Good morning, and welcome to Independence Contract Drilling Second Quarter Financial Results Conference Call. All participants will be listen-only mode. [Operator Instructions] Please note today's event is being recorded. I would now like to turn the conference over to Phil Choyce. Please go ahead sir.

Good morning, everyone, and thank you for joining us today to discuss ICD's second quarter 2016 results. With me today is Byron Dunn, our President and Chief Executive Officer. Before we begin, I would like to remind all participants that our comments today will include forward-looking statements which are subject to certain risks and uncertainties. A number of factors and uncertainties could cause actual results in future periods to differ materially from what we talk about today. For a complete discussion of these risks, we encourage you to read the company's earnings release and our documents on file with the SEC. In addition, we refer to non-GAAP financial measures during the call. Please refer to their earnings release and our public filings for our full reconciliation of EBITDA and adjusted EBITDA and for definitions of our non-GAAP measures. With that, I'll turn it over to Byron for opening remarks.

Thanks Phil. Good morning, and thanks to everyone for joining us today. On today's call, I'll review Independence Contract Drilling's second quarter results and follow with thoughts on what we anticipate going forward. Phil will provide details on our second quarter financials and then we'll take questions from call participants. The second quarter came in inline with our expectations. During the quarter, ICD generated free cash flow at four rigs drilling with an additional four rigs earning revenue on a standby basis together representing 66% utilization of our available fleet of 200 series rigs. Importantly, we believe the second quarter represented an operational trough for Independence. During the second quarter, we completed the rig 217 upgrade to 7,500 PSI three pump system and the rig mobilized to a multi-well pad contract with a new customer, a large publically-traded Permian player. We contracted two rigs with another client which will be deployed to the Louisiana Haynesville during the third quarter, a new region for ICD and a market we foresee as another key he operating basin within ICD's strategic geographical service area. Economically efficient drilling operations in this basin require a 1,500 horsepower rig with omnidirectional walking capability for complex well designs, bi-fuel systems, a 7,the 500 PSI rated fluid system and most importantly, highly experienced rig crews prepared for challenging HPHT wells. We signed two multi-well contract extensions with a long-term customer and were informed that two rigs on standby will be reactivated and deployed at the Permian during the third and early fourth quarters. We have substantial inquiry on the few remaining idle rigs in our fleet and assuming commodity prices don't pull back anticipate reaching full effective utilization of our fleet during the first half of 2017. During the quarter, we continue to effort to streamline rig moving efficiencies. These modifications to our move protocols are materially reducing our cycle-time between wells in traditional rig moves. This enhances our operating performance compared to our peers and increases the value proposition ICD delivers to its customers. Having mapped our moves, we have been able to cut move time to as low as two days with proper customer logistical support. Day rates for pad optimal rigs are in the mid to high teen range. Although, we don't anticipate any material day rate improvement during 2016, we believe a shortage of omnidirectional walking pad optimal equipment and the value proposition of these rigs will drive day rates higher in 2017. We're beginning to see willingness on our customer's part to discuss term contracts as evidenced by our two recently signed contracts. Currently, contracts in the six month and long retainer range are part of current and forward discussions with term greater than six months becoming more realistic when the U.S. pad optimal fleet gets closer to full effective utilization in 2017. As ICD's fleet utilization increases, we don't foresee any difficulty in sourcing exceptionally qualified rig groups. Through the downturn, we retained our rig leadership in top talent to process by which top skill individuals worked temporarily and lower job classifications as rigs became idle. As rigs reactivate, these layers will be moved back to their previous roles and ICD will hire into the lower tiers of crew experience requirements. Although staffing won’t be an issue for ICD. We do anticipate incurring additional cost over the next couple of quarters associated with staging our crews into an accelerating ramp-up in activity. So we’ll provide additional quantification of these costs later in our discussion. We’ve maintained our cash operating cost at rig level at approximately $10,600 per day and we expect that cost to remain flat. More importantly, as rigs on standby go back to work and our fleet begins to approach full effective utilizations. We expect our reported fully burdened operating cost per day to average about $12500. To the downturn, we’ve made steady permanent improvements in our cash SG&A cost evidenced by a 23% reduction in SG&A during the current quarter compared with the prior year. Our SG&A is scalable and we don’t anticipate any material increase to our run rate as our rigs return to work and we grow our ShaleDriller fleet. The capital budget for the remainder of 2016 has increased from 3 million to 8 million, as we upgrade fluid systems to 7,500 PSI and we had third mud pump capability to select rigs for those customers who require and can fund this addition. It is noteworthy that the vast majority of our customers are moving towards longer laterals which require 7,500 PSI fluid systems in order to deliver adequate hydraulic horsepower to the bit phase. We believe that 7,500 PSI systems are becoming a requirement and industry standard prepared applications. Our balance sheet allows us to rapidly respond to customer requirements in this regard. The stabilization and the improvement of the contract drilling market in ICD core basins is welcome news, but I think it’s important to take a step back and ask what’s difference this cycle and examine what key contract drilling value drivers maybe as the recovery unfolds. I think, the foremost difference to alienating this recovery from our previous cycles is that today the industry knows exactly where to drill to recover a large oil and gas reserve base. There is no real cost associated with discovering large Independence and majors have tens of thousands of map drilling locations in inventory. The second major factor is the recent application of the new drilling and completion technologies that substantially lower the time and cost incurred to drill, complete and put new wells on production. Our E&P customers have told us that the application of locking rigs and pads, advances in frac and completion engineering and well side logistic coordination has lower the overall cost to the level that $50 oil supports target rates of return of across a broad portion of their asset portfolio’s . Right now, all of our customers are actively evolving from focusing on single well economics to long-term strategies focused on pad-centric well bore manufacturing models driving permanent reductions in their development cost structure. For example, during the quarter, and in partnership with long-term customer, we commenced their first multi-well pad drilling program. On the first pad, we decreased drilling days by 40% from the previous ASE. The outcome of the combinations of these new faucets of the oil and gas field frac pattern, a large known resources base and disruptive oil service technologies driving substantial and ongoing development and production cost reductions. As the establishment of the U.S. shale resource is the global swing producer of oil. For our E&P customers who are now filling the role of swing producer for global oil supply this means owing very large asset portfolios, concentrated in the most economic North American land basins and these are the specific basins that are the focus of ICD’s business development and operations. I don’t think ICD could be better positioned to play a leadership role in the expansion of North American drilling activity. I’ll conclude our prepared remark by addressing the rig replacement cycle and thoughts on future rig build. The rig replacement cycles have been interrupted, but it's alive and well. The driver of the replacement cycle is the economic and technological obsolescence of legacy rigs resulting from the broad adoption of pads by the E&P customer base as the most economic and efficient mechanism for shale development, and the accelerating growth in the number of wells per pad. In fact, last week when a very large independent just informed us that they are moving to a 21 well pads as their standard design. While there will be ongoing demand for a high quality but non-walking SCR and AC rig base, the number of those units and demand will shrink while the vast majority of incremental demand will be for omnidirectional walking pad optimal rigs. This is the equipment that will go to full utilization the quickest and see contract tenure extension the soonest. I’ll now hand the call over to Phil and he will discuss our second quarter financial results in detail with you.

Thank you, Byron. During the second quarter, we reported a net loss of $4.2 million or $0.12 per share. Included in this net loss were approximately of $1.5 million as an executive retirement expense and $0.5 million non-cash write-down of deferred financing costs associated with our April credit agreement amendment. Excluding these items, we reported a net loss of $2.2 million or $0.07 per share. Adjusted EBITDA for the quarter came in at $5.4 million. The fleet generated 732 revenue days, representing a 22% sequential decrease from the prior quarter. This included 363 days earned on a standby-without-crew basis. Our marketed rigs achieved 66% utilization which included our recently completed rig conversion that reentered our fleet engine. Overall, we recognized revenue of $15.2 million, including $1.6 million associated with an early termination of a contract that occurred at the end of the first quarter of 2016. Pass-through revenues were approximately $400,000 during the quarter. Gross margin per operating day during the quarter was $11,359 per day which is favorable compared to guidance provided on our first quarter conference call. Especially due to the extension of higher price expiring term contract for an additional mop during the quarters. Galayda Yard costs that we expensed during the second quarter was $500,000 and pass-through cost was $400,000 during the quarter. SG&A expenses during the quarter were $5 million including the executive retirement accrual. Excluding those payments SG&A expense was $3.5 million including $1.2 million related to non-cash stock-based compensation. Cash SG&A expense of $2.3 million represented over a 20% decline from the prior year quarter. Depreciation expense was $5.8 million during the quarter, and second quarter tax expense was deminimis. Interest expense of $1.1 million which included a non-cash write-down of deferred financing cost came in line with our prior guidance. At June 30th, we had net debt excluding capitalized leases of $9.3 million. Our borrowing base under our credit facility was approximately $81 million. During the quarter cash outlays for capital expenditures, net of disposal and insurance proceeds of $4.6 million. Our backlog at term contract at June 30th was approximately $48.5 million which included our two recently signed contracts. One of the rigs mobilizing for these new contracts is a rate currently earnings to standby revenue and there the term contract that expires in the middle of the third quarter. Looking at the third quarter, we expect that we will have between 740 and 750 revenue days. Of which we estimate approximately 37% will be earned on a standby basis. Approximately 54% of this revenue days will be from term contracts signed in 2014. We estimate our margin per day to range between $7006 and $7009 per day. A sequential decline compared to the second quarter relates to substantially larger percentage of our revenues being earned at spot market rates. We have two term contracts to expire during the second quarter and a third contract to expire during the third quarter. We also recognize early termination revenues in the second quarter that will not continue during the third quarter. This margin guidance excludes reactivation cost associated with three non-operating rigs back to work. We expect to incur up to $250,000 of additional operating expenses each time an idle rig is recommissioned and placed back in service. Given the rapid pace that we expect our fleet to reach full effect of utilization, assuming commodity prices did not deteriorate, we also intend to accelerate the hiring and stating of our crews. Today, we know four rigs we expect to return to operations during the third or early fourth quarter and there are three additional rigs which we're in active discussions regarding reactivation. This includes rig reactive -- this includes reactivating rigs from standby status. For the third quarter, we estimate these additional reactivation in ramp-up cost including additional cost of staging crews to range between $1 million and $1.5 million during the quarter depending on the exact timing of rig reactivations. If additional rigs are reactivated during the quarter, early in the fourth quarter, actual cost could exceed this guidance. Our Galayda Yard cost were expect to expense during the third quarter, should be flat with the second quarter and these costs are not reflected in our margin per guidance. We expect SG&A for the third quarter to approximate $3.3 million, of which approximately $1.1 million will be non-cash stock-based compensation. Depreciation expenses should approximate $6 million and interest expense should approximate $550,000 of which approximately $150,000 will be non-cash related. We do expect to recognize some one-time non-cash disposal charge for obsolete equipment removed in connection with 7,500 PSI three mud pump upgrades we're completing. Tax expense should be flat with the second quarter. On the capital side, we have increased our capital budget for 2016 by $5 million, principally relating to the addition of 7,500 PSI mud systems and third mud-up [ph] to certain shale rig and inventory purchases. As rigs go back to work, we also will be investing in working capital which we expect to be approximately $600,000 per reactivated rig. Thus we do expect to incur some incremental borrowings under our revolving credit facility as we upgrade and put rigs back to work. However, we do not see any capital restraints under our credit facility that would limit our ability in any way to respond to this increased demand. Finally, we expect the share count to be utilized and calculating loss per share will be approximately 37.4 million shares in forward quarters. And with that I will turn the call back over to Byron.

I have no comments at this point. So, operator would you open the line for questions and answers.

Absolutely. We will now begin the question-and-answer session. [Operator Instructions] And today's first question comes from James West of Evercore ISI. Please go ahead.

Hey, good morning guys.

How, are you doing James?

Good. Byron, I know what your utilization is, but what you estimate the industry utilization is for pad optimal rigs at this point.

Yes. That's a hard question to answer, so we look at the same public data you do. If we -- a wild guess would be something 80%, but we think it's approaching that kind of that magic number where we begin to get some term in your contracts and we say that because we're beginning to have conversations, we haven’t done it, but we aim to have conversations in contract terms that are excess of six months. And that typically happens when you get up to that 80% to 85% utilization rate.

And for those term contracts that you're having these discussion is the pricing consistent with today's levels or does it have some type of premium.

We haven’t got there yet. So, it's -- this is -- I was just out in West Texas and this is pretty nascent, but it's headed in the right direction, but we haven't had any conversations about day rates in excess of that mid to high teens rate that we're operating in right now.

Okay. Fair enough. And then last one from me. In order to build additional rigs from -- at today's market rates, is this a question of term contracts that are year plus obvious thing to see or do rates go up as well?

I think they will go up hand in hand James, but certainly, the key to us would be a financeable rig, meaning a term contract in excess of a year. That would be the starting point where we have those conversations. We actually have had people coming in and ask a question is if we wanted -- if we -- they -- we were to build a rig for them. What way to look like, so we'd have those conversations. And we probably, at this point, wouldn't build any more 200 series rig. We have a design for a 300 series that addresses some of the things we see in the industry gravitate to over the course of last few years. So we've got those two half build rigs that we've talking about. We got one upgrade. Those will be the last 200 series we'd ever build and then we move on to a 300 series. And the conversations we had with people vis-à-vis build have been in regard to the 300 series rig.

And what are the key aspects that are different from the 200 series?

You'd have a longer walking capability. You'd go to [Indiscernible] mud pumps probably two quince rather than three triplexes. You'd have additional racking capacity. And the design will be such where the top driver stay in the mass during the move which we take eight or 12 hours off a rig move.

Okay. Sounds very interesting. Okay. Thanks Byron.

You bet.

And our next question today comes from Marc Bianchi of Cowen. Please go ahead.

Hey, thank you. Curious -- I apologize I missed the first, two or three minutes of the call if you mentioned this first. Just interested to hear what customer sentiments like here in the last call it three to five weeks with the reduction in oil price if you notice any noticeable change and kind of what you can talk to us it relates to customer interest at different oil price levels?

Sure. So, in general, the conversation has been that as a result of efficiency improvements and cost reductions $50 of work across a broad spectrum of our client's portfolio. Clearly we are not at 50 right now. But I'll also say that nothing go straight up or straight down and I think it's more the forward expectation for where prices are going to be and how the behavior is driving the current reactivation that we are seeing. So, I think as long as expectations are in place for an environment that's going to be in -- over the course of where this year is going to be approximately 50 or above. I think we’re in a good shape. And I think if to the extent that I read the published material from the sell-side, the buy-side there seems to be the expectation that's in place. And that also at least in the last couple of days with the expectation in place with the client base I was speaking with. Obviously, if prices move down, it's going to be another downdraft, but that's not what people hands on right now.

Okay. Okay. Thanks for that. And then on the four rigs that are expected to return to work here, are they all going to work in the Permian or they are going to do in different basins?

No, Haynesville and Permian, so we picked up a new client two-rig contract in the Haynesville and it will be a slip between the Haynesville and the Permian. We also -- we’re in conversation with the Stacks Group [ph] and Eagle Ford as well. So, I think if the across our -- if rigs go back to where I think you see as probably hit most of the basins that are in our target operating area.

Is there a difference in your overall cost to be running a couple of rigs in the Haynesville, a couple of rigs in [Indiscernible] and a couple in West Texas versus having them all in West Texas, how should we think about -- how that impacts your overall cost structure?

The answer is yes. The further answer is our employee base which works 14-14 who lives across this area. And so what we do is we slide people into those areas who are geographically the closet and so there is an impact I think it's not going to be something you will see relative to financial scale.

No, I don't think it would be meaningful when we would think about our cost structure going forward.

Got it. Okay, thanks gentlemen. I'll turn it back.

And the next question comes from Connor Lynagh of Morgan Stanley. Please go ahead.

Yes, thanks and good morning.

Hey, Connor.

I'm wondering if maybe you could give a little bit more color, you were sort of mentioning just now, but just where the interest is from your customer base on your uncontracted rigs and just what type of customers you are primarily reaching out?

The answer is really Permian centric. We’ve got some conversations in Mid-Con, some conversations in the Eagle Ford. We’ve obviously had successful conversations in the Louisiana, Haynesville. So, it's kind of come across the client base that you've seen us published before. So, -- and actually that's helpful. Is there another way I can get out this for you?

I mean, I guess, I am basically wondering, my -- I was little surprised to see the add in the Haynesville I was thinking, Permian was sort of going to be where most things were going. So, I'm just interested to hear if you're noticing a different trend in where the interest is versus what we might expect?

Basically, it's broader than it's been in the past. It's -- certainly the Permian is the core area that our discussions are focused -- most of our discussions are focused on. But I think that either we're having a much broader set of discussions across all these areas. So, with -- and again this has really occurred in the last month or month and a half. Gas prices have improved and the cost structure of Haynesville down, so I think that you'll probably see -- I would expect you'd see additional interest in people putting incremental rigs back to work in selected areas of the Haynesville.

Got you. And maybe just shifting gears a little bit here. I mean if you're sort of thinking you are going to be at full utilization early next year, how are you thinking about your priorities on pushing your rates when you get to that point versus just keeping everything working and starting up the new build program again. Where would you say your priorities are on that front?

Well, as a small player, we're really a day rate taker. So, what we've done historically and what we'll continue to do is get the highest day rate and the longest tender available in any of these markets. I think you can expect that. And we'll take a deep dive at our cost structure. I think there's some things we can do incrementally over the course of the year that will improve our overall cost structure. And at that point, we'll continue to very efficiently and safely operate our entire fleet minimizing unscheduled downtime; -- running a very competitive and compelling PRIR and the market will come to us. And when the market comes to us at the point where our contract terms result in the financeable situation or we have somebody come to us on a one-off or two-off and say, hey, look we'd like to add three or four rigs, what would it take for you to build these for us? I think we'll start that up again. I don't think you're going to see that before mid-2017.

Yes, fair enough. And just one last small one here. When you refer to your maximum effective utilization, how do you think about -- what that actually means?

All the rigs on contract.

Okay. Got it. Thanks a lot.

You bet.

And our next question comes from Kurt Hallead of RBC. Please go ahead.

Hey good morning.

Hi Kurt.

So, really out [ph] very compelling growth case for ICD, especially on the walking omnidirectional dynamics and -- so as you -- maybe as you have the opportunity, can you kind of give us your view on how many omnidirectional walking rig you think will be market place within the course the next 12 to 18 months? And you have done much visibility and are these major Independence kind of looking at the opportunity?

So, the -- when we have these conversations, Kurt, and the driver for this type of equipment is pads and particularly larger pads. So, we're talking to a large independent who have told us that they're going to go to 21 well pads as their standard development structure in the Permian. And that size of pad is going to require -- it does not going to require it. I mean you can use whatever you want to drill that. If you're going to drill effectively and if you're going to give the full economic benefit from that size of a pad, you're going to use a walking rig. The other things come up. For example, with the pads are close enough, we can walk rigs from pad to pad rather than do a conventional move. And that was one of the reasons I think that we put a couple of rigs back to work this quarter because they -- the client was surprised to learn we could do that and that again illuminated multiple days from they thought they -- their ASE was going to be to developer's pads. So, those are really specialized conversations and the driver is the adoption of pads. I think the second is oil and gas price downturn has accelerated the internal discussion about pads across every client we're talking to. So, there are people that we were talking to in the Permian before that weren’t interested in pads all of a sudden some of those people are the most aggressive in the application of the pads going forward. So how many rigs are going to be out there, Kurt, I don’t know, I think we'll go back to -- I think it’s clear that this asset class will back to full effective utilization the soonest. I think when you see year contracts, you could be pretty certain that across the fleet of this type of rigs that are fielded by us and our competitors are at 80% above. And if you see day rates moving up for this asset class and not for other asset class, you can draw your own conclusions. And I think that’s what we expect to see unfold over the course of 2017. So, our expectation would be this asset class goes back to work, day rates -- rather contract terms extend and then later in the year, you will see a day rate move.

All right. So, when we look at and try to assess the element of markets, it seems like there's a lot of circular references as to how many of these assets are truly available? When we talk to -- some of the larger players in the business it doesn’t appear that they have walking rigs in their inventory. So, my guess -- my point is this market can -- should be tight right now in effect purpose will be 100% utilization, if they are not, why do you think they are not?

You have to ask E&P, I think every one of our clients went through a different experience when we went through this downturn. I think there was a lot of just overall reduction in rig count. As people internally restructured, I think it's been very difficult for the E&P community to go through cost cuttings that they have gone through and I think a lot of them or many of them seized operation or cut back -- I don't want to seem discriminately, but very broadly as they took a step back and said what does this mean where we're headed and what are our plans going forward. You have the whole issue of rigs on contract, it stay on contract and so to the extent you've got a rig that isn’t a walking rig, it's on contact and you got a substantial payment penalty, you’re going to have to incur to drop it to get more productive rig and probably they are going to run their contract out. You have got subcontracting that went on where you could take a rig -- people take a rig at $25,000 a day, day rate on long-term contract and sub it out at $10,000 a day. And so that’s really $10,000 a day a day rate that was an accommodation to the guy who is paying 25 is going to only paying 15 and he is got the equipment off his books. So, I think we went through a lot of that, which is okay to both of us and I think to the sell-side community. And I think that we're coming to the backside of that now and it will be a lot clearer as we go to the next three or four quarters.

Got it. And then, lastly, you mentioned three four rigs that you're going to activate and put back into service. You talked about six months contracts. I may have missed it, but what’s the rate range in which these rigs are going to -- could go back for?

Mid-to-high teens, Kurt. Amidst all the conversations right now, if you are looking just a day rate and not any ancillary services, so you strip out trucking, your chasing running tools, rig day rates where this type of equipment across industry are mid to high teens

Got it. All right. Thanks, Byron.

You bet.

And our next question comes from Daniel Burke of Johnson Rice. Please go ahead.

Hey good morning, guys.

Hey.

Not too many, left here, but Phil still maybe just one Calgary next from our model still up speed here, how many rigs in Q3 do you have still operating on 2014 type winnage term contracts?

4.5.

4.5, okay.

In the third quarter.

Okay. And then after you put the two rigs in the Haynesville and you restart the two rigs that have been on standby that will leave --- at that point, you have three rigs -- I guess I'm looking for some more buckets here, three rig on spot, three idle, I mean can you kind of take me through the baskets?

You want me to -- do you want the third quarter or what we might see in the fourth quarter?

Well, I guess I was asking sort pro forma for these next four and then maybe you could solve the Q4 equation for me on what happens after that?

So, for the third quarter if go through your rig, we’ve got three rigs on term contracts that will be extending through the quarter. One of those will drove through the whole quarter, two of those are on standby and will go out kind of midway through the quarter or at the end of the quarter and then we’ve got one of standby that the term contract expires in the middle of the third quarter and that’s one the rigs that's in the yard to the Haynesville. We have got three rigs operating in the spot market.

Right.

That we expect to operate throughout the spot market. And then we got one rig that we expect -- it's on standby the term contract that will go through the whole quarter on standby and we haven’t been informed yet that they will activate that rig. So, if you go and you look at the fourth quarter -- fourth quarter under that guidance with nine rigs earning revenue, three would go in on drilling on term contracts with one rig on term contract earning revenue on standby basis, we got the two rigs in Louisiana and we'd add three other rigs in the spot market. And then well what we don’t know is conversations for three other rigs that possibly could something could have where they could reactivate late in the third quarter down to fourth quarter. We just have to wait and see.

Okay.

If oil prices stay at 50 above by the end of the fourth quarter, we probably have one or two rigs that aren’t working.

Yes, that’s all for Byron. And then I guess we've getting comfortable with the two rigs that you have out in West Texas that have been kind of rolling well-to-well spot. But in the early comments on the performance for the conversion, sounds like you guys expect that one to stay active; I think that’s in something of spot situation.

Both of those contracts were just extended.

Okay. Great. And then, I guess maybe last one after you complete this latest round of upgrades, how many of the 200 series rigs will have the 7,500 configuration specifically?

All of them will. Eventually, I think it's going to be requirement. So, as we reactivate rigs or we have downtime between contracts, we'll upgrade. It's really a piping situation. So, you upgrade to 7,500 PSI high pressure piping systems. And then it's different fluid ends on the pumps. So, eventually the entire fleet. Right now we've got eight. And again these rigs come back, they are going to come out at 7,500 PSI.

Daniel if you think about the CapEx, the incremental CapEx guidance that we gave. Byron talked about the eight. That guidance includes another rig potentially that we could upgrade to 7,500 PSI in that incremental CapEx guidance.

The issue is that the length of the laterals were drilling results in fluid pressure loss through the drill pipe across the motor such that in order to have enough hydraulic horsepower at the bit phase and then to maintain turbulent flow on the back side, so you keep your cutting suspended, you have to run a 7,500 PSI system at the surface. Running at 7,500 and maybe 6,000 or the low 6s, but its above 5 and you need a safety factor. So, that's why -- that's what's driving these changes to -- in the industry to 7,500 PSI surface systems.

That's helpful. Well, thank you guys. Thank you, Byron.

[Operator Instructions] Our next question comes from Rob MacKenzie of IBERIA Capital. Please go ahead.

Thanks guys. Phil, I wanted to check with you some of the numbers you gave out early to make sure I got them right, if I may. I think you said the $250 million OpEx to reactivate each rig, what you also said that each reactivated rig would need about $600,000 in working capital.

Yes. That's just going to be -- we put the bag -- the working capital as you're putting the rig back to work. And now your payables receivable. Most of the expenses are payroll related -- about half. And you're paying that right away. Don't get paid for 60 days after invoice to customer. So, that's just something we're going to be have to -- that's money we're going to have to fund as our rigs go back to work.

Okay. And I think you also mentioned that in the third quarter $1 million to $1.5 million reactivation cost. What would that number be? And you also said kind of full utilization by the end of the first half of 2017. If we're kind of go soup to nuts in terms of reactivating what's out there, if we exclude rig 101 for now, what would that soup to nuts reactivation cost look like?

Okay. We talked about up to $250,000 of reactivation cost and that's really our guide going in and recommissioning the rig, requesting kind of some of the rubbers, and parts and things like that and all that good stuff. And there's also in that guidance was -- we're bringing in an awful lot of crews very quickly. We're going from four rigs drilling to date to eight at the end of the quarter. The people are available just how we stage in. It's going to cost money. So, going forward, we'll -- up to 250 for each idle rig that goes back out to work. Whether we have as that level of crew staging cost is going to depend on how rapidly the rigs come back. If all -- if they come back very quickly, then -- in those quarters, it's going to be -- it could be -- it could hit the quarter pretty hard. And then we just have to see how the fourth quarter plays out and when these rigs come back to work.

Right. So, to Byron's related comment having conversations with three other rigs for 3Q and 4Q, 4Q could be quite a working capital build that would then reverse once those rigs could get -- go to work, right?

That's correct. And it could be the third quarter, if the rigs are going out in October, then a lot of these costs are going to be incurred in the third quarter. And so that's -- and we just don't know the answer to that yet.

Okay. Great. And then thinking forward, I know you were asked before, but what kind of -- obviously it's necessary to build -- what kind of rate would you look to have before you commit to building a new rig again?

The term is I think the most critical component, because if you're getting term, rate is going to follow. In general, when we founded the company, we target full year paybacks. And I suspect that the day rate associated with term would lag that payback metric a little bit in the beginning. But it's kind of chicken and egg thing, if we see the rig replacement cycle behaving as we expect it will, and it's not that we're taking market, a new market is developing and the industry is filling it. And in order to have -- we need to have rigs available so our marketing and business development people can talk to clients about delivery dates relative to their requirement. So, once we got term -- adequate term, I think we would probably engage in those discussions and day rates in -- at 20 or above, I think would get us where we needed to get to. But certainly we wouldn’t building rigs with the expectation of that as a run rate. Our expectation would be that we're -- that this segment of the market is returning to full effective utilization, multi-year contracts and much higher day rates and is certainly -- and that was not our expectation. We don't tamper this a little bit, but right now that's how we expect this to unfold.

Okay. And then just follow-up on that. If you were to decide to build a 300 series rig, what do you think your delivery time would look like from signing of the agreement to delivering the rig?

I think that serial number 0001 is always challenging. You'd want to build in some slack there. I have to talk to our engineering staff, but I'd certainly not want to push it any tighter than nine months. Once we got serial number 01 out, got to red lines, then we'd be back to regular six-month delivery cycles. It's not that -- it's not harder, it's just different.

Yes. Okay. Thank you. I'll circle back.

And our next question comes from Mark Kelley of FBR Capital Markets. Please go ahead.

Thanks guys. Just a quick clarification. So, the earliest period that you said the market at fleet might to full utilization is 1Q 2017?

What I said was that I expect in the absence of a down-drafting commodity prices based on the calibrations we're having right now, I would expect that our fleet would be a full effective utilization during the first half of 2017.

First half? Okay, great. That's all from me. Thank you.

And our next question comes from Brian [Indiscernible] of JMP Securities. Please go ahead.

Thank you. I have two very quick ones. You said that eventually all your equipment will be 7,500 PSI as they come in for your upgrades. How many are there currently? I missed, I don't think you said that.

Eight.

There's eight. And then our CapEx guidance were -- you had assumed were bringing in kind of equipment to add a ninth.

Yes. Got it. Okay. Second question, after some are purchased, does that have any effect on you, will have effect on new build or your systems that you're using? Or how should we look at that risk?

I think well, we actually met with the Schlumberger folk right after they did that, Phil and I did. And the conversation was very good. And the indication we got was that that was critical technology for them internally. But their expectation and plans were to run the business as it had been run and to continue to supply the industry with that type of variable frequency drive. Along with us many of our competitors have standardized on that systems. I suspect that we're in a position now which is actually helpful vis-à-vis Schlumberger to the extent Schlumberger contract rigs. Everything they are doing internally with regard to their rig of the future and so on would be plug-and-play with regard to our equipment. So, I think there's probably some benefit to the industry as well. So, we don't see a risk and we actually see that there may be some benefits.

Thank you. And final one, if you're talking about these mega-pads, is there any risk that you'll lose some of the surface work and the early work just about the rigs or do you not see that as a risk?

I think they are going to continue to use solders [ph] if that's what you're talking about, we don't do that.

Okay. That's it. Thank you.

You bet.

[Operator Instructions] Our next question comes from Matthew Johnson of Nomura. Please go ahead.

Hey, good morning gentlemen.

Hey Matt.

Hey.

A quick question on your OpEx guidance, pretty impressive that you're looking to hold it flat at the rig at least in the near-term. Just wondering how do you see that metric unfolding as this recovery kind of plays out and as the fleet moves back to full utilization?

I think the cash component stays flat and the GAAP fully burden component drops a little bit, because we're spreading our fixed cost over a larger asset base. So, you can take a look at what gets allocated to the rig. Its health, safety, and environment, its rig maintenance and we will be adding people. If we add people, these will be very incremental and so that reported cost will come down. Phil, do you want to--?

Yes. I think we're comfortable when you get -- get back the full effect of utilization. We get out of the stand-by situations that we're in. Those rigs are activating more back. We think our fully burden OpEx cost in 12.5 [ph] range is -- that's our goal and that's what we think we're going to be able to do.

Got it. Great. Thanks guys. That's it from me.

And ladies and gentlemen this concludes our question-and-answer session. I'd like to turn the conference back over to Byron Dunn for any closing remarks.

Well, sure. Thank you everyone for joining us today. We really appreciate your interest and we appreciate the broad and good questions that we received today. We're excited about recovery in drilling activity in North America. ICD is well-positioned from a leadership, balance sheet, and liquidity standpoint as we've discussed. During the downturn, we worked very diligently and maintain focus on the preservation of intellectual capital and skilled employees. And we're implementing strategies right now to redeploy our people over the coming quarters. And I'd like to thank all of our employees for their ongoing commitment to ICD and its success and safety record. And we look forward to speaking with you all next quarter.

Thank you, sir. Today's conference has now concluded. We thank you all for attending today's presentation. You may now disconnect your lines and have a wonderful day.