Patterson-UTI Energy Inc (PTEN) 2017 Q4 法說會逐字稿

Good morning. My name is Krista, and I will be your conference operator today. At this time, I would like to welcome everyone to the Q4 2017 Patterson-UTI Energy Earnings Call. (Operator Instructions) Mike Drickamer, Vice President of Investor Relations, you may begin.

Thank you, Krista. Good morning, and on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss results of the 3 and 12 months ended December 31, 2017. 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 on 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 hand the call over to Mark Siegel for some opening remarks. Mark?

Thanks, Mike. Good morning, and welcome to Patterson-UTI's conference call for fourth quarter 2017. We are pleased you are able to join us today.

Before reviewing the financial results for the fourth quarter, I would like to take some time to discuss the tragic accident that recently occurred in Oklahoma. All of us at Patterson-UTI are heartbroken and deeply saddened that 5 individuals, including 3 of our employees, lost their lives. Our thoughts and prayers continue to go out to all those affected and their loved ones. We are thankful for the numerous condolences and messages of support we have received from many of you, and all of us very much appreciate your concern.

I would also like to once again thank the first responders, emergency personnel, authorities and others for their tremendous courage and efforts. I would especially like to thank the numerous people from the local community in and around Quinton that dropped everything to offer support to those affected by the accident. There is nothing more important to us at Patterson-UTI than the safety of our employees and those we partner with in the field.

Turning now to our financial results for the fourth quarter. As set forth in our earnings press release issued this morning, we reported net income of $195 million or $0.88 per share on revenues of $787 million. These results include net after-tax items that positively affected fourth quarter earnings by $218 million or $0.98 per share. Excluding these items, the per-share loss for the fourth quarter would have been $0.10. These items include a $219 million or $0.99 per share benefit related to the noncash revaluation of deferred tax items on our balance sheet arising from lower corporate tax rates as part of the recent tax legislation. Additionally, there were $8.7 million of pretax merger and integration expenses, and an $8.4 million pretax gain related to the sale of certain oil and gas interests. These last 2 items were each approximately $0.03 per share after tax and marginally offset each other.

We ended 2017 with approximately $43 million of cash on the balance sheet and $868 million of debt, which included $268 million drawn on our revolving line of credit.

In January, we issued $525 million of 10-year, 3.95% investment-grade senior notes. A portion of the proceeds were used to repay the outstanding borrowings on our line of credit, and the remainder increased our cash balance.

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

Thanks, Mark. First, I'd like to say that our hearts go out to the families and colleagues that were impacted by the accident in Oklahoma. Our primary efforts have been focused around providing support for the families.

Turning now to our business in the fourth quarter. In contract drilling, despite widespread concerns of an industry-wide drop in the rig count during the fourth quarter, our rig count proved resilient and rebounded during the quarter. Even with the typical holiday-related slowdown in Canada, our rig count ended the year near the highest level of 2017.

Our average rig count for the fourth quarter was 161 rigs, and we have seen some strength in the rig count in early 2018 such that our rig count averaged 165 in January. Average rig margin per day for the fourth quarter increased $280 sequentially to $8,010, as a $630 increase in average rig revenue per day offset a $350 increase in average rig operating cost per day. Average rig revenue per day of $20,950 was better than expected as the market for super-spec rigs remains tight. Average rig operating cost per day of $12,940 increased as expected from an unusually low level in the third quarter.

At December 31, we had term contracts for drilling rigs providing for approximately $540 million of future day rate drilling revenue, an increase of approximately $70 million from $470 million at September 30. This increase in our backlog was a function of both an increase in the number of rigs under term contracts as well as higher average term dayrates. Based on contracts currently in place, we expect an average of 96 rigs operating under term contracts during the first quarter and an average of 67 rigs operating under term contracts during 2018.

Turning now to our outlook. As mentioned, we are seeing further strength in our rig count, and the market for super-spec rigs remains tight. We estimate there are approximately 550 super-spec rigs in the industry in the U.S., with utilization likely exceeding 95%.

Within our own fleet, we have 130 super-spec rigs, of which 98% have contracts.

We completed the 7 previously announced rig upgrades to APEX-XK, all of which are currently working. The APEX-XK continues to be one of the most modern land rig designs in the industry and the rig of choice for many of our customers. Additionally, we have also seen customer interest in incremental APEX PK rigs. As such, we have customer contracts to support upgrades on 5 additional rigs, 2 of which will become APEX-XK rigs and 3 will become APEX PK rigs. All these rigs are expected to be delivered in the first half of 2018. Given these upgrades as well as the reactivation of additional rigs, we expect our rig count for the first quarter will average 169 rigs.

With an increasing proportion of super-spec rigs as well as the favorable repricing of short-term contracts, average rig revenue per day is expected to increase sequentially by approximately $300 in the first quarter. Average rig operating cost per day is expected to be higher in the first quarter, due in large part to the typical first quarter increase in payroll taxes.

For the first quarter, we expect average rig margin per day of approximately $7,700.

Turning now to pressure pumping. During the fourth quarter, pressure pumping revenues increased 12% sequentially to $407 million. Gross margin was $83 million or 20.4% of pressure pumping revenues, an increase from 19.9% in the third quarter. While revenue growth for the fourth quarter exceeded our expectations, gross margin did not improve as much as expected and still has room to improve. In order for us to fully benefit from the expected strength in our pressure pumping, we have several initiatives under way.

First, we are working to optimize our average spread size in order to gain an extra active spread from already active equipment. We ended 2017 with 1.25 million horsepower active, comprising 23 spreads. Early in the second quarter, we expect to go to 24 active spreads with the same 1.25 million horsepower.

Second, we plan to reposition 2 active spreads out of the Mid-Continent region to more profitable markets.

Finally, assuming demand remains as strong as expected, we plan to reactivate additional spreads from our currently idle equipment later in the year.

Turning now to our outlook for the first quarter. Pressure pumping revenues are expected to be down slightly, to approximately $400 million. This decrease is due in part to the weather, as we estimate weather-related downtime in January alone negatively impacted first quarter revenues by approximately $9 million. Despite this revenue decrease, pressure pumping gross margin is expected to increase by approximately $5 million in the first quarter.

Turning now to directional drilling. We completed the acquisition of MS Directional on October 11, and as such, fourth quarter results included 81 days of post-acquisition contribution from MS. For the fourth quarter, directional drilling contributed $45.6 million of revenues with a gross margin of 29.4%. For the first quarter, we expect directional drilling will contribute approximately $47 million of revenues with a gross margin of 28%.

Before I turn the call back to Mark for his concluding remarks, let me provide an update on several other financial matters. Our other operations include Great Plains Oilfield Rental, Warrior Rig Technologies and our E&P business. For the first quarter, we expect other operations to generate revenues of approximately $21 million with a gross margin of 17%.

For all of Patterson-UTI, depreciation expense for the first quarter is expected to be approximately $205 million.

SG&A for the first quarter is expected to be $32 million, excluding expenses related to the accident in Oklahoma.

We are still assessing the financial impact of the accident in Oklahoma, but we want to share the following based on what we know at this time. We maintain insurance coverage of types and amounts that we believe to be customary in the industry, including, but not limited to, workers' compensation, employer's liability, general liability and equipment coverage. While we carry pollution insurance coverage, we are not aware at this time of any meaningful environmental impact from the accident.

Based on the information we have available at this time, we believe that we have adequate insurance to cover any losses, excluding the applicable insurance deductibles and expenses related to the investigation. This expectation is preliminary and subject to information that may become available after today.

Moving on to taxes. For the fourth quarter, our effective tax rate, exclusive of the benefit from the revaluation of our deferred tax items, was 25.8%. Please remember that as our pretax earnings approach breakeven, relatively small items have the potential to have an outsized impact on our effective tax rate.

Based on our current understanding and recent interpretations of the new tax law, we are currently projecting our effective tax rate to be approximately 28% for 2018.

During the fourth quarter, we spent approximately $237 million on CapEx, bringing our full year 2017 CapEx spend to $567 million. With the increasing rig count and activity levels we expect for both drilling and pressure pumping in 2018, our CapEx budget for 2018 is approximately $675 million, comprised of $330 million for drilling, $260 million for pressure pumping, $40 million for directional drilling and $45 million for other operations and general corporate CapEx.

We expect to generate strong free cash flow in 2018.

The $330 million of CapEx spend for drilling includes approximately $130 million for maintenance, with the remainder budgeted for growth opportunities including rig upgrades and reactivations. We are not budgeting for any newbuilds in 2018, but this budget allows for 12 major rig upgrades for delivery in 2018, of which 3 were previously announced. Of these 12 rigs, 1 has already been delivered and another 5 are already contracted and scheduled for delivery in the first half of 2018. The remaining 6 provides optionality to deploy additional super-spec rigs into what we believe will be a strong rig market during the second half of this year.

In addition to these major upgrades, we have budgeted for additional upgrades, including 7,500-psi high pressure circulating systems, walking systems, larger diameter drill pipe as well as additional mud pumps and generators as we meet the growing demand for super-spec rigs.

The $260 million for pressure pumping is budgeted primarily for maintenance and spread reactivations. At this point, we do not have plans to add incremental horsepower to our feet.

The $40 million for directional drilling is primarily growth CapEx as we expand our fleet of drilling motors and MWD equipment to keep pace with the growing market for directional drilling.

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

Thanks, Andy. 2017 was a transformational year for Patterson-UTI. We both strengthened and diversified our company through the strategic acquisitions of Seventy Seven Energy and MS Directional. These acquisitions improved our scale in drilling and pressure pumping while also adding new services in directional drilling and oilfield rentals.

We also reached another significant milestone in terms of being recognized with an investment-grade credit rating, one of only a limited number of oilfield service companies with an investment-grade credit rating.

Through the downturn, the U.S. unconventional market has proven its resilience and is starting to demonstrate its dominance on the global stage. This position has been made possible by advancements in horizontal drilling and hydraulic fracturing, taking geologies that more than a decade ago were considered almost worthless and transforming them into some of the most prolific in the world. Within this framework, it is important to note that Patterson-UTI is the only company in the U.S. -- in U.S. unconventional market with significant scale in drilling, pressure pumping and directional drilling.

Also, I am pleased today -- to announce today the company declared a quarterly cash dividend on its common stock of $0.02 per share to be paid on March 22, 2018, to holders of record as of March 8, 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.

Before closing, and in conclusion, on behalf of Patterson-UTI, I would again like to express our thoughts and prayers are with all those affected by the Oklahoma tragedy.

With that, operator, we'll turn the call over to you for questions.

(Operator Instructions) Your first question comes from the line of John Daniel from Simmons & Company.

Just a couple ones for me, Andy, and I'll start on the frac segment. Can you speak to just kind of the timing and the magnitude of the potential fleet reactivations?

John, so what we said so far is with 1.25 million horsepower that we currently have active today, early in the second quarter, we'll go from 23 spreads to 24 spreads with that same 1.25 million horsepower. Given the market strength, we anticipate that we'll be acting further spreads in the year, but we haven't called out a timeline necessarily on when that would occur.

Can you maybe quantify what the number of potential spreads could be from the stacked fleet?

I think some of that is going to depend on our comfort level with the strength of the market as well. And we'll have to wait and see how that moves through 2018.

Okay. Last one for me and I'll turn it over, because I don't want to be a hog here. We've had several E&P companies sort of share that inbound calls from frac sales people are rising, which gives them the impression that we're starting to see slack in the system. Some, but it's a few, have reported some pricing benefits following comprehensive RFP processes. Can you just speak to your strategy right now as when you are participating in competitive tenders? And whether you've had to sharpen the pencil at all, so to speak, in order to win work? And just sort of frame for us what you're seeing real time from a pricing perspective.

Yes. First, what I'd like to frame up is that in 2018, we do expect that pricing can continue to move up, just like it was doing in 2017. But what you saw in 2017, or at least what we saw, is that pricing in pressure pumping moved up in Q2 and Q3, and that was along with the rig count increases that you saw as well. But the rig count increases leveled off in Q4 as some of the E&Ps took a pause during Q4. And when that happened, this released, in our view, some spreads that worked on the spot market. And then pricing took a pause in terms of moving up in pressure pumping in the fourth quarter as well. We see this as a short-term effect. So I'm sure that there are some E&Ps that felt like they were running a competitive RFP process in the fourth quarter and probably early in the first quarter. But overall, we expect the rig count in high-spec and super-spec rigs to continue to move up in 2018. We expect this will continue to drive demand in pressure pumping. And based on our outlook, in 2018, even with some of the more bearish cases for pressure pumping with higher numbers of new horsepower coming in, we still see that this horsepower is likely consumed by demand due to the increasing rig activities.

Your next question comes from the line of James West with Evercore ISI.

This is Alex on for James. My first question relates to pressure pumping CapEx. And it looks like even if you average it for active horsepower or active spreads, that the increase is pretty significant. I'm curious, I guess, what's driving that, if you guys are seeing higher consumable costs or anything for the equipment that's stacked at the end of the yard.

It's really just based on our anticipation of what we see in terms of maintenance. The majority of that $260 million that we are projecting for CapEx for pressure pumping is really around maintenance. There's some reactivations in there as well, but most of it is maintenance. And it's just the increase in activity in '18 versus what we saw on average in '17.

Okay. So just like the timing of major maintenance upgrades and whatnot?

No particular timing of any major maintenance. This is just an increase in maintenance CapEx based on activity levels increasing year-on-year.

Okay. And then second on revenue within pressure pumping. Even with the impact of weather, it seems kind of light given that your spread count's higher and your expectations for pricing. Is that, I guess, a commentary on 1Q pricing and then we should expect some increases as we progress? I guess what's driving that flatness relative to your commentary on pricing?

Well, the primary driver are the weather delays that we saw in January. We called out that this is $9 million in revenue. The majority of this is actually in West Texas, where we had a lot of freezing temperatures early in the month. But back to the pricing discussion; as I mentioned, we saw the pricing movement upwards in 2017 take a bit of a pause in the fourth quarter. That carried over a little bit into the first quarter. But I expect that pricing for '18 in pressure pumping continues to move up.

Your next question comes from the line of Scott Gruber from Citigroup.

Look, I realize that returning incremental cash to shareholders is not appropriate around a tragic accident, and you guys have -- you just went out and raised some debt as well. But Mark and Andy, can you just discuss the parameters that you are monitoring to think about enhancing the cash return program? And you did achieve the IG rating. What else are you monitoring to think about enhancing that cash return program?

Scott, it's a great question, and we do think about it regularly. Most recently, we have been thinking about it in terms of this year being a year in which we are going to -- we expect to generate substantial free cash flow. And I think as the year progresses, we are going to continue to reevaluate that. As you know, we've spent a considerable amount of capital over the last several years retooling our drilling fleet and increasing our pressure pumping fleet, and entering into new businesses. And so there's a sort of a sense on the part, I think, of the board and management to, in effect, wait a little while, while we consider what's actually -- how the year unfolds before we make any changes and commitments in terms of share buybacks or dividend increases.

And can you just discuss your thoughts around enhancing the base dividend versus a variable return program via buyback or a special? And how do you weigh one versus the other?

Yes, Scott, I've spent a lot, a lot of time studying dividend history, both of our company and of other companies and actually looking at academic research on the topic. And having spent that time, I've yet to see anything persuasive about a particular direction for that. My own personal view, not necessarily anything else, is that a consistent dividend is what investors are most comfortable with, that the consistency of the payout is what matters to investors. And that's the thing that I think is most useful in thinking about companies and their dividends. So if you have a dividend -- we've had a $0.02 per share dividend, but we've had it for quite a long while, I think investors have felt comfortable counting on it. By the same token, if we were to change it, I'd want them to have the same confidence in it that it would not be something they would have to worry about going away. So I'm much more in the school of consistent payouts that are predictable and more or less certain, if that makes any sense, and less persuaded by the research about variable dividends and variable payouts. Hope that helps.

No, it does, I would agree with that thought. If I could slip one more in quickly, Andy, what are you seeing today in terms of pricing in directional?

You know what, our expectation is for 2018 is that pricing in directional drilling continues to move up, because we see that rig count is continuing to move up and you're seeing that in our CapEx budget. So as industry rig count moves up, I think directional drilling pricing continues to move up. Our margin in directional drilling is forecasted to drop just a little bit. What that is, it's related to our availability of spare parts and having to rent some equipment from third parties in the first quarter. But we expect this to be transitionary. And based on discussions with suppliers, we expect to be caught up with that sometime in the second quarter and back to more normalized margins in directional drilling.

Your next question comes from the line of Ken Sill from SunTrust Robinson Humphrey.

You just answered one of my questions, on directional drilling. A couple of quick ones here on the additions. So out of the 5 rigs that you guys are going to upgrade to super-spec and the 6 more that you could potentially do that are in the budget, are any of those rigs working? Or they are all idle rigs that you're going to upgrade and then add to the fleet?

So in the current upgrade plan, the rigs that we are going to be upgrading are rigs that were -- that are typically 1,000 horsepower, built for the markets such as the Barnett or the Marcellus originally. And we'll be looking to upgrade those to 1,500-horsepower super-spec rigs. The majority of these rigs are available to us to do that, because being 1,000 horsepower, the majority are not working. But -- and I expect that the majority will be idle at some point. So we do have some 1,000-horsepower rigs working. And we'll work that into the schedule as to which ones we actually upgrade.

Okay, that's great. And then getting back to the pressure pumping capacity issue. We don't have a plan yet for how they're going to be or how much is in your cost. But how many more fleets, given your restructured fleet size, do you think you could reactivate out of your existing horsepower on top of the one that you're doing from the -- so you've got 1.25 million active, you're going to 24, how many more fleets could you get out of your available stacked capacity?

Well, out of the additional 250,000 horsepower that we have that's still stacked, we should get around 5 frac spreads out of that.

So 50,000-horsepower spread is kind of where things are?

Roughly.

And then a final question, and I'll turn it over. Revenue is down because of weather, pricing a little bit softer or flattish, I guess, would be fair in Q4. How far out are you guys committed on pricing? And then, how far out beyond that are you kind of committed in terms of schedule on your pressure pumping, please?

So without getting into the details, we have a basket of contracts. Some are longer term with pricing agreements that may be up to 6 months to a year. Some are shorter term. And we have some spreads that work just directly on the spot market and move between different customers during the month and during the quarter. We feel we have the right balance, because when we are activating spreads, we're investing $6 million for a reactivation for a stacked spread, and so we want to know that -- that these assets have a fair way to work under for that investment. But we do feel like we have the right mix there. And we do feel that some of our spreads certainly have the ability to price upwards as the market pricing continues to move upwards.

Yes, but I guess, without getting too much into details, I would think that most of your work for the next 60 to 90 days is -- or at least the next 45 to 60 days is priced. So any kind of price improvement, or if you're going to be bearish, price decline would probably not show up in your numbers until Q2. Is that fair to say?

Well, certainly in the projection in Q1, we are not baking in any significant price increase there. And then we'll give you Q2 at the next call.

Your next question comes from the line of Blake Hancock from Howard Weil.

Andy, first, if you could, could you quantify the magnitude of the payroll impact in 1Q for the drilling margin?

This is Andy Smith. On the cost increases in 1Q, it's probably about $250 an hour -- I'm sorry, a day.

Okay, that's helpful. And then, Andy, from an operation and the pressure pumping perspective, right, the revenue's down, but the margin is up. Can you maybe talk about, are you seeing, I guess, I would have expected that to potentially be down with some reactivations and some movements of the fleet. Can you maybe talk about how you're absorbing some of those costs? And what those may be? And then how those could expand into 2Q and 3Q as they abate?

I think what you're seeing in our Q1 projections are really our operations doing a better job with their efficiency and their cost control, even though we've had weather delays that impacted revenue by $9 million, where we are carrying cost for labor at the same time. But I think our operations teams continue to improve in their ability to manage their costs and deliver margins. I think in terms of reactivations, we are not carrying a lot of cost for that in the first quarter, because the spread that we intend to add is coming out of existing active hardware.

Your next question comes from the line of James Wicklund from Crédit Suisse.

On the rigs that you're reactivating, you note in the press release that you have contracts for 5, and I'm going to assume that the dayrates for those are mid -- low to mid-20s, which has been the commentary, feel free to correct me if that's wrong. I'm more interested in the duration of these contracts. Are these closer to 1 year or 3 year? And I don't want to give anything competitive away, but can you talk about what kind of duration we are seeing in the contracts that both you and your E&P customers are willing to commit to at this point?

Jim, first off, I don't feel the need to correct you on your assumptions regarding pricing. It's what we would like to see to spend $8 million to $10 million to reactivate a rig and do the upgrade to the level that we are discussing to get to an APEX-XK or APEX PK super-spec rig. In terms of duration, for these rig upgrades, I would say our average has been about 1 year, and I think that is mutual between ourselves and the E&Ps. That gets us moving in the market in the direction we are happy with. But we anticipate that this market continues to improve and that there's still pricing upside for super-spec rigs in 2018.

Perfect. And if I could move to pressure pumping and kind of ask the same question, a lot of the spreads that are working today are more dedicated than contracted. You guys didn't want to sign a contract when pricing was going up and the market was short. E&P companies don't want to sign contracts up until a couple of months ago because oil could go to Goldman Sachs' $20 any moment now. When do we start contracting frac spreads rather than just calling them dedicated? Is that going to happen this year?

I'm not sure I see that changing this year. I think our marketing teams do a good job getting contract structure with a pricing agreement that gives us good visibility on how much work we are going to do. I don't believe we've had any real trouble there. I don't see that market or any of the service side of the business moving towards how we contract with the drilling rigs. But I think our teams are doing a good job working with the E&Ps to understand what that work program looks like.

Would you build a new spread? I know -- and I know you don't have that in your budget, so this is hypothetical, would you build a new spread without a, say, 2-year contract? Or how much of a contract -- we won't even discuss price, but how much of a term do you think it would take for you or industry to go build a brand-new 50,000-horsepower spread?

I think in our case, and remember we still have 250,000 horsepower that we have stacked that -- we'll start to reactivate some of that in 2018. But I don't think we would get to buying equipment until we had discussions with customers that at least gave us a year on a program and returns that we were comfortable with buying new hardware. And I think we are monitoring in terms of how we reactivate it and the pricing levels that we wanted for those reactivations. And we've just worked through a very huge integration, at least for us, combining 1.5 million horsepower of assets into one company with operations in multiple states. So now we're working to just make that operation even more efficient than it has been. That's our focus right now. And we are going to push for the best pricing we can get, and for the best terms we can get. But back to any potential newbuilds that would come after activating 250,000 horsepower, again, I'd want to know that we have at least a year of a work program at a pricing that gives us an acceptable margin. And we're just -- not quite there for us yet.

And if I could sneak one in, why do we refer to it as revenue per day instead of dayrate like we used to?

In terms of drilling?

Yes, and -- I'm sorry, in terms of drilling. Is it because the contracts are structured different because of add-ons? Because I noticed that you and everybody else now refers to it as revenue per day instead of dayrate, and I didn't know if that meant there was a base dayrate and then you charge extra for things that you add to the rig, and that's why we refer to it as revenue per day. I just -- if you could just, quick and dirty, on why the change has occurred in the semantics.

This is Mark, I'll jump in for a second and just say that actually we've been doing this for a very, very long time, and it was reflective of the fact that you had to also factor in what you got paid for moving, what you got paid for all kinds of things when you ultimately decided, you took your total revenue against total number of days, and that's how we got to -- that's how the industry, I think, moved there. But you're correct that there are all kinds of incremental -- we now think of rig pricing as what's the base rig, and then what the incrementals that we are going to add on to that for additional things that a particular customer may want, an additional crew member, additional piece of equipment, et cetera, et cetera.

I think we were talking more about this back in 2013 and '14, and we look at it, as Mark said, in terms of a base dayrate for the major capital asset where we want a certain return. And when we're adding things such as larger diameter drillpipe or other ancillary equipment to the rig, we are going to be looking for a shorter payback and better returns on that, so that's how we structure those.

Your next question comes from the line of Tommy Moll from Stephens.

First, I just wanted to talk about the weather impact that you saw in January. Was that isolated just to West Texas? Or were there impacts in other parts of the country as well? And can you give us any sense of how many days or weeks were impacted in West Texas?

So we said we had $9 million of revenue impact in the first quarter due to the weather. That was the first few weeks of January. The majority of that was West Texas. We did have some other basins that were impacted, but the majority was West Texas. And we haven't necessarily called out how many days or anything like that, it's really more about stages that we didn't get to pump versus days.

Okay. And then as a follow-up on rigs, it's good to hear the commentary about strong demand for more upgrades to super-spec. Once you get through the dozen or so that you've got in the budget for this year, how many more upgrade-eligible rigs do you have? And how many of those are currently active?

So technically, all of our rigs could be upgraded to super-spec rig, it really becomes an economic decision. And we'll just have to wait and see how 2018 progresses and if it makes sense for us to economically upgrade some more of these rigs. But technically, all of the rigs in our fleet could be upgraded to super-spec rig.

Your next question comes from the line of Marc Bianchi from Cowen.

My first question is on the couple of Mid-Con fleets I guess that are moving, and then this additional fleet from -- that's being created from optimization. It sounds like just one of those has a customer locked in. Did I get that right?

No, we haven't called out any particular customer information on those fleets. But it's certainly our plan that we are going to move 2 out of Mid-Continent and we'll line up customers for those. And we'll reactivate the 24th spread out of the existing active horsepower and we'll have a customer for that early in the second quarter.

Okay. And were the Mid-Con fleets working for most of the fourth quarter?

Yes, they've been working.

Okay, great. I guess over on the drilling side. You talked about the payroll cost increase in the first quarter. But looks like the implied cost per day is guided up about $600. So there's some other cost increase in there. Should we be thinking about that as continuing? Maybe there is some labor inflation. I don't know. Perhaps you have some reactivation that was going on there.

Some of it is going to be OpEx related to reactivations. I'm not -- we are not expecting a large labor increase in the first quarter. And if we do have labor increases in our contract drilling business, then that's essentially a pass-through in the contracts.

Your next question comes from the line of Kurt Hallead from RBC.

I heard a lot of positive commentary about the outlook pretty much across all your business lines. Sitting here, scratching my head trying to figure why your stock is down 6%, so a little plug for your outlook relative to the stock performance today. But the specific questions I have, Andy, when you look at the frac, your frac fleet and horsepower and spread as you kind of outlined for the remainder of the year, I was wondering if you could help us translate that into what you think the maximum number of frac jobs you can perform with your spread count and horsepower on an average basis per quarter?

I don't think I want to get into those levels of detail. But like I said, by early Q2, we'll be up to 24 spreads out of existing 1.25 million horsepower. We'll do further reactivations in 2018. And at some point, we will be able to activate another 5 spreads or close to 5 spreads out of the stacked equipment that we have in pressure pumping.

I appreciate that. The nature of my question really, you guys report frac jobs on a quarterly basis and kind of been between 173 and 180 through the second, third and fourth quarter. So I'm just wondering if you guys are kind of in that 180 range, you're going to hit your maximum number of frac jobs given your existing fleet, or there's some additional efficiencies that are going to be gained and so on, so I was just looking for some color around that.

I think we have the ability to continue to improve efficiencies. Our operations teams are doing a great job. Part of the relocation of 2 spreads is to improve the efficiency in the number of stages per month as well as pricing on those 2 spreads as well. But I think our teams will continue to improve the level of efficiency that the E&Ps will allow us to get when we're working.

Okay, great. In the frac-related and directional drilling business, very service-intensive business. Heard a number of different peer group companies talk about incremental margins for '18 versus '17 in maybe the 35% to 40% type of range. And is there any reason to think that the Patterson frac business and Patterson directional drilling business should be anything less than what some of your peer group companies have talked about on incremental margin for '18 versus '17?

I'll give it to you in terms of pricing. I don't see why our improvements in pricing in 2018 would be any less than anybody else's improvements in pricing. Our teams do a great job in the field, whether it's pressure pumping, whether it's directional drilling, especially contract drilling. And we are going to see increasing activity levels. We see that in the rig count that we are projecting for the year. And that's going to drive increased activity in pressure pumping and directional drilling, and our rental business as well.

All right. One final one, just as a follow-up on that. So what have you been experiencing in terms of overall sand use per well or per job? And have you contracted any in-basin Permian sand as of yet?

So in terms of volumes of sand per job or per pad or per well, we are not seeing any big change quarter-on-quarter. We just started using some of the regional sands in West Texas in the first quarter. And we'll probably see that start to increase. Regional sands have to be accepted by the customer, and we have to line up delivery from the mine. And I think as customers start to sign off technically that it's acceptable to pump that, we'll start to see some more use of the regional sand.

Your next question comes from the line of Waqar Syed from Goldman Sachs.

Andy, has any E&P so far said no to regional sands?

I'm not aware that any of the E&Ps have said no. They're going through a qualification process looking at lab results from testing to determine if it's applicable for those -- for their wells. But I'm not aware of any that have said no yet. It's just a process for approval.

And where you've pumped the regional sand, has it been mostly all 100 mesh or has it also been 40/70?

It just started in the first quarter and I don't have that information.

Okay. On directional drilling, when I look at the CapEx number, $40 million, that seems fairly high relative to this current size of the business. Is that all growth CapEx right now? And could you give us some kind of guidance on, over the next 12 months, where you see that business going with this kind of an investment?

So MS Directional is a very good company with great operations. They have a challenge right now with some of their suppliers, and their margin's been impacted by an increased use of rental equipment. The $40 million of capital, roughly 2/3 of that is planned for growth. We think they have great technology with their motor technology and also with their electromagnetic MWD systems. And so we believe that they have the opportunity to grow at a faster rate than the rig count, funded with the capital. So 2/3 of that $40 million is roughly earmarked for growth capital.

Okay. And then just -- also on just uses of cash, working capital, what's your projections for that? Or could you provide any guidance whether it would be a source of cash this year? And if so, how much?

As we continue to grow, we'll probably -- it will be neutral to us, working capital. I wouldn't see it as a big source of cash. At the end of the quarter, I think we were 6% sort of on a run rate revenue number, and that's probably about an accurate number going forward. It might bounce around that number, but be close.

And then just one final question on CapEx. Could you give us maybe some guidance on quarterly projection or how much of the CapEx may be spent in the first half versus the second half?

I just don't have that information with me today.

Would it be still more front-end loaded or more kind of increased pace throughout the year?

It's really going to depend on if we sign up some of these contracts for potential rig upgrades in the second half of the year. Right now, it's certainly more front-end loaded based on contracts because we are not going to deliver a $10 million upgraded rig without some kind of agreement for -- around the year.

Your next question comes from the line of Chase Mulvehill from Wolfe Research.

I guess a lot of questions have been answered already. But a few kind of I guess, maybe follow-ups. And we think about the potential for rig upgrades, you talked about, I think it was 12 this year. Did that 12 excludes the 7 that you announced from last year. Correct?

So we're saying that the 2018 budget allows for 12 major rig upgrades, and we previously announced 3 of those. Now there's other upgrades in the budget as well, smaller upgrades of $1 million for high-pressure piping, there's $2 million for some walking systems in there as well. But it's 12 major upgrades.

Okay. All right. And then someone asked -- sorry, go ahead.

Go ahead.

And then you talked about having a significant amount of upgrades, that basically your entire fleet could be upgraded to super-spec. But obviously there is a limit to how much you'd want to spend. What is that limit you would want to spend on an upgrade before actually ordering a newbuild?

I think what's important about this market as well is that there's been relative discipline in this market. And the fact that we have the opportunity to upgrade rigs in this market as opposed to building new rigs provides continued discipline in this market. And I think, our opinion is that we would rather upgrade a rig than build a new rig up to a point where we are not happy with the economics. But technically all the rigs can be upgraded. But we are also pleased with the relative discipline in the market at the same time.

Okay. When you upgrade a rig, how much of -- I guess, how longer life does that add to the rig?

The way that we're upgrading these rigs, and some of these rigs were built 10 years ago; when we invest $8 million to $10 million on these upgrades, it really gives them another 20 years of life. We are changing many of the major components, including the mast and the substructure.

They're virtually new rigs at the time when they're finished going through one of these major upgrades. So they have the life of a newbuild rig.

And what's the cost of a newbuild super-spec today if you were to go to the market?

When we were building high-spec rigs back in 2014 and '15, they ranged from $22 million to $24 million.

Okay. And we'll squeeze one more in real quickly. On the term dayrate, one of your competitors gave some information that kind of led to kind of a mid-20s, and I'll call it the low part of mid-20s term dayrates for some of these super-spec rigs. Is that kind of -- the most recent 5 that you got, is that a fair average dayrate for those 5?

Well, yes, earlier in the call I acknowledged that for us to be able to invest this kind of dollars in that $8 million to $10 million range, we would be looking for contracts with around 1 year of term and rates in that low to mid-20s.

Can we take the low out now?

We'll see how 2018 progresses.

Your next question comes from the line of Chris Voie from Wells Fargo.

Just filling in for Jud. Just wanted to clarify, maybe if you could quantify the impact of the mobilizations from Mid-Con in 1Q.

We are not expecting any big impact from the mobilizations in the first quarter.

We have no more questions in the queue at this time. I'll turn the call back over to the presenters for closing remarks.

Thanks, Krista. We would like to thank everybody for joining us on our Fourth Quarter 2017 Earnings Conference Call and look forward to speaking with you for our first quarter 2018 call in April. Thank you, everybody.

This does conclude today's call. Thank you for your participation, and you may now disconnect.