place going to maintenance level. Maybe even something like $275 million. And so as you hit by the 2020 budget, could you maybe just help us set at base line on where you think the spending could that? And then from there you make decisions around incremental deployment into technology and/or rigs versus frac?
Yes. So in terms of what could happen in 2020, of course we don't have a lot of visibility. But any assumptions you make on 2020 in terms of our cash flow, and what we would spend on CapEx, the CapEx in terms of maintenance is going to be relative to activity. So let's say activities were to stay relatively flat at the exit of Q3 through Q4 and going into 2020, with activity down year-on-year in 2020, you can see maintenance CapEx down.
And as Andy called out, in our Drilling business, we had $235 million total for contract drilling, $115 million of which was maintenance. So it's possible that we don't do as many projects outside of maintenance. These projects are good for our business and it's worth the investment for this year, but maybe we're not doing as many in 2020. So certainly CapEx could continue to come down. We'd still be generating very good free cash flow as well.
Fair enough. Thank you for the feedback.
Your next question is from the line of Vebs Vaishnav with Howard Weil. Your line is open sir.
Hey, sorry I was on mute. My apologies. Thank you for taking my questions. I guess you kind of mentioned but just on the leading edge dayrates, like the implied dayrates is in declining, and I guess you kind of mentioned that it's somewhat impacted by the standby rigs. But could you just help on talking about what you are seen in terms of leading edge dayrates and what you see going forward?
Yes, so just to clarify we're saying that the average rig revenue per operating day is expected to be approximately 23,700 that also includes similar levels of early termination that we had in the second quarter. And it’s an increase, there's moving parts within this number and part of it as an increase in the number of rigs on standby. So I wouldn't say that there's a big dayrates element of that.
Now, as I mentioned earlier, certainly dayrates are under some pressure with the rig count coming down, but as our fleet, by the end of the third quarter is expected to be almost exclusively APEX rigs and super-spec rigs are still at relatively high utilization. It's not clear how much the pressure will affect us on the pricing yet in terms of dayrates.
Got it, okay. And just – I guess a guess picking back in on Sean's question, just if we think about 2020 and think about where you guys are in terms of basin presence for pressure pumping. Any thoughts around like, if all the basins that you guys are currently and make sense, we need to rationalize, if you can comment on that that would be grateful?
You know the basins that we work in today, which are primarily Permian, South Texas, Mid-Continent and Northeast in no particular order. They make sense for us today. We don't see any need today to rationalize or move any of the current spreads that we're working today. We've already done that on a number of cases over the past year, 1.5 year where we've moved spreads out of the mid-con and we've moved spreads between South Texas and West Texas, back and forth. But today I don't see any change right now for the rest of the year.
Thank you for taking my question.
Your next question is from the line member Praveen Narra with Raymond James.
Thanks, good morning guys.
Hey, good morning.
I guess we can keep on the pressure pumping theme just in terms of the idea of stacking fleets versus the inefficiencies you guys are expecting in the second half. Can you walk through kind of the idea of choosing to keep those fleets active, despite those inefficiencies and obviously, getting the CapEx reduction for the second half, we’re going to be free cash flow positive. But how do we think about that? Is it a basin scale issue or how do we – how do we think about the active fleet count?
And so when we think of the slowdown in activity, we think of the reduction in number of stages that we're going to pump in the third quarter versus the second quarter. And some of that's driven by mixed shifts and the type of work we're doing, where some of our crews are going to be moving from a multi-wells zipper frac pads to single-well pads. So when you do that, it doesn't give you the option to reduce the number of frac spreads, because you still have to have the equipment available, but that mix shift does negatively impact you on activity and efficiencies. And so we're seeing that shift, but, because we still need to cover the work, I expect we're going to run the same number of spreads.
Okay, understood. And then on the rig side, if I guess we can think about it, in terms of the activity and the reduction that you've already seen or that customers have laid out to you. How do you kind of think of the cadence of rig declines as we go through the quarter? Do you think in terms of an exit rate and rigs by – on standby rate have – we could see kind of the – most of the reduction happens at the beginning part? Or does it kind of happen when nearly throughout?
Well, even if I gave you our calendar of what that would look like, I can tell you we change. We have customers that delay their programs, delay their decisions or different things happen. So I think we're giving you the best case scenario of what we think the average looks like in the third quarter based on all that movement.
Okay. Thank you.
Thanks.
Your next question comes from the line of Taylor Zurcher with Tudor, Pickering and Holt.
Hi, good morning. Andy, I just wanted to follow-up on your response to the prior question on the mix shift you're seeing in pressure pumping. Is that in the mix shift towards more single-well pads in Q3? Is that primarily a function, I assume of changing customer mix or is it a function of geographies you're working in today? Any detailed that'd be helpful.
Well in one particular case it's the same customer where it's just a different part of their program that, that we have. And so you know, their program would have multi-well pads and zipper fracs for a period of time. Then it goes over to single-wells then it may eventually go back to zipper fracs, so it's just a shift in the customers’ internal program and in other case it’s a frac spread moving from one customer to another customer. So it varies and it depends. I wouldn't say it's any kind of industry trend and wouldn't surprise me to see a shift back in the future as well. It just happens to be what our mix looks like in the third quarter.
Okay, okay, got it. And on the rig side, I know there's a lot of moving pieces at the cost line as it relates to lower fixed cost absorption from standby rigs et cetera. But is there any way to frame the order of magnitude for the – in terms of the cost impact to idle some of these rigs and stack them as they roll off contracts? Just to kind of calibrate a baseline OpEx per day that we should use moving forward?
It's really a minimal cost and doesn't work in too much. And when you look at our 13,900 a day in operating costs, two thirds of that is roughly labor. So, I wouldn't say there's any real cost on the stacking to call out. It's fairly minimal.
Okay, I'll try to squeeze one more. And in terms of some of these rigs coming off contract, it sounds a lot of them are SCR or legacy type rig, non-APEX class rigs. What's your view or outlook as these sorts of rigs roll off contract as it relates to eventually finding follow-on work from probably out in 2020, but I guess a long winded way of saying is there any chance that that some of these rigs actually find their way back into the marketability stacks at some point moving forward?
Yes, history has shown us that lower spec rigs like these are very dependent on commodity price and commodity price moves higher, you'll see these rigs go back to work. So I wouldn't make any kind of premature call that the end of this class of rig I think is really dependent on commodity price. And just in the market we're in today with the volatility we've had in WTI, the challenge that operators are having, making decisions whether to work a rig or not work a rig and the publically traded operators that are under a lot of pressure to stay within budget. This is just where we're landing. But again the super-spec rigs, which generate the majority of the cash flow for the drilling business, utilization is still relatively high.
Okay, great. Thanks for the responses.
Your next question is from the line of Brad Handler with Jefferies.
Thanks. Good morning, guys.
Hey, Brad.
If I could ask you please first to speak to I guess the competitive landscape in the pumping side. There is evidence we're hearing from other of your public peers around shutting in frac fleets, some even at a quicker pace than I think that the market is expecting. Can you comment on that – on sort of the competitiveness of bidding? Are you seeing – I don't know if in this – in some of the transfers if you're still seeing activating bidding or if it's a lot more negotiated because of dedicated relationships, but any commentary on kind of that competitive landscape would be interesting to hear.
So the majority of our frac spreads work under dedicated agreements, so it's only the minority of our frac spreads where we might be in a competitive bidding. But that being said I think we become more competitive in our bidding. Our teams have done a very good job of improving our efficiency and there's still opportunity to do so. And that reduces our OpEx cost. We also called out the $110 million of planned CapEx for pressure pumping.
Our fluid-ins spend, which is the first time we've ever really given anybody clarity on this on an annualized basis is only $1.5 million to $2 million per spread, which is probably much lower than most people model for us. And so we thought it was important to call that out as well because our teams have done a really good job of getting control of these costs, doing a lot of technical work to improve efficiencies, improve the life of fluid-ins and it makes us competitive in our bidding processes. And so, our 15 spreads that we're planning to work in the third quarter generate free cash flow after CapEx. So we think we're very competitive in that respect.
Understood and yes you're right. Certainly, it's lower than we were modeling for your fluid-in expense, so at least one affirmation there. Okay, so I think I understand that point, but maybe the other half of the question was going to be anyway and it sounds like you've half answered it. What are you seeing with pricing in the sphere where it is competitively bid or I think in general pricing sounds like it was flattish in 2Q, but are you seeing things get that much more competitive again as the work – as the volume of work whittles down?
I think there is pressure under pricing in pressure pumping. I think in some of the cases where we do have to bid, pricing comes down a little bit in the third quarter. But again, I think our teams are doing a great job controlling the cost side of that equation right now as well. Now, we have the challenge of the mix shift in the third quarter going from multi-welled zippers to single well pads for some of our crews. And that's going to reduce the overall activity and efficiency in terms of stages per quarter. But I think our team is doing a good job on the cost side right now, but there is pressure on pricing for the spreads that we have to go out and do it.
Understood. Okay, thanks very much. I'll turn it back.
Thanks.
Your next question is from the line of Chris Voie with Wells Fargo.
Good morning.
Good morning.
Just question on dayrate and margins per day. If I've done the math correctly on your guidance and the impact of the termination, they get to about 9,500 a day, somewhere in that range in the next quarter on an adjusted basis. Just curious if you were to roll current leading edge rates, where you see them being bid over the last few weeks through. Would force you likely to – excuse me, be likely to trend lower than that 9,500 range?
I think it's too early to know what the average margin per day is going to be on the rigs in the fourth quarter because a lot of it will depend on the mix of rigs on standby as well.
Okay. And you didn't call out the number of rigs that you have on standby, did you?
No.
Okay. Is that standby rig dilutive or accretive to the overall margin for drilling on average?
It's roughly neutral, but it depends on the mix at the same time.
Okay. And then just one on pressure pumping if I could. I'm curious at – when – if you have these dedicated customers that are switching to wealth well operation, does your contract kind of account for that lack of efficiency that you're going to get when you switch to that and raise the price per stage? Or is it something where you have to kind of carry the extra cost of that switch and efficiency when you go to that kind of operation?
Every pricing agreement is a little bit different. Every pricing agreement is based on what we anticipate and what's communicated to us is the potential scope of work. And so in some cases, we maybe doing a multi-year agreement that would also include taking account of these shifts and they may happen from month to month or quarter to quarter and some may include that already.
Okay, thank you. I'll turn it back.
Thanks.
Your next question comes from the line of John Watson with Simmons Energy.
Thank you. Good morning.
Good morning.
Good morning.
Andy, I apologize if I missed this. Did you call out where you expect the rig count to bottom in 3Q? And if not, would you mind sharing that with us?
No, we're certainly not calling a bottom in the third quarter. It's too early to know exactly what's going to happen in the fourth quarter. Rig count could stay level. It could drop a little bit more. I think what we are trying to explain is that instead of E&Ps, you know, just pushing their operational activity steady through the end of the year and then a big roll off in the fourth quarter. This year we're seeing E&Ps get ahead of that where they're slowing down earlier in the year. But again, it's hard to know exactly what that means for the fourth quarter yet.
Got it. And on the pumping side, we talked about electric fleets on the prior call and it seems like that wasn't of interest for Patterson today. What about dual fuel tier four fleets? Are those something – those types of upgrades, something that you've contemplated? I know you have a couple of dual fuel tier two fleets, but any interest in dual fuel tier four?
So we have more than a couple dual fuel spreads. Every spread that we operate in the northeast has the ability to operate with dual fuel. I believe on any given week we probably operate as many or more bi-fuel frac spreads as anybody in the industry. In terms of tier four, we have the ability to do tier four bi-fuel. We don't operate tier four bi-fuel today just because it's not required by a particular customer, but we certainly have the capability to move in that direction. We've been adding more tier four engines for particular customers this year. They could easily be upgraded through an OEM upgrade to bi-fuel as well if we need to. It's not a big capital cost.
Okay. Thank you. And I'll try one more on drilling pricing. You all are not focused on share your focus on returns, which is admirable. Have you seen any type of shift from your competitors who are becoming maybe more focused on share than Patterson is?
I wouldn't say we've seen any particular shifts. I think our competitors – in general behavior has been steady with what they've historically done.
Okay, understood. Thank you.
Relative discipline in the market, especially since super-spec rig utilization remains relatively high.
Perfect. I appreciate it. Thank you.
[Operator Instructions] This question is from the line of Waqar Syed with AltaCorp Capital.
Thanks for taking the call. Andy, just a general clarification question on your comments regarding pressure on rig dayrates. Is that’s a comment for super-spec rigs also? Or is that for low spec rigs?
I think it's a general comment with the rig count coming down, even super-spec rig counts coming down a bit too and it does put pressure on pricing. I don't think we could ignore that. And we'll just have to wait and see how that that really plays out. A lot of these rigs are working under contracts right now. And there is relative discipline in the market. So I think it's too early to say how much that's going to affect pricing on super-spec rigs, but we do acknowledge there's pressure.
But have you seen rigs come off as yet in any of the contract renewals for super-spec?
We've seen a little bit of movement, but it's too early to know what the impact is on our average rig revenue per day. If you look at third quarter, most of that's impacted by the mix of rigs you want on standby.
Okay. Now, in terms of the industry rig count, you mentioned that your rigs would be down, but does it imply that industry rig count could be down maybe about 40, 50 rigs from here in the third quarter?
Well, I do think that our rig count, like other large contract dealers is a proxy for what's happening in North American. And I think that while our total rig count maybe moving down a little bit faster than others, our super-spec rig count is probably moving down at the same rate. So it's – you can take that and interpolate it to what the overall number is, but I do think the industry rig count is coming down.
Okay. And what would you say the super-spec rig utilization is currently?
It's very close to 90%, but it's relatively high still today.
Okay. Now your comments on a weakness, upcoming weakness in pressure pumping as well as in drilling, is that a comment for all basins? Or is it – you're seeing particularly more severe pressure in some market regions versus others?
I think it's a comment across all basins because the pressure is equal on all of these publicly traded E&Ps that work across the U.S. to stay within their budget. Now, every E&P has varying levels of their own internal cash flow that affects their budgets, but – because that pressure is equal across all of those public E&Ps in all the basins.
Understood. And then just one final question. If you – it's up to you if you would choose to address that, but there was a Reuters article sometimes back about possible asset sales that you may be considering. Do you want to comment on that?
We didn't think too much of that article and we still remain focused on improving our own internal efficiencies and still providing cash flow after CapEx in our pressure pumping business.
Great, thank you very much guys.
Your next question comes from the line of Tommy Moll with Stephens.
Good morning. Thanks for taking my questions.
Thanks.
I wanted to double back on electric frac. How much inbound have you had from customers asking you about it? It's something that it seems the E&Ps particularly the integrators are interested in and presumably asking for – asking about. There's a tension there given the capital discipline across most of oilfield services landscape at this point. But I'm just curious for – from the customers’ perspective they'll ask you about it anyway if they want it and have you had many inbounds on the topic?
I think there certainly is questions from operators on electric frac. What does it mean and how does it work and what are the benefits and what are the challenges as well. And we certainly know electric fracs very well. On the technology side of our business, our division Current Power has done the electrical systems for several electric frac spreads. And so, we certainly understand the technology. We understand what it takes to deploy it, et cetera. We just don't think for us that it makes economic sense. We don't see ourselves adding capacity. We're very focused on generating free cash flow in this business and adding electric frac spreads and the costs around that for us just don't make sense.
Okay. Shifting gears to the land drilling side, I want to talk about the automation. You've got Superior QC. And I wonder if you can give us any insight into the pipeline to the extent one exists for any drilling automation software that you might introduce at some point. And maybe just more generally with any of the technology value add that you can sell around the rig. How do you envision going to market outside the dayrate structure potentially?
So we certainly have a pipeline of technology that we're working on. We're probably a little quieter than others on exactly what we're doing. On some of the previous calls, I've talked about our Cortex operating system that we layer on top of the rig AC control system. And this allows us to also plug-in various apps to help improve the efficiency and controls on the rigs. We're in the early days of field testing some of these apps. We’re also riding other apps. They do a variety of different things on the rig and we'll get into more of that probably later when we're ready to talk more about that pipeline.
And when it comes to getting the value, we want to make sure we get the value for what we're putting into this. Now, it's software. It's software development, very little on the hardware side. So, we've got some engineering costs there, but it's not a big CapEx deployment to put this out on a rig and that's a positive. But the rig can improve its overall efficiency. So we'll look at various models outside of the dayrate for when we do add-on technology because it's certainly our intent to get our value for our investment when we do improve performance and efficiency on the rig.
Thank you. That's all from me.
This question comes from the line of Chris Voie with Wells Fargo.
Hi guys, just one more. A little bit of a clarification, on the commentary you put out on the fluid-ins, I think you said $1.5 million to $2 million per spread in the first half of the year. The spread count has come down a bit. It since that's just a – what you're purchasing in that period? Is that a sustainable level? Or is that in part benefiting from the fact that you're stacking some fleets and the purchase rate might be a little bit lower?
Well, first off, just to clarify, that wasn't the first half of the year. The $1.5 million to $2 million was an annualized estimate. So I'll hand it over to Andy Smith.
Yes, we spent $15 million in the first half of the year. And if I’m remembering your question correctly, we think that kind of the run rate on sort of a per spread basis for the first half, it's good for the second half as well. So, as Andy said, it's $1.5 million to $2 million per spread on an annualized basis.
We've done a lot of work in that area to try to get those costs down and certainly most estimates out there are running higher and we wanted to call that out.
Okay, that's helpful. Thank you.
Thank you. That was our last question. I'd now like to turn it back over to Mark Siegel.
Everybody, we appreciate you are participating in our conference call with respect to the second quarter earnings. We look forward to speaking with you as we announce third quarter. Thanks everybody.
And this concludes today's conference call. Thank you for your participation. You may now disconnect.