Good afternoon, and welcome to the Independence Contract Drilling Inc. First Quarter 2018 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 this event is being recorded. I would now like to turn the conference over to Philip Choyce, Executive Vice President and Chief Financial Officer. Please go ahead.

Good morning, everyone, and thank you for joining us today to discuss ICD’s first quarter 2018 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 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. Ina addition, we refer to non-GAAP measures during the call. Please refer to the earnings release and our public filings for our full reconciliation of net loss to adjusted net loss, EBITDA and adjusted EBITDA and for definitions of our non-GAAP measures. And with that, I'll turn it over to Byron for opening remarks.

Thank you, Phil. Good afternoon, and thank you for joining us today. I'll start by reviewing ICD's first quarter 2018 operations and update our outlook for the year. Phil will provide details on our first quarter financials, and then we'll take questions from call participants. In the first quarter, ICD generated record revenue and continued full utilization of our pad-optimal ShaleDriller fleet. Sequential revenue per day improvement began as several contracts rerated from cyclical lows to the current robust and improving market day rates. This is a trend we fully expect to continue throughout 2018 as older contracts rerate and new contract extensions are negotiated. I'd like to provide some additional color on this. Since the low point of the downturn, day rates on contracts we have signed have increased over 43%. And re-contracted day rates on rig roles have increased over 26% year-to-date. It is not unreasonable to expect similar percentage improvement in day rates for pad-optimal equipment over the next 12 to 18 months. Today we've reported a backlog of $52.7 million with an average day rate of $19,650 per day. However, we are at the signature state on four contract extensions that will increase our March 31 backlog to $91 million with an average day rate of $20,200 per day. These four contracts are each being extended for a year, months before their current contracts respected expiration, at day rates up over 10%, and in one case the day rate increase itself begins months before that current contract expiration. Over the remainder of 2018, with the contract expiration metrics we’ve put in place and including the effect of the four to-be-executed contracts and do build pad-optimal ShaleDriller 214 schedule to enter the fleet during the third quarter, we will have two rigs re-contracting during the second quarter, three in the third quarter and two in the fourth quarter. ICD is extremely well positioned to continue to realize revenue-per-day improvement and to continue to post backlog average day rate increases. In the first quarter, operating cost per day statistics were in line with our guidance. I expect field-level cost to decrease throughout the year. Some of this decrease will come from new contract terms, as contract renewals include more favorable cost-sharing allocations. Further improvement will be driven by initiatives put in place regarding crew utilization, staffing and field supervision. I am very pleased with the improvement in cash cost per day at the rig level already evident, especially when taken in the context of ICD’s growth. Unlike the rest of our industry, whose rig fleets and crew requirements that have actually shrunk compared to pre-downturn levels, ICD’s fleet and the number of operating personnel we have been required to recruit and train has grown substantially. We have met this unique challenge while continuing to satisfy the increasingly complex demands of our customers. In fact, during the year-to-date period, as ICD has ramped to meet fast-growing customer pad-optimal rig demand, our unscheduled downtime has run at 2% - an exceptional level in the industry and a testament to the men and women working at the rig phase as well as our operations in field maintenance teams. As I mentioned on our previous call, demand for pad-optimal land-drilling rigs is greater than the U.S. fleet can deliver and this trend is growing as our clients, the top-tier players in the shales, expand wellbore manufacturing principles and design successfully more complex pad-drilling programs. In this macro environment, ICD continues to deliver exceptional results to our customers. A good example of the value add of ShaleDriller’s advanced omnidirectional moving system was on the slate during the first quarter, where we completed a 215-foot completely diagonal walk for a customer on a single pad in only four hours. Our rig equipped with an X, Y walking system would have head to move to 200 feet in the X direction, then 60 feet in the Y direction, taking much longer period of time and a skidding system would not be capable of meeting this customer requirement. Additional value is delivered to our customer on this pad as our rigs are on operating on high line power and our moving system allows the customer to plan simultaneous operations, which they’re expecting to implement in the near future. ICD pad-optimal ShaleDriller rigs on complex pads delivered extraordinary financial results to our customers, as they move further to full wellbore manufacturing operations. It is not economically feasible to execute these extremely complex well designs by skidding upgraded X-Y walking for other legacy moving systems. So wrapping up, ICD’s fleet is a full utilization. The economic manifestation of the shortage of pad-optimal rigs has begun. Day rates and contract tenures are improving. We continue to build a strategically staggered contract backlog at higher day rates, with customers who have long-term complex wellbore manufacturing programing requiring pad-optimal equipment and we are in growth mode with the 15th shale driller on schedule to enter our fleet early to mid-third quarter. Our leadership team is reducing field cost across the board while meeting the increasing demands of our customers. With that, I'll turn the call back over to Phil.

Thank you, Byron. In the first quarter, ICD reported an adjusted net loss of $4.3 million or $0.11 per share. Based on 1,259 revenue days in the first quarter, small decrease from the fourth quarter of 2017, ICD reported record revenue of $25.6 million, including pass-through revenue of $1.6 million. Average revenue per day of $19,055 came in line with the higher end of our guidance and represented a 4% sequential increase compared to the prior quarter. Cost per day of $13,414 came in line with our guidance and was impacted by the shorter quarter and seasonal payroll taxes. Overall gross margin for operating day came in line with our prior guidance. SG&A expenses during the quarter were $3.5 million, including $650,000 of non-cash compensation expense. Cash SG&A expenses of $2.9 million increased sequentially as a result of higher incentive compensation expense compared to the prior quarter as well as typical year-end legal and accounting professional fees. Depreciation expense and interest expense came in line with our prior guidance. Tax expense was de minimis, included a small deferred tax benefit associated with the leasing on state taxes. At the end of the quarter, we had net debt excluding capitalized leases of $50.7 million. Our borrowing base on our credit facility was $103 million, exceeding the $85 million of commitments under the facility. Our capital budget for 2018 has increased slightly to $22 million. We awarded an additional drill pipe spring ahead of the recent steel tariff announcements and we’ll be adding a third pump to a rig. Cash outlays for capital expenditures in the first quarter, net of disposals, were $6.1 million of which $5.3 million related to deliveries occurring during the fourth quarter of 2017. Accounts payable at quarter-end included approximately $4.6 million relating to first quarter deliveries. At March 31, 2018, our backlog was $52.7 million. Byron mentioned four contract extensions that are at the signature stage, which will significantly increase backlog in aggregate dollars and average day rate in backlog. Second quarter guidance. We expect our rigs will again achieve full effective utilization, but small number of ideal days for rigs transitioning between customers. Revenues days range between 1,260 to 1,265 days during the quarter. Revenue per day should range between $19,300 and $19,500 per day, as we continue to realize benefits from improving day rates under contract extensions. We do not expect day rate improvements for the four pending contract extensions that Byron mentioned to kick in until the third quarter of 2018. We expect fully burdened operating cost per day to range between $13,100 and $13,300 per day. These per-day expectations exclude pass-through revenues and expenses. We expect the fully absorb all rig construction expenses into our new will during the second quarter, which is on schedule for delivery beginning in the third quarter. SG&A expenses should approximate $3.4 million, of what $70,000 will be non-cash. Depreciation expense approximate $6.7 million, interest expense should come at around $1 million and tax expense should be about $50,000 during the quarter. And with that, I will turn the call back over to Byron.

Thanks, Phil. I have no other comments. So, operator is you would open the line for questions, please?

[Operator Instructions] And our first question comes from [Taylor Zurcher with DCH]. Please go ahead.

Hey, good morning, guys. First question is just the sixteenth new build. Could you just remind us? I know you talked about it in the past how much CapEx would be required to get that rig out in the field and it sounds like number fifteen would be out there early to mid-Q3. In terms of timing for the sixteenth, if you made a decision, would it be similarly a quarter or two before you could get it out there? And then finally, what's preventing you today from making that decision? Is it a balance sheet decision or really just a mix of term and price that you're looking for that you're not quite getting today?

The rig under construction would be ready to go out at the end of June. The next rig, it’s still unclear what we're going to build and there is still some -- ambiguity is wrong word. There is some differences in what the industry thinks it needs in the next cycle of newbuilds. And until that becomes clearer, we're going to – we’ll hold off. From a cost standpoint, if we were to build a traditional ShaleDriller 200, it will be another $14 million. If we were to build a, what we call the 250 series, which would have three mud pumps, four engines, additional racking capacity. It will be couple of million dollars in addition to that. And as you pointed out, what we're doing is we're trying to match day rate, rate of return, what the industry really needs, and we want to make sure that there what we put out is going to satisfy those needs for a long period of time. So we haven’t made a decision yet, and those are the variables.

Got it. Makes sense. Second question is just on cost. If I heard you correctly, I think the Q2 cost number is going to come down slightly. You realize that there are some transitory, I think, payroll impact in Q1. But as we think about that the cost level moving forward, a lot of rigs in the Permian and the labor market tight. Is there any wage inflation realizing is to pass through cost to you embedded in that cost guidance and consequently in the dairy guidance you provided in Q2? And how should we think about that over the back half of the year?

Day rate is separate from cost. There is no cost inflation in terms of our employees at the rig level. Bear in mind that most of our – the vast majority of our employees don't come from the Permian area. We work two weeks on and two weeks off. And to the extent there was any inter-period, inter-contract wage cost increase, that's a pass-through to our customers. So our margins would not be impacted.

Understood. That's it from me.

Our next question comes from Daniel Burke with Johnson Rice. Please go ahead.

Yeah. Good morning, guys.

Hey, Daniel.

Hey. One more on cost just to stay there, I guess. Byron you alluded to potential piece of field-level cost decreases due to more favorable contract arrangements with customers. Can you quantify? Maybe what that means is I would imagine day rate escalations are more material, but to figure that [Indiscernible].

Yeah. The day rate escalation is vastly more material. When you talk about contract roles, and I'll turn this over to Phil when I get done it and quantify for you, but one of the things that happens during various contract negotiations, during the cycle is it may be that we take a day rate and embedded in the contract is -- something like that. So what we've been successful in doing is taking those things out of the system so that part of our cost structure is decreased. Another thing to remember is, sometimes when people report day rates, they include pass-throughs. And so you'll see a – where you’ll see a high 20s day rate that may include $4,000 a day in pass-throughs that will be day rates. So we avoid that when we report that to the Street. Our number is a peer number. The other thing about cost structure currently is we're looking hard at how we allocate and work with our field supervisory team. And I think there is a way we can continue to do what we’re doing and in fact improve our supervisory structure, at the same time taking a couple of hundred dollars a day out of average costs. So, Phil, if you what to see if you can quantify?

Yeah, I guess the only thing I'd add on top of that, Daniel, is in addition to the rentals, we do have some contracts where we will have sixth man on the rig that we’re not -- that our older contracts where we weren't getting compensated for that. Our contract renewals now are going to compensate for those things. And it's probably overall across our fleet when we get back to what I consider more of a normalized cost-sharing arrangements, probably several hundred dollars a day across our fleet.

Okay, great. That's helpful. Another one for you. I just wanted to reconcile a couple of comments you had on day rates. I thought I heard you say your recontracted rates are up 26% year-to-date. And then you referred to a couple -- or excuse me, four contracts where day rates will be up over 10% versus prior. Just wondering if you can maybe reconcile those two comments. What was the 26% referring to?

Okay, I'll help you as much as I can without disclosing anything that I think we don't want to disclose on our conference call. So the 26% related to the marginal rate we're signing new contracts right now versus the low we came into this year at. So that's a year-to-date improvement. The 43% number is the same calculation, but the starting point was the low point of the downturn. The 10% related to those specific contracts and the improvement in day rate just associated with them from where they were initially signed and where they're rolling to.

Okay. Got it. And then maybe last one. Maybe this is for Phillip. But in the past, whether for just a second quarter or a few quarters out, you've been able to share one of that the contracted pay rate in backlog. Maybe you could do that now. Maybe it's tough because you got this four sort of what pending contracts, but at a minimum, could you give it to us Q2, if it’s available?

No, let me kind of give you -- this will be – I’m going to give you the guidance based on those four contracts that we expect to be signed this week, later this week. So the backlog – that adjusted backlog would be $91 million. The four contracts really don’t affect the second quarter. You’re going to have an average day rate and contract there about 19,600; third quarter, 20,200. It’s also the same in the fourth quarter and then it starts going up to 20,400 in the first quarter of next year and over 20,000…

Okay. That also depends on – we’ve got some rules coming up and so what Phil gave you is status quo in the backlog. The numbers should be materially higher than that because we've got four or five rigs that we’ll re-contract during that period that’ll pull that number up.

Right. Got that. Thanks, Byron. Maybe last simple piece of that is, what are the uncommitted rig days in the $91 million backlog for Q2? Could you get two rolls, right, you said later this quarter?

Yes, uncommitted. Let me – I have to do some math here. It’s probably a rig and it's probably about one rigs worth.

Okay. That’s pretty close enough. Okay. Great. Thanks, guys. That’s what I have for now.

Thanks, Daniel.

And our next question comes from Tom Curran with B. Riley FBR. Please go ahead.

Good morning, guys.

Hey, Tom.

Byron, when it comes to the specific technical aspects of what would be the 16th rig that you’re discussing with the potential customers, could you expand upon what is the nature or the range of capabilities for the decisive specs that will determine which model you go with. What exactly is it that you're trying to clarify with customers that they're going to want that rig to be able to do and what aspects of the wellbore with those specs applied to?

Okay. So there’s two, I guess, major areas that are in discussion. One is the – I’ve said back capability of the rig. So to the extent that you're doing Wolfcamp B wells, you're targeting deeper longer laterals and we're talking to people about laterals that are extremely long. It like the ability to rack back additional pipe. And then the question is, is it 5 inches and 5.5 inch, and the – and that crosses over into how many mud pumps do you need. And the issue there is, when you've got long laterals, you want to keep – you want to be able to maintain turbulent flow in your return. So if you think about the energy in the mud system, you got to get it down to the bit, you've got to have the right hydraulic horsepower to bid phase. You're going to be turning mud motor, which requires additional hydraulic horsepower. You got to keep the bit cool. Than you have to return the cuttings to the surface, you don’t get stuck. And that requires, after all those pressure drops, the maintenance of turbulent flow characteristics throughout annual lists all the way up to home. And that then is a two pump, three pump question. Okay, when you do that, the question is what size they really need and that varies too. So every time you move one thing, several other items change, and so it's not [Indiscernible] You can’t just bolt some on and so, “Okay, you got it. There is the engineering changes that occurred throughout the system.” This is why upgrades are so difficult. So people talk about upgrading rigs and we're going make this rig walk and so on. It isn't that easy. And what's you wind up with some cases isn't really fit for purpose. So this is why -- this is where newbuilds come in. And so these discussions are vary between operator, how much pipe do they need, what kind of set-back do they need? What's the diameter of the pipe? What's the pump capacity requirement which then relates to power requirement. So that's the mix of issues.

Very helpful. Thank you for illustrating there. And then as part of this ongoing discussion with customers about what they're going to be looking forward in the next wave of innovation and enhancements. Do you find that some customers are starting to evaluate you or asking what you can do for them not only on ROP and days per well, but other Wellbore related performance metrics such as well wellbore placement or total velocity. Are they starting to expand the envelope of performance metrics?

Well. So let's take that in different steps. [Indiscernible] is a reservoir engineering issue that relates to permeability but then the degree to which interconnected cores aren't straight. So that's not something we have anything to do with and that something that reservoir engineers will take a look at. What I can deliver, what the drilling industry can deliver to our customer base is supposed a safety statistics and low unscheduled downtime. And this is why I talked about that in my prepared remarks. Rig penetrated depends heavily mud chemistry, mud maintenance, bid selection, bottom haul assembly design. And that is the per view of the ENT customer. So what we can provide for them is a safe piece of equipment that operates with the highest possible uptime and move the quickest possible between wellbores, which is why I talked about the -- move which same [Indiscernible] stays from days, and then then the rate of penetration is really up to them. So what you're alluding is more of a partnership agreement where you take on a 50- or 100-well program and those attributes, those issues would be part of that conversation. We don't have to balance sheet for that, but I think that's. I think industry is probably moving that way that's not something that we would do because you petroleum petroleum engineering team and so on to be able to make those decisions.

Got it. Very helpful answers. I appreciate it, Dunn.

Your next question is from Kurt Hallead with RBC. Please go ahead. Kurt, your line is live. You may proceed with your questions. Please?

Hey. Byron, I was curious given the challenges that are facing positive challenges that is that are facing the market right now – notably tight labor markets and so on. What is, is this going to be a major limiting factor do you think for ICD and its potential plan as you get out into 2019. And maybe a better way of asking it is how are you planning and advantage, right? And oil companies saying, “Well, look, we'd like to what we do, we’d like what we’ve already done, but we're not quite sure if you can kind of manage rigs.” I mean, are you facing – getting any pushback or whatsoever? And if so, how you can react in there?

Yeah. Short answer is no. Longer answer is we've got competitors that are for sale. We have competitors that have financial issues. And so we have no shortage of incoming relative to our needs. Where it's been difficult, and I’ve talked about this in the past, is pure entry-level people and there we're having some issues with the lack of knowledge of hydraulics, electronics, mechanics, which in the past we've typically had in the entry-level folks. So it's been a longer train period. But even that is abating now because of some of the industry dynamics of companies for sale and companies that have financial issues. So I don't see that as an issue anywhere on the horizon, Kurt.

Okay. Great. That’s great. That’s a good color. And let me apologies. I might ask you the question that might have been answered, but I didn't bargain with a lot of things this morning, as you probably know. So when you look at the prospects for your new rig and then when you look for rig that might become one of contract and then kind of rebooking, I know that there has been a lot of conversation in the industry that the requirement is now like two years for re-contracting and upgrading assets and three years for newbuild. So can you give us some insight as to how the terms are evolving for the contract expansion and new contract?

Well, we’re pushing back on three year right now. We'll see how successfully -- because it’s just – I think we are in a very substantial day rate improving market. This looks a lot like the market looked when we IPO-ed the company and day rates were 28 down the way to 30. And I'm not saying that's where they are today, but the dynamic of the market is quite similar. So we're very happy to work with one year terms. I did extend some contracts that still had three to six months on them for a year. So arguably, we went past our year – there’s sort of have been one year target of ours, but this was for a very important client we've really partnered with. And as I mentioned, the day rate increases began before those contract terminations. So there's a little bit of give and take on that. But in general, we’d look for one year term and expect day rates to continue to substantially improve through this year and next year.

Okay. Great. That's awesome. Thanks.

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

Nothing really. I want to thank all the folks on the call. I know we've got some investors along with the analysts community. We thank you for your support. We look forward to speaking with you on our next conference call.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.