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Patterson-UTI Energy Inc
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Good morning. My name is Dan and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson-UTI Energy Second Quarter 2018 Earnings Conference Call. Thank you.
I would now like to turn the conference over to Mr. Mike Drickamer, Vice President, Investor Relations. Please go ahead.
Thank you, Dan. 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 and six months ended June 30, 2018. Participating in today's call will be Mark Siegel, Chairman; Andy Hendricks, Chief Executive Officer; and Andy Smith, Chief Financial Officer.
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 or 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 filing 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 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 2018. 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 30. 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, for the second quarter, we reported a net loss of $10.7 million or $0.05 per share on revenues of $854 million. Adjusted EBITDA for the second quarter of 2018 increased 8% sequentially to $204 million. During the second quarter, we returned $42.4 million to shareholders, including dividends of $8.8 million and share repurchases of $33.6 million. At June 30, our net debt to capital stood at 18.5%.
Our projected capital expenditures for 2018 remain unchanged at approximately $675 million. As discussed in our press release, subsequent to the quarter, we entered into agreements to provide four upgraded rigs under long term contracts. These contracts each have a duration of four years, and we expect to recover the incremental capital required for these upgrades within the term of the contracts. As such, we have increased our drilling CapEx budget but have reduced other CapEx primarily from pressure pumping by a corresponding amount. The reduction in the pressure pumping CapEx is primarily the result of lower expected spend on maintenance CapEx due to improved performance and, to a lesser extent, less maintenance and reactivation CapEx due to a softening market.
Depreciation expense for the third quarter is expected to be approximately $215 million. SG&A for the third quarter is expected to be $36 million. Our effective tax rate for the third quarter is expected to be approximately 15%. 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 difficult to predict.
With that, I will now turn the call over to Andy Hendricks.
Thanks, Andy. In contract drilling, during the second quarter, our average rig count increased by seven rigs to 176 as demand for super-spec rigs remained strong. Our results in contract drilling exceeded our expectations with average rig margin per day during the second quarter was $8,270, a sequential increase of $700, which resulted from a $330 per day increase in average rig revenue per day and a larger than expected decrease in average rig operating cost per day. The increase in average rig revenue per day was better than we expected due to the continued strength in rates for super-spec rigs.
On the cost side, in addition to the expected decrease in labor costs associated with payroll taxes in the second quarter, we also benefited from some transitory items that positively impacted second quarter expenses.
At June 30, we had term contracts for drilling rigs providing for approximately $680 million of future day rate drilling revenue, an increase in our backlog from approximately $600 million at March 31.
Since the end of the quarter, we have signed 17 contracts providing for more than $200 million of future day rate drilling revenue. Based on contracts currently in place, we expect an average of 119 rigs operating under term contracts during the third quarter, and an average of 81 rigs operating under term contracts during the 12 months ending June 30, 2019.
As Andy noted earlier, since the end of the second quarter, we have signed contracts for four additional rigs with major upgrades for the Permian Basin, two of which are expected to be delivered in late 2018 and two in early 2019, and each with a four-year term. These newly contracted rigs will be state of the art APEX-XK and APEX-PK rigs, and will have an average upgrade cost of approximately $15 million each. The increased upgrade spend, as compared to previous major upgrades, is due to fewer components on hand, and also, as we go deeper into our fleet, more work is required.
It is important to note that with the favorable day rates and the four-year term, all four of these rigs are expected to pay back the capital investment for the upgrade within the terms of the contracts. We believe these are compelling economics. Since the beginning of this year, we have delivered nine rigs with major upgrades and we have customer contracts to deliver five more this year and two in early 2019.
Turning now to our contract drilling outlook, we estimate there are approximately 600 super-spec rigs in the U.S. of which Patterson-UTI is one of the market leaders with 142 super spec-rigs in our fleet. Across the industry, many of the easy upgrades were performed in 2016 and 2017.
As the extent of the upgrade necessary for rigs to reach super-spec capability has increased, the pace at which upgraded super-spec rigs are being delivered to the market has slowed. We estimate only 50 rigs have been upgraded to super-spec capability through the first half of this year, and the super-spec rig market remains very tight. We've spent a significant amount of time to understand the plans of our customer base, which is one of the broadest in the contract drilling industry. We recognize that the investment community has concerns about the industry, including the potential risk to activity and pricing from Permian differentials. However, we expect demand for super-spec rigs will remain strong as evidenced by the number of contracts we signed since the end of the quarter. We will continue to de-risk to the extent possible any additional upgrade capital through attractive rates and contract terms.
For the third quarter, we expect our rig count will continue to grow to an average of 180 rigs. Average rig revenue per day is expected to increase approximately $250 per day during the third quarter, and average rig cost per day is expected to increase $200 per day. We are actually seeing more significant increases in day rates in the current market than what is suggested by our expectation for the third quarter, but the full extent of these increases is being masked in the back half of 2018 by the roll-off of older higher rate contracts.
We still have six high day rate legacy contracts, of which five are scheduled to expire in the third quarter and the last one in the fourth quarter. Further to this and looking forward towards the end of the year, we expect a continued increase in our super-spec rig count. We still have customers that intend to add super-spec rigs into early 2019.
Turning now to pressure pumping. Our results fell short of expectations for the quarter with revenues of $425 million and gross profit of $82.4 million. The shortfall was due primarily to unexpectedly high idle time rate in the quarter as a result of operational delays at multiple well sites unrelated to our pumping operations. Our pressure pumping operations were held at numerous times for challenges with third-party wireline, coal tubing, and even mechanical issues in customers' wells. The market for pressure pumping was also softer late in the quarter due to what we believe is a result of some oversupply versus the current demand, which impacted our ability to find short term work to fill the unexpected holes in our schedule.
We are making good progress in the initiatives taken to improve our financial performance in pressure pumping, and we're disappointed that the softening of the market and lower utilization at the end of the quarter masked this progress. One area of improvement is in fluid ends, where our team has increased fluid end life through various technologies and initiatives. We believe that we have reduced the number of fluid ends used per spread each year by one-third through the use of improved materials, new designs, and the ability to rebuild certain designs.
During the second quarter, we activated two frac spreads and ended the quarter with 25 active spreads. Our 24th spread was activated early in the second quarter and contributed revenue during most of the quarter. Our 25th spread was reactivated late in the quarter, and therefore, did not significantly contribute to second quarter revenues. Given near term market conditions, we do not plan to reactivate additional frac spreads at this time. For the third quarter, we expect pressure pumping revenue to decrease 5% and gross profit to decrease approximately 7.5%. However, over the long-term, it is worth noting that the continued strength in the super-spec rig counts which we have discussed bodes well for pressure pumping demand.
Turning now to directional drilling, activity increased during the second quarter, and as such, revenues improved to $52.7 million from $48.6 million during the first quarter. However, margins continue to be negatively impacted by third-party rental expenses incurred due to ongoing vendor delays in the delivery of various key components for our proprietary downhole motors and MWD tools.
For the third quarter, we expect revenues to be similar to the second quarter with a gross profit margin of approximately 20%. We expect to see cost relief from these third-party rental expenses and consequently, margin improvement late in the year.
Turning now to our other operations, which includes Great Plains, Oilfield Rental, Warrior Rig Technologies, and our E&P business. Revenues during the second quarter increased slightly to $26.5 million, and the gross margin as a percentage of revenues increased to 33.9%. For the third quarter, we expect similar results to the second quarter.
With that, I will now turn the call back to Mark for his concluding remarks.
Thanks, Andy. Demand for super-spec rigs remains strong. In contract drilling, which accounted for approximately two-thirds of our EBITDA during the second quarter, we expect further improvement in both our rig counts and average dayrates. I believe it is worth reiterating that just this month, we signed 17 contracts, which includes four rigs with a four-year term that we will expect will provide for the full payback of the capital investment under the contract term.
In pressure pumping, we began seeing industry softness late in the second quarter due to an oversupply in the market and because some E&P companies' activity and capital spend are ahead of budget. It is disappointing to hear our peers continuing to plan to add additional horsepower to this market in the near future. We believe that given these headwinds in the market, the building of new frac spreads, reactivating idle spreads and chasing market share, given the current oversupply, will lead to worsening returns on capital for the entire industry.
We continue to see great value in our company in our equipment, people and operations. During the first half of the year, we repurchased more than $50 million of stock, including more than $33 million in the second quarter. In addition, our board upped our share repurchase authorization so that it currently stands at $250 million.
In times of uncertainty, it is important to maintain a long-term perspective. We will continue to balance CapEx opportunities with returning capital to shareholders in order to seek the best term, best long-term returns for our shareholders. I'm also 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 20, 2018 to holders of record as of September 6, 2018.
With that, I would like to both commend and thank the hard working men and women who make up this company. We appreciate your continuing efforts. Operator, we'd like to now open the call to questions.
Your first question today comes from the line of Sean Meakim with JPMorgan. Please go ahead.
Hi. Good morning.
Good morning, Sean.
So, you noted in your prepared comments, a lot of positive momentum in the drilling business and 3Q looks like it's set up pretty well. So given there's plenty of upgradable rigs still in inventory and there's this growing appetite for the significant terms, is there any reason that you think dayrates need to move above the mid-20s just given how solid the economics are for upgrades, or perhaps, do we just see the market shift towards greater mix of longer-term contracts?
I think it's both the combination of the two because I think that, and we've been saying this for several years coming out of the downturn in 2016, as this rig count, and especially the high-spec super-spec rig count, continues to go up, the dayrates, and especially the leading edge and what people are contracting for these rigs, continues to move up as well. And when you look at the economics for us to upgrade some of these rigs, it's going to take some high dayrate. But I think the market is moving in that direction.
Sean, I just would add that our customers get tremendous value from these highly technical, highly sophisticated rigs. And they recognize that and are willing to pay for that.
I appreciate those comments. And then thinking about beyond the third quarter, it seems like increasingly, the third quarter is becoming the best quarter of the year given the way E&Ps are sticking to their more, a real focus on calendar year budgets. So, do you see seasonality in the rig count and maybe completions activity in the fourth quarter in line with what we saw last year in terms of seasonality? Could it be better or could it be worse, just leaving aside the obvious unknown with weather impact?
I think in terms of contract drilling, we see that the super-spec rig for us continues to go up and that our rigs that aren't super-spec will be roughly flat going forward. So therefore, our rig count is actually moving up. And I think that the seasonality doesn't affect that much. We can have a little bit more seasonality in completions, but I think it's too early to know at this point what's that going to look like.
Okay, fair enough. Thank you, guys.
Your next question comes from the line of Jim Wicklund with Credit Suisse. Please go ahead.
Good morning, guys.
Hey, Jim.
Congratulations on the four rigs. For four years, that's a milestone in the business and the whole recovery, so good job. The other 13 rigs that you've got contracts for, what's the average term on that tranche of rigs? What does the follow-up market look like?
The average term on those rigs is in the range of a couple years. It just depends on when we sign those contracts.
So, we're away from the six-month deals being called contracts by the end of and we're moving past six months or one year to a large extent at this point?
We're still signing a mix of contracts. I think the important part is that we signed 17 term contracts since July 1. That's been big for us. It just shows you the market in general.
No question.
I'd say this, Jim. If we're going to have to spend significant money, the contract's going to have to have some term to it. That's really what I think you're hearing from us. And when we get excited about the rates, we'll sign for longer periods.
Got you. Well that's the way it's supposed to work. That's why I'm excited about the four years. Okay. Okay. And my follow-up, if I could. Go ahead, Andy, I'm sorry.
I was just going to say, we recognize the concerns in the market right now. And for us to sign contracts that made sense to do some major upgrades that we're going to have to do on these four rigs to get them up to that full APEX-PK level, we had to de-risk that. And I think we were successful in doing that, so very, very pleased with the position on those rig upgrades.
Between that and giving money back to shareholders, you're doing all the right things. If I could transition to pressure pumping for my follow-up, we all know that the Marcellus has been a little bit weak. You guys have been talking about moving a couple of spreads out of the SCOOP/STACK. Can you just hit a couple of geographies and tell me which is best, which is worse, which is going to weather this Permian takeaway storm best outside the Permian? Can you do me a little regional jump around on pressure pumping?
In pressure pumping, we've called out that we saw towards the end of the second quarter that in our view, the market is becoming oversupplied. And that's actually in multiple regions, including the Permian. We believe that a large number of companies have pushed equipment into the market in the Permian, and we're just seeing that even as well a bit oversupplied at this point.
Okay. So, it's not just the Permian that's oversupplied and it's not just the Marcellus. It's kind of endemic, okay. Okay, gentlemen, thank you very much.
Your next question comes from the line of Marshall Adkins with Raymond James. Please go ahead.
Good morning, guys. Would you help reconcile the – you seem very upbeat on the rig side. Things are looking up there. You're putting more rigs to work. And at the same time, we're seeing a deterioration in pressure pumping. Last I checked, you had pressure pumping business or frac crews follow the rigs by three to six months. So, I think I know the answer to this, but just give us more color on the difference between a bullish rig outlook and a fairly pessimistic pressure pumping outlook.
Well, the super-spec rig market is very tight. The number of rigs that are available for upgrade is relatively small relative to the total number of rigs that are out there, and then you got the capital requirements along with that, and so that market's staying very tight.
Pressure pumping, we're seeing signs of oversupply at the end of the second quarter and going into the third quarter for various reasons, including, as Mark pointed out, we have some E&Ps that are running ahead of their schedule on their budget. So, we could see a reset in the budget for some of these E&Ps at the beginning of 2019 as well.
So, you've got this one side where the super-spec rig count continues to go up, and with the efficiencies of the super-spec rigs, you're driving a high number of wells being drilled and put into the market, and then you have this potential budget reset early in 2019 for some customers that may be ahead of their spending or ahead of their efficiencies on completions right now. And so I think we just have to work through this through the rest of 2018.
Okay. Shifting gears over to the directional drilling side, I know you kind have been targeting getting back up to eventually 30% margins and we've been tracking a little bit below that here recently. What's the trajectory going forward? And are you still thinking getting back to that 30% margin level and when?
Well, we've certainly been trying to get it back to the 30% level when we first talked about the business. We've had this overhang from having the rental equipment based on various third-party suppliers that we've been waiting on products for. Some of that is – we've start to get relief on. You can see the margins improving a little bit in the third quarter. And we see that we should be past a good course of this third party rental later in this year. I think that's the best color I can give you at this point right now.
Okay. Thank you, all.
Your next question comes from the line of Tommy Moll with Stephens. Please go ahead.
Good morning. Thanks for taking my question.
Good morning.
So for the four upgrades that you mentioned at about $15 million each on a four-year term, as you get deeper into the fleet with respect to what's eligible for upgrade, is that the new framework you think we ought to keep in mind going forward? And can you give us a little context on which class of rigs you're pulling from to upgrade here, and what some of the component parts are to get to that $15 million? And then, about how many more do you think you've got eligible?
Yeah. And we have a mix of rigs that can be upgraded. Some of our rigs only need maybe $2 million to $3 million or maybe $5 million, but those rigs are actually working right now for customers that don't need the upgrade. So they're still what we would consider some rigs out there that are high spec that don't need what we are calling a major upgrade of $15 million.
What we're doing in that major upgrade of $15 million is we're taking a rig that was built 2006 to 2008 at 1,000 horsepower draw-works rating for the Marcellus and the Barnett. And these rigs just aren't as interesting anymore for customers drilling the deeper wells and the longer laterals in the various basins. The customers, the operators want 1,500 horsepower at a minimum. They want a larger rack back capacity on the substructure. So when we're doing these major upgrades, we're actually changing the substructure, the derrick, draw-works, some of the electricals that power all this.
And so, that's why we consider it a major upgrade. The entire center section of the rig gets changed out. And as we work into the fleet and we work into some of the rigs that we're doing some major upgrades on, then the refurbs on some of the backyard component start to cost us more, and that's why you're seeing the increased costs as well, along with the fact that we have less components that just are inventory left over from the downturn, and so we're buying a few more new components as well.
Got it. Thank you. And then just as a follow-up. With your relatively optimistic outlook on the drilling side versus the more muted outlook on the pressure pumping side, is it fair to take away that what you're hearing from customers is they maybe building some ducts here over the next quarter or two, or is there some other dynamic?
I think it's hard for us to know. I think there's just some oversupply in the pressure pumping market. But as we said, the super-spec rig market remains very tight. And that's a very interesting business, and that generates approximately two-thirds of our EBITDA, especially in the second quarter.
Great. Thanks. That's all for me.
Your next question comes from the line of George O'Leary with TPH & Company. Please go ahead.
Good morning, guys.
Good morning.
Good morning.
Got the color on the four contracts for four years, and the discussion so far is really interesting, but you guys put together an impressive overall incremental set of contracts between the last time we spoke to you on a conference call. I guess just generally on average for those incremental contracts signed quarter-on-quarter, could you talk a little bit about the delta in average term versus what you saw in the last quarter, how much is that increasing? And maybe, obviously, not providing the exact rate, but any color on how much rates migrated up for contracts signed quarter-on-quarter would be helpful.
Yeah. I don't want to give any of the details from the values of the contracts. But as we stated, our average revenue per day is going to move up in the third quarter. We're seeing dayrates that were signed on these contracts moving up. And as I mentioned, the upward move on these dayrates and what we're generating in terms of revenue per day is just being masked by some older contracts signed back in 2014 at a very high dayrate that are rolling off. But dayrates in the forward contracts are still moving up.
And any color on term duration?
Well, so I need the four years. And so, that's certainly out there in terms of term. We'll just have to wait and see what others look like.
Okay. That's helpful. And then, I guess if you could parse out what you believe the drivers of the oversupply are on the pressure pumping side. Obviously, you talked a little bit about budget exhaustion and the potential for folks to slow their well programs. But if you had to break it down between the demand side of the equation versus the supply side of the equation, and then how much of that demand erosion you believe is maybe driven by this Permian constraint issue versus just that budget exhaustion, any more color on what's driving the oversupply would be super helpful in addition to how you've framed it so far.
Yeah, I'll try to describe it as best I can from the way we see it. And so, we're seeing some oversupply. It really came to life towards the end of the second quarter. And our belief that it's really basically the number of spreads that have been pushed into the market in the second quarter relative to the demand.
I don't believe that we've seen any shift in the demand. I'm not saying that demand side won't change, but I'm saying that we haven't seen any change in the demand side, and especially in the Permian. But we are seeing in the Permian, for example, a number of spreads that just are not filling their schedules.
So you've got a number of spreads that are out there across the industry that have idle time. And so we see this in terms of oversupply. It made it difficult for us to fill white space in our calendar into the second quarter when we had delays from third parties. Normally, we'd be able to shift some spreads, go do some fracs for some other companies, but there was just oversupply in the market that didn't allow us to do that.
All right. That's very helpful. Thanks for the color, guys.
Your next question comes from the line of Ken Sill with SunTrust Robinson. Please go ahead.
Yeah, good morning. I want to ask one more question about that pressure pumping because you can never ask too many. Is the issue with the revenue more utilization or has pricing actually started eroding, too?
I wouldn't say pricing has started eroding, but it's really more about utilization for us and white space in the calendar. We'd had white space at the end of the second quarter, and that's carrying forward into the third quarter as well. It also poses some upside on the projections that we gave you on pressure pumping if we're able to fill some of this white space, but we're doing our best to give you the projections the way we see it today.
And that was down 4%, right, sequentially?
Direct pressure pumping revenue down 5% and gross margin down 7.5%, gross profit down 7.5%.
Yeah so, there hasn't really been much pricing, it's we're just not just getting work for the spreads. Could you talk a little bit, has there been any difference in behavior by customers in the spot market versus guys that have dedicated fleets?
I wouldn't say there's any difference in behavior. I think that just given the number of spreads that are available on the market today, you just have a large number of pressure pumping companies all going after the work that happens to come up.
That's never good. I'd like to change directions. Just one quick question. How are you guys set for drill pipe inventory? And are you guys seeing as we do more of these laterals, as these rates get better, what's going on with the pace of requirements for replacing drill pipe?
We do have drill pipe in our maintenance capital budget for our drilling company also in what I would call the growth capital budget because when we do the major upgrades, we're going to buy some pipe as well. But in general, we're only buying specialty pipe where we need to. And when we buy the specialty pipe, we are able to rent that to the customers at a separate rate.
All right. Thank you.
Your next question comes from the line of Scott Gruber with Citigroup. Please go ahead.
Yes. Good morning.
Good morning.
Hey, Scott.
Andy, what's the remaining useful life on the upgrades after the upgrade is complete?
The easy upgrades have a full and useful life of the new rig. I mean, when we spend $15 million on these next four, you've got a rig that has a 20-year life at that point. And so, very excited about position of that asset. It's taking an asset that, as I mentioned, built for the Barnett or the Marcellus. We want a lighter load capacity. It's basically stranded in the market right now. And then it brings it up to a full super-spec, and essentially, it will work like a new rig.
Got it. And broadly speaking, I'm not asking for the specific rates on the latest contracts but from a high level can you just comment on the shape of the rig curve given that we have six months in the mix and now three-, four-year in the mix, so the three- to four-year contracts being signed around at the six months level? Are they above, below?
Day rates in general are up into the right. Day rates are moving up as the super-spec rig count moves up, and you're seeing the higher day rates in the forward contract. And that bodes well for that business going forward.
Got you, got you. Thanks for the color.
Thanks.
Your next question comes from the line of Marc Bianchi with Cowen. Please go ahead.
Thank you. If I could just ask on the pressure pumping guidance to be down 5%. Can you talk to what that would look like from the current run rate or maybe the June level? Just curious if there's additional deterioration assumed in there or if it's steady, or any other color you have.
It's a function of the white space that we ended up with in our calendars at the end of the quarter, call it June, that carries over into the third quarter, and then we see some opportunities to work through that towards the end of the quarter. That's probably the best color I can give you on that. As I mentioned, it still offers some upside in our results for pressure pumping in the third quarter if we're able to fill some more of that white space.
Okay. Thanks, Andy. And on these $15 million upgrades, how much would an equivalent newbuild cost?
An equivalent newbuild, and this is specific to us at Patterson-UTI, and – we have a specific style of rig that we like, it's the APEX-XK and the APEX-PK, and our newest rig that's working in the industry, the APEX-XC. These rigs are built to last 20 years. And very pleased with the assets, pleased with the way these trade in the market.
And so, we invest a little bit extra in these rigs because these are rigs that we're going to own for a long time. So we tend to spend in the range for a newbuild, if we had to take a guess looking forward, in the $25 million range, plus or minus. That's about where that would be. You can build a rig for less, but it's not a rig we want to own for 20 years.
And that also includes all of the collateral aspects of the rig as well.
That includes BOPs, drill pipe, your first mobilization to location. When we capitalize that, we put everything in.
So, some people give you a number that's lower, but they don't also include all those aspects.
And the other thing that's changed from 2014 and when we were last building rigs in 2014 and 2015, is just the amount of equipment and the level of equipment, the demand is higher now, the specification for load rates. The efficiencies that these rigs produce is even higher than what we were doing before.
Yeah. And just one last one. On those candidates for the $15 million upgrade, can you say how many more you have? And I guess it seems like all of those would be idle rigs at this point. None of them are working. Is that a fair assumption?
Yeah. That's a fair assumption. I mean, it's not hard for you to go through our list and just look and see. You're basically taking high spec to super-spec from currently idle rigs built at the 1,000 horsepower capacity.
Okay. We'll go through it. Thanks a lot. I'll turn it back.
And we have no further questions in the telephone queue at this time. I will now turn the call back over to the presenters.
I'd like to thank everybody for joining us on our second quarter conference call. Look forward to speaking with you when we report numbers for the third quarter. Thanks, everybody.
Thank you to everyone for attending today. This will conclude today's call and you may now disconnect.