Good morning. My name is Kristen, 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] Thank you. Mike Drickamer, Vice President of Investor Relations, you may begin.

Thank you, Kristen. 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 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 the conference call that state the company's or management's plans, intentions, beliefs, expectations or predictions for the future are forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements are subject to risks and uncertainties as disclosed in the Company's annual report on Form 10-K and other filings with the SEC. These risks and uncertainties could cause the company's actual results to differ materially from those suggested in such forward-looking statements or what the company expects. The company undertakes no obligation to publicly update or revise any forward-looking statement. The company's SEC filings may be obtained by contacting the company or the SEC and are available through the company's website and through the SEC's EDGAR system. Statements made in this conference call include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included on our website, www.patenergy.com, and in the company's press release issued prior to this conference call. And now, it's my pleasure to turn the call over to Mark Siegel for some opening remarks. Mark?

Thanks Mike. Good morning, and welcome to Patterson-UTI's conference call for 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 five individuals, including three of our employees lost their lives. Our thoughts and prayers continue to go out to all of 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 players 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 $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 non-cash revaluation of deferred tax items 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 two items were each approximately $0.03 per share after-tax and largely 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 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 on 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 2013 such that our rig count average 165 in January. Averaged rig margin per day for the fourth quarter increased $280 sequentially to $8010 that $630 increase in average rig revenue per day offset a $350 increase in average rig operating costs 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 costs 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 day rates. Based on contracts currently in place, we expect an average of 96 rigs operating under a term contract during the first quarter and an average of 67 rigs operating under term contracts during 2018. Turning now…

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 interactional drilling and oil fields 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 geology is 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 the Patterson UTI is the only company in the U.S., a conventional market with significant scale in drilling, pressure pumping and directional drilling. Also I'm pleased today to announce today the company declared a quarterly cash dividend on 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'd 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 open for questions.

[Operator Instructions] Your first question comes from the line of John Daniel from Simmons & Company. Please go ahead. Your line is open.

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

So what we said so far is with 1.25 million horsepower that we currently have access 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'll will occur.

Can you maybe quantify what the number of potential spreads could be from the stack 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.

Last one from me, and I'll turn it over. But we've had several E&P companies share that inbound calls from frac sales people are rising which gives then the impression that we're starting to see slack in the system sum, but a few have reported some pricing benefits following comprehensive RFP processes. Can you just speak to your strategy right now when you're 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.

First, what I'd like to frame up is in 2018, we do expect that pricing can continue to move up, just like it was doing in 2017. But what you saw on 2017, at least what we saw is that pricing and pressure pumping moved up in Q2 and Q3, and that was along with the rig count increases that you saw as well. With the rig count increases leveled off in Q4 as some of the EMPs took a pause during Q4. And when that happened, this released, in our view, since spread 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 EMPs 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 higher 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 basis 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 increase in rig activities.

Your next question comes from the line of James West from Evercore ISI. Please go ahead. Your line is open.

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, active spreads, that you've increased pretty significant. And I'm curious I guess what's driving that, if you guys are seeing higher consumable cost or anything for the equipment that's stacked at the end of the [indiscernible].

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

Just like the timing of major maintenance upgrades and whatnot?

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

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

Well, the primary driver or the weather delays that we saw in January, we call that this is $9 million in revenue, the majority of this is actually in West Texas. We held a lot of freezing temperatures early in the month. But back to the pricing discussion, as I mentioned, we saw that 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 the pricing for ‘18 in pressure pumping continues to move up.

Your next question comes from the line of Scott Gruber from Citigroup. Please go ahead. Your line is open.

Look, I realize that returning incremental cash to shareholders is not appropriate around a tragic accident and you guys have a - you just raise some debt as well. But Mark can you just discussed the parameters that you're 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 the cash return program?

Scott, it's a great question and we do think about it regularly. Most recently, we've been thinking about it in terms of this year being a year in which we expect to generate substantial free cash flow. And I think as the year progresses, we're going to continue to re-evaluate 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 dividends increases.

And can you just discuss, just thoughts around enhancing the base dividend versus available return program via buyback or special and how do you weigh one up the other?

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 how we extend 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 you know if you have a dividend you know 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 wanted to have that same confidence in it that it would not be something that they would have to worry about going away. So, I'm much more in the school of consistent chaos 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 and Directional?

What our expectation is for 2018 is that Pricing and Directional Drilling continues to move up, because we see that rig count has continued 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 its 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. Please go ahead. Your line is open.

You just answered one of my questions on Directional Drilling. Couple of quick ones here on the addition. So out of the five rigs that you guys are going to upgrade to super-spec and the six more that you could potentially do there 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're going to be upgrading are rigs that are typically 1000 horsepower built for the market such as the Barnett or the Marcellus originally. And we'll be looking to upgrade those to 1500 horsepower super-spec rigs. The majority of these rigs are available to us to do that because being 1000 horsepower, the majority are not working. And I expect that the majority will be idle at some point. So we do have some 1000 horsepower rigs working, and we'll work that into the schedule as to which ones we actually upgrade.

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 restructure fleet size do you think you could reactivate out of your existing horsepower on top of the one that you're doing from the - 1.25 million active, you're going to 24, how many more fleets could you get out of your available stack capacity?

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

So 50,000 horsepower spreads is kind of where things are.

Roughly.

And then a final question and I will turn it over. Revenue is down because of weather, pricing a little softer or flattish I guess to 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 fleets?

So without getting into the details, we have a basket of contracts. Some are longer term with pricing agreements that may be up to six 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're activating spreads, we're investing $6 million for the reactivation for stack spread. And so we want to know 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.

But I guess without getting too much into details, I'd think that most of your work for the next 60 to 90 days is or at least 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?

Internally in the projection in Q1, we're not baking in any significant price increase there, and then we'll give it 2Q at the next call.

Your next question comes from the line of Blake Hancock from Howard Weil. Please go ahead. Your line is open.

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 day.

And then Andy from an operation and the Pressure Pumping prospective, the revenue is down, but the margin is up. Can you maybe talk about, are you seeing - I guess, I already expected that to potentially be down with some reactivation and some movements of the full year? 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 efficiencies and their cost control, even though we've had weather delays that impacted revenue by $9 million where for recurring cost for labor at the same time. But I think our operations teams continue to improve and their ability to manage their costs and deliver margins. I think, in terms of reactivations, we're not carrying a lot of cost for 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 Credit Suisse. Please go ahead. Your line is open.

On the rigs that you're reactivating are not in the press release that you have contracts for five. And I'm going to assume that the day rates for those are mid – low to mid 20s which is been the commentary, feel free to correct me, if that's wrong. I'm more interested in the duration of these contracts. Are these closure to one year or three year and I don't want to give anything competitive away, but can you talk about what kind of duration we're seeing in the contracts that both you and your ENP customers are willing to commit to it at this point?

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

And if I could move the pressure pumping, I can't ask the same question. A lot of the spreads that are working today are more dedicated than contracted. You know you guys didn't want to sign a contract when pricing was going up in the market, we're short. E&P company don't want to sign contracts of a couple months ago because oil could go to you know 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 we are marketing teams do a good job getting contract structure with a pricing agreement that gives us good visibility on how much work we're going to do. I don't believe we 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.

What would you build a new spread? I know you don't have that in your budget, so this is hypothetical. Would you build a new spread without a, say a two year contract or how much of a contract wanting to discuss price. But how much of it of the 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 have discussions with customers that at least gave us a year on a program and returns that we were comfortable with buying new hardware. I think - in terms of how we reactivated and the pricing levels that we wanted for those reactivations and we’ve just worked through a very huge integration at least for us combine 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’re going to push for the best pricing we can get in for the best turns we can get but back to any potential new builds that would come after activating 250,000 horsepower. Again I want to know that we have at least a year of a work program that our pricing that gives us an acceptable margin and we just not quite there for us yet.

And if I could sneak one why do we refer to it is revenue per day instead of dayrate like we use too?

In terms of drilling.

Yes, I am sorry in terms of drilling is it - because the contracts are structured different because of add on because I noticed that you and everybody else now refers to it is 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 add for the rig and that’s why we refer to it as revenue per day. If you could just quick and dirty on why the change has occurred in the semantics?

Jim this is Mark I’ll jump for a second to 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 kind of things when you ultimately decided when you took your total revenue against total number of days and – that’s how the industry I think moved there. But you’re correct that there all kinds of incremental we now think of rig pricing as what’s the base rig and then what the incrementals that we’re 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 2014 we look at it as Mark’s said in terms of base dayrate for the major capital asset or we want a certain return and when we’re adding things such as larger diameter drill pipe or other ancillary equipment to rig we’re going to be looking for a shorter payback and better returns on that. So that’s how we structure those.

And the next question comes from the line of Tommy Moll from Stephens. Please go ahead. Your line is open.

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

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

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 rate do you have and how many of those are currently active?

So technically all of our rigs could be upgraded as 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 the rigs in our fleet could be upgraded to super-spec rig.

Your next question comes from the line of Marc Bianchi from Cowen. Please go ahead. Your line is open.

My first question is on the couple of new conflicts I guess that are moving and then the traditional fleet from - that's been created from optimization. It sounds like just one of those has a customer locked in. Did I get that right?

We haven't called out any particular customer information on those fleets. But it's certainly our plan and that we're going to move to our mid-con fleets 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.

And where are the midcon fleets working from us for the fourth quarter?

Yes, they've been working.

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 guided up about 600 bucks. So there's some other cost increase in there? Should we be thinking about that as continuing - maybe there's some labor inflation. I don't know perhaps you have some reactivation that's going on there?

Some of that's going to be OpEx related to reactivations not when we're 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 contract.

Your next question comes from the line of Kurt Hallead from RBC. Please go ahead. Your line is open.

I heard a lot of positive commentary about the outlook, pretty much across all your or your business lines so sitting here scratching my head, trying to figure out why your stock is down 6%. So little 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 fleet in horsepower and spreads 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 could perform with your spread count in horsepower on an average basis per quarter?

I don't think I want to get into those levels of detail, but you know like I said, by early Q2 will be up to 24 spreads out of existing 125 million horsepower. We'll do further reactivation in 2018 and at some point we'll be able to activate you know another five spreads or close to five spreads out of the stacked equipment that we have in pressure pump.

Nature of my question really is for our report frac jobs on a quarterly basis and kind of in between 173 and 180 you know through the second, third and fourth quarter. So I just wonder if you guys were kind of in that 180 range. You're going to hitting up your maximum number of frac jobs given your existing fleet or there's some additional efficiencies you're going to gain and so on. So I was just kind of looking for some color on 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 two spreads is to improve the efficiency and the number of stages per month as well as pricing on those two spreads as well. But I think our teams will continue to improve the level of efficiency that E&Ps will allow us to get when we are working.

And then in the frac related and directional drilling business you know very service intensive business for a number of different peer group companies talk about incremental margins on freight versus ‘17 and maybe 35% to 40% type of range. The only reason I think that the Patterson frac business and Patterson Directional Drilling business should be anything less than what some of your previous 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 you know 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 through actual drilling or especially contract drilling. And you know we're going to see increasing activity levels. We see that in the rig count that we're projecting for the year and that's going to drive increased activity and pressure pumping and directional drilling in our rental business as well.

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 volume the sand per job or per pad or per well we’re 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 starts to increase. Regional sands have to be accepted by the customer and we have the line of delivery from the mine. And I think as customers start to sign off technically that its 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. Please go ahead. Your line is open.

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 their wells but I’m not aware of any that have said no yet. This is the process for approval.

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

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

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 do you see that business going with this kind of investment?

So MS Directional was a very good company with great operations. They have a challenge right now with some of their suppliers and their margins been impacted by an increase use of rental equipment. The $40 million of capital roughly two-thirds 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 and a rig count funded with the capital. So two-third of that $40 million is roughly earmarked for growth capital.

And then just also on this uses of cash working capital, what’s your projections for that or could you provide me guidance whether it would be a source of cash this year and if so how much?

We'll continue to grow we’ll probably it will be neutral to us in the long working capital I would see it as a big source of cash. At the end of the fourth 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 of 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.

But would it be for still more front-end loaded or more kind of equally base 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 certainly more front end loaded based on contracts because we’re not going to deliver $10 million upgraded rig without some kind of agreement for around a year.

Your next question comes from the line of Chase Mulvehill from Wolfe Research. Please go ahead. Your line is open.

I guess a lot of questions has been answered already, but a few kind of I guess may be 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 seven that you announced from last year, correct?

So we’re saying that 2018 budget allowance for 12 major rig upgrades and we previously announced three of those. Now there is other upgrades in the budget as well. The smaller upgrade of $1 million for high-pressure piping. There is $2 million for some walking systems in there as well, but its 12 major upgrades.

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

No, 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 oppose to building new rigs you know provides continued disappoint in this market. And I think our opinion is that we would rather upgrade a rigs than build a new rig up to a point where we're not happy with the economics, but technically all the rigs can be upgraded. But we're also pleased with the relative discipline in the market at the same time.

When you upgrade a rig, how much 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 mass and sub-structure.

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

And what’s the cost of the new build super-spec today if you were to go to the market?

When we were building high spec rigs back in 2014 and ‘15 they range from $22 million to $24 million.

And then will squeeze one more in real quickly. On the term rate, one of your competitors gave some information that kind of led to mid-20s now call it the low part of mid 20s term day rates for some of these super spec rigs? Is that the most recent five that you got, is that a fair average day rate for those five?

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

So we take the low out now?

We'll see how 2018 progressive.

Your next question comes from the line of Chris Wallace from Wells Fargo. Please go ahead. Your line is open.

Just filling in for Judd. Just wanted to clarify, maybe if you could quantify the impact of the mobilizations from mid-con in 1Q?

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

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

Thanks. First, I 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. You may now disconnect.