Independence Contract Drilling Inc (ICD) 2016 Q2 法說會逐字稿

Good morning and welcome to the Independence Contract Drilling second quarter financial results conference call. All participants will be in listen-only mode. (Operator Instructions). After today's presentation there will be an opportunity to ask questions. (Operator Instructions). Please note today's event is being recorded.

I would now like to turn the conference over to Philip 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 measures during the call. Please refer to the earnings release and our public filings for a 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 in-line with our expectations. During the quarter, ICD generated free cash flow and had 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 a 7,500 PSI three-pump system and the rig mobilized to a multi-well pad contract with a new customer, a large publicly-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 operating basin within ICD's strategic geographical service area. Economically-efficient drilling operations in this basin require a 1,500 horsepower rig with omni-directional walking capability for complex well designs, bi-fuel systems, a 7,500 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 would 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 process don't pull back, anticipate reaching full effective utilization of our fleet during the first half of 2017.

During the quarter, we continued efforts 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 omni-directional 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 customers' part to discuss terms contracts, as evidenced by our two recently-signed contracts. Currently, contracts in the six-month and longer tenor 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 crews. Through the downturn, we retained our rig leadership and top talent through a process by which top skilled individuals worked temporarily at a lower job classification as rigs became idle. As rigs reactivate, these leaders 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 costs over the next couple of quarters associated with staging our crews into an accelerating ramp-up in activity. Phil will provide additional quantification of these costs later in our discussion.

We have maintained our cash operating cost at the rig level at approximately $10,600 per day and we expect that cost to remain flat. More importantly, as our rigs on standby go back to work and our fleet begins to approach full effective utilization, we expect our reported fully-burdened operating cost per day to average about $12,500.

Through the downturn, we have made steady permanent improvements in our cash SG&A cost, evidenced by the 23% reduction in SG&A during the current quarter compared to 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 is increased from $3 million to $8 million as we upgrade fluid systems to 7,500 PSI and add 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 face. We believe that 7,500 PSI systems are becoming a requirement and industry-standard for pad applications. Our balance sheet allows us to rapidly respond to customer requirements in this regard.

The stabilization and improvement of the contract drilling market in ICD's core basins is welcome news, but I think it's important to take a step back and ask what's different this cycle and examine what key contract drilling value drivers may be as the recovery unfolds.

I think the foremost difference delineating this recovery from all previous cycles is that today the industry knows exactly where to drill to recover a large oil and gas reserve base. There's no real cost associated with discovery. Large independents and majors have tens of thousands of mapped drilling locations in inventory.

The second major factor is the recent application of 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 walking rigs on pads, advances in frac and completions engineering, and well site logistics coordination has lowered their overall costs to the level that $50 oil supports target rates of return across a broad portion of their asset portfolios.

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 a 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 AFE.

The outcome of the combination of these new facets of the oil and gas field fact pattern, a large known resource base, and disruptive oil service technologies driving substantial and ongoing development, and production cost reductions is the establishment of the U.S. shale resource as 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 owning 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 prepared remarks by addressing the rig replacement cycle and thoughts on future rig build. The rig replacement cycle has 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, one very large independent just informed us that they're moving to 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 in demand will shrink while the vast majority of incremental demand will be for omni-directional walking pad-optimal rigs. This is the equipment that will go to full utilization the quickest and see contract tenor extension the soonest.

I'll now hand the call over to Phil and he'll 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 $1.5 million of 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 in June.

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 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 was favorable compared to guidance provided on our first quarter conference call, principally due to the extension of a higher-priced expiring term contract for an additional month during the quarter. Galayda Yard costs that were expenses during the second quarter were $500,000 and pass-through costs were $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 de minimis. Interest expense of $1.1 million, which included the non-cash write-down of deferred financing costs, 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, were $4.6 million.

Our backlog of term contracts 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 rig currently earning standby revenue under a 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 these revenue days will be from term contracts signed in 2014.

We estimate our margin per day to range between $7,600 and $7,900 per day. The sequential decline compared to the second quarter relates to a substantially larger percentage of our revenue being earned at spot market rates. We had two term contracts expire during the second quarter and a third contract expire starting the third quarter. We also recognized early termination revenues in the second quarter that will not continue during the third quarter.

This margin guidance excludes reactivation costs associated with putting 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 effective utilization, assuming commodity prices do not deteriorate, we also intend to accelerate the hiring and staging of our crews.

Today, we know of four rigs we expect to return to operations during the third or early fourth quarter and there are three additional rigs for which we are in active discussions regarding a reactivation. This includes reactivating rigs from standby status. For the third quarter we estimate these additional reactivation and ramp-up costs, including additional costs of staging crews, to range between $1 million and $1.5 million during the quarter depending on the exact timing of our rig reactivations.

If additional rigs are reactivated during the third quarter or early in the fourth quarter, actual costs could exceed this guidance. Our Galayda Yard costs we expect to expense during the third quarter should be flat with the second quarter and these costs are not reflected in our margin-per-day 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 expense 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 charges for obsolete equipment removed in connection with the 7,500 PSI three mud-pump upgrades we are 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 pumps to certain ShaleDriller rigs 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 in 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). James West, Evercore ISI.

Hey. Good morning, guys.

How are you doing, James?

Good. Byron, I know what your utilization is, but what do 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 (inaudible) that you do. A wild guess would be something under 80%. But we think it's approaching kind of that magic number where you 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're beginning to have conversations on contract terms that are in excess of six months. And that typically happens when you get up to that 80%, 85% utilization rate.

And for those term contracts, when you're having these discussions, is the pricing consistent with today's levels or does it have some type of a premium?

We haven't gotten there yet. So, 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 for me. In order to build additional rigs at today's market rates, is it just a question now of term contracts that are a year-plus that you'd need to see? Or do you need to see rates go up as well?

I think they'll go up hand in hand, James.

Okay.

But, certainly, the key to us would be a financeable rig, meaning a term contract a year, in excess of a year. That would be the starting point where we'd have those conversations. You know we actually have had people come in and ask that question. If we were to build a rig for them, what would it 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've seen the industry gravitate to over the course of the last few years. So, we've got those two half-built rigs that we've talked to you about. We've got one upgrade. Those would be the last 200-series we'd ever build and then we'd move on to a 300-series. And the conversations we've had with people vis a vis build have been in regard to a 300-series rig.

And what are the key specs that are different from the 200-series?

You'd have a longer walking capability. You'd go to quintuplex mud pumps, probably two quints rather than three triplexes. You'd have additional racking capacity. And the design would be such where the top drive would stay in the mast during the move, which would take eight or 12 hours off of a rig move.

Okay. That sounds very interesting. Okay, thanks, Byron.

You bet.

Marc Bianchi, Cowen.

Hey, thank you. Curious -- I apologize. I missed the first two or three minutes of the call if you mentioned this. But just interested to hear what customer sentiment is like here in the last, call it three to five weeks, with the reduction in the oil price; if you've noticed any noticeable change and kind of what you can talk to as 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 works across a broad spectrum of our clients' portfolios. Clearly, we're not at $50 right now, but I'll also say that nothing goes straight up or straight down. And I think it's more the forward expectation for where prices are going to be and how they'll behave that's driving the current reactivation that we're seeing.

So, I think, as long as expectations are in place for an environment that's going to, over the course of later this year, is going to approximate $50 or above, I think we're in good shape. And I think, to the extent that I read the published material from the sell side and the buy side, that seems to be the expectation that's in place. And that also, at least in the last couple of days, was the expectation in place with the client base I was speaking with. Obviously, if prices move down there will be another downdraft, but that's not where people's heads are 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 are they going to different basins?

No, Haynesville and Permian. So, we've picked up a new client, a two-rig contract in the Haynesville. And so, it will be a split between the Haynesville and the Permian. We're in conversations with the STACK SCOOP in Eagle Ford as well. So, I think across our -- as rigs go back to work, I think you'll see us 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 rigs in the Haynesville, a couple rigs in SCOOP STACK, 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 and 14, lives across this area. And so, what we do is we'll slot people into those areas who are geographically the closest. And so, there is an impact. I think it's not going to be something you'll see roll through our financials. Phil?

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

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

Connor Lynagh, Morgan Stanley.

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 it just now, but just where the interest is from your customer base on your un-contracted rigs and just what type of customers that are primarily reaching out.

The interest is really Permian-centric. We've got some conversations in Midcon, some conversations in the Eagle Ford. We've obviously had successful conversations in the Louisiana Haynesville. But, Connor, it cuts across the client base that you've seen us publish before. So, it's -- I'm not sure that's helpful. Is there another way I can get at this for you?

I mean I guess I'm basically wondering, I was a 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.

It strikes me that it's broader than it's been in the past. Certainly, the Permian is the core area that all our discussions are focused -- or most of our discussions are focused on. But I think that we're having a much broader set of discussions across all these areas. And, again, this has really occurred in the last month or month-and-a-half. Gas prices have improved and the cost structure in the Haynesville down so I think 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. Got you. And maybe just shifting gears a little here. I mean if you're sort of thinking you're 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 tenor available in any of these markets. I think you can expect that. And we'll take a deep dive in 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 TRIR and the market will come to us. And when the market comes to us to the point where our contract terms result in the financeable situation or we have somebody come to us on a one-off or a two-off and say, "Hey, look. We'd like three or four rigs. What would it take for you to build these for us?" Then 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.

Kurt Hallead, RBC.

Hey, good morning.

Hi, Kurt.

So, you lay out, Byron, a very compelling growth case for ICD, especially on the walking omni-directional dynamics. And so, maybe as you have the opportunity and you kind of give us your view on how many omni-directional walking rigs you think will be in the marketplace within the course of the next 12 to 18 months, and do you have that much visibility and are these major independents kind of looking at the opportunities?

So, 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 very large independent who have told us that they're going to 21-well pads as their standard development structure in the Permian. And that size of pad is going to require -- it's not going to require it. I mean you can use whatever you want to drill that. If you're going to drill it effectively and if you're going to get 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, if 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've put a couple of rigs back to work this quarter because the client was surprised to learn we could do that. And that, again, eliminated multiple days from what they thought their AFE was going to be to develop those pads. So, those are really specialized conversations and the driver is the adoption of pads.

I think this oil and gas price downturn has accelerated the internal discussion about pads across every client we're talking to. So, there were 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 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 go back to full effective utilization the soonest. I think, when you see your contracts, you can be pretty certain that across the fleet of this type of rigs that are fielded by us and all our competitors are at 80% or above and if you see day rates moving up for this asset class and not for other asset classes, 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, contract terms extend, and then, later in the year, you'll see a day rate move.

Alright. So, when we look at and try to assess the elements of the market it seems like there is a lot of circular references to how many of these assets are truly available. When you talk to some of the larger players in the business, it doesn't appear that they have walking rigs in their inventory. So, I guess my point is that this market should be tight right now, in all effective purposes, be 100% utilized. And if they're not, why do you think they're not?

You have to ask the E&Ps. I think that 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, period, as people internally restructured. I think it's been very difficult for the E&P community to go through the cost-cuttings that they've gone through. And I think a lot of them, or many of them, ceased operations or cut back, I don't want to say indiscriminately, but very broadly as they took a step back and said, "What does this mean? Where are we headed? And what are our plans going forward?"

You have the whole issue of rigs on contract that stay on contract. And so, to the extent you've got a rig that isn't a walking rig that's on contract and you've got a substantial payment penalty you're going to have to incur to drop it to get a more productive rig, you probably are going to run that contract out.

You have got subcontracting that went on where you could take -- people would take a rig a $25,000 a day day rate on a long-term contract and sub it out at $10,000 a day. And so, that's not really a $10,000 a day day rate. That was an accommodation to the guy who is paying $25,000, who is now only paying $15,000 if he's got the equipment off his books. So, I think we went through a lot of that which is opaque, both to us and I think to the sell side community. And I think we're coming out the back side of that now and it will be a lot clearer as we go through 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-month contracts. I may have missed it, but what's the rate range in which these rigs could go back to work?

Mid- to high-teens, Kurt. All the conversations right now, if you're looking just at day rate and not at ancillary services, so you strip out trucking or casing, running tools, rig day rates for this type of equipment across the industry are mid- to high-teens.

Got it. Alright. Thanks, Byron.

You bet.

Daniel Burke, Johnson Rice.

Hey. Good morning, guys.

Hey.

Not too many left here, but still maybe just one, just calibrating to make sure my model is still up to speed here. How many rigs in Q3 do you have still operating on 2014-type vintage-term contracts?

It will be four-and-a-half.

Four-and-a-half, 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 you -- at that point you'll have, what, three rigs -- I guess I'm looking for some buckets here. Three rigs on spot, three idle. I mean can you kind of take me through the baskets at that point?

Do you want the third quarter or what we might see in the fourth quarter?

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

Okay. So, for the third quarter, if you go through our rigs, we've got three rigs on term contracts that will be extending through the quarter. One of those will drill 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 on standby that the term contract expires in the middle of third quarter and then that's one of the rigs that's going to go out to Haynesville. We've got three rigs operating in the spot market that we expect to operate throughout the spot market. And then, we've got one rig that we expect -- it's on a standby. It's a term contract. It 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, roll into the fourth quarter under that guidance, with nine rigs earning revenue, three would go in on drilling on term contracts with one rig on a term contract earning revenue on a standby basis. We'd have the two rigs in Louisiana and we'd have three other rigs in the spot market. And then, what we don't know is we're in conversations for three other rigs that possibly could -- something could happen where they could reactivate late in the third quarter of during the fourth quarter. And we're just going to have to wait and see.

Okay. That's --

Look; if oil prices stay at $50 or above, by the end of the fourth quarter we'd probably one or two rigs that aren't working.

That's helpful, Byron. And then, I guess we've gotten comfortable with the two rigs you have out in West Texas that have been kind of rolling well to well spot. But any early comments on the performance of the conversion? It sounds like you guys expect that one to stay active. I think it's in something of a spot situation.

Both those contracts were just extended.

Okay. Okay. 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 a 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 system and then it's different fluid ends on the pumps. So, eventually the entire fleet. Right now, we've got eight and, again, as these rigs come back, they're 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 PSIs in that incremental CapEx guidance.

The issue is that the length of the laterals we're drilling results in a fluid pressure loss through the drill pipe across the motor, such that, in order to have enough hydraulic horsepower at the bit face and the 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. You're not running at 7,500 PSI. It may be 6,000 PSI or the low 6,000s, but it's above 5,000 PSI, and you need a safety factor. So that's what's driving these changes in the industry to 7,500 PSI surface systems.

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

(Operator Instructions). Rob MacKenzie, Iberia Capital.

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

Yes. That's just going to be -- the working capital is just you're putting the rig back to work and you're not getting payables, receivables. Most of the expenses are payroll-related, over half, and you're paying that right away. You don't get paid for, say, 60 days after you invoiced a customer. So, that's just something we're going to have -- 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 of reactivation costs. What would that number be? And you also said kind of full utilization by the end of the first half of 2017. If we were going to 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 costs and that's really our guys going in and recommissioning the rig, replacing kind of some of the rubber parts and things like that, and all that good stuff. Then, 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 today to eight at the end of the quarter. The people are available. It's just how we stage them. It costs money.

So, going forward, up to $250,000 for each idle rig that goes back out to work. Whether we have that level of crew staging costs is going to depend on how rapidly the rigs come back. If they come back very quickly then, in those quarters, it's going to be -- it could hit the quarter pretty hard. And we'll just have to see how the fourth quarter plays out and when these rigs come back to work.

Right. So, to Byron's latest comment, having conversations with three other rigs for 3Q or 4Q, 4Q could be quite a working capital build that would then reverse once those rigs 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 we just don't know the answer to that yet.

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

You know 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 targeted four-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 a 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 share. A new market is developing and the industry is filling it. And, in order to have -- we need to have rigs available so that our marketing and business development people can talk to clients about delivery dates relative to their requirements.

So, once we got term, adequate term, I think we would probably engage in those discussions and day rates at $20,000 or above I think would get us where we needed to get to. But, certainly we wouldn't be building rigs with the expectation of that as a run rate. Our expectation would be that this segment of the market is returning to full effective utilization, multi-year contracts, and much higher day rates. And if that was not our expectation, we'd have to temper this a little bit. But, right now, that's how we expect this to unfold.

Okay. And then to 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 it 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 the red lines, then we'd be back to regular six-month delivery cycles. It's not harder. It's just different.

Yes. Okay, thank you. I'll turn it back.

Mark Kelley, FBR Capital Markets.

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

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

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

Brian Uhlmer, GMP Securities.

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

Eight.

Eight, okay.

There's eight and then our CapEx guidance, that assumes we're bringing in kind of the equipment to add a ninth.

Got it, okay. A second question. After Schlumberger purchased Omron, does that have any effect on you, will it have an effect on new build, or your systems that you're using? Or how should we look at that risk?

Well, actually we 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 Omron systems. I suspect that we're in a position now, which is actually helpful vis a vis Schlumberger. To the extent Schlumberger contracts rigs, everything they're 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 lose some of the surface work and early work to spudder rigs or do you not see that as a risk?

I think they're going to use spudders if that's what you're talking about. We don't do that.

You don't do -- okay. That's it. Thank you.

You bet.

(Operator Instructions). Matthew Johnston, Nomura.

Hey. Good morning, gentlemen.

Hi, Matt.

Hey.

Just a quick question on your OpEx guidance. Pretty impressive that you're looking a little bit flat at the rig level, 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-burdened component drops a little bit because we're spreading our fixed cost over a larger asset base. So, if you take a look at what gets allocated to the rigs, it's health, safety and environment, it's rig maintenance. And we won't be adding people or if we add people it will be very incremental. And so, that reported cost should come down. Phil, do you want to --?

Yes. I think we're comfortable; when we get back to full effective utilization, we get out of these standby situations that we're in, and those rigs are activating and we're back. We think our fully-burdened OpEx costs in the $12,500 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 for me.

And, ladies and gentlemen, this concludes our question and answer session. I would 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've received today.

We're excited about a 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 maintained 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 and we thank you all for attending today's presentation. You may now disconnect your lines and have a wonderful day.