Good day, and welcome to the Independence Contract Drilling First Quarter 2017 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. Please go ahead, sir.

Good morning, everyone, and thank you for joining us today to discuss ICD's first quarter 2017 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 filed 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 adjusted net loss, EBITDA and adjusted EBITDA, and for our definitions of our non-GAAP measures. With that, I'll turn it over to Byron for opening remarks.

Thank you, Phil. Good morning, everyone, and thanks for joining us today. This morning I'll review ICD's first quarter 2017 operations and follow with an update on what we anticipate during the balance of the year. Phil will provide details on our first quarter financials and then we'll take questions from call participants. The first quarter of 2017 marked the continuation of a strong recovery in demand for pad-optimal rigs. In the quarter, ICD's fleet of 200 Series rigs was fully contracted. We commenced completion work on our final 100 Series conversion and generated adjusted EBITDA of $2.6 million. The last 100 Series to 200 Series conversion will be deployed during the third quarter of 2017 on a multi-year contract in the Permian. Our fleet continued to create industry-leading up-time and over the past 12 months, ICD's fleet wide up-time exceeded 98.5%. As our customers continue to migrate to larger more complex pads, ICD ShaleDrillers remain the rig of choice and all our rigs are scheduled for multi-well pad drilling applications. During 2016, we restructured ICD, right-sized our senior management team and reduced our SG&A and cost base across rig construction, field and support operations. As a result, we eliminated approximately $5 million of SG&A and fixed construction overhead costs from the Company when compared to our 2015 cost structure. The first quarter 2017 captured a full quarter of these restructuring benefits, which after normalizing for market-driven incentive compensation costs and new hire and training costs reflected a 22% decrease in combined SG&A and construction overhead expenses compared to the prior year quarter. During the first quarter, we received inquiries from multi-rig packages with proposed tenders of a year or longer. As we discussed on previous calls, this signals a tightening of the market for pad-optimal rigs and sets the stage for upward pressure on day rates. We're seeing this dynamic play out in our current market contract negotiations with rate discussions moving from the mid-teens to high-teens range to the high-teen to $20,000 range. From a fleet average perspective, by the end of the third quarter, our legacy day rate contracts will have almost completely rolled to the new day rate environment, but we still expect to see a positive quarter-on-quarter EBITDA incremental beginning in the second quarter of this year. ICD's fleet is well-positioned with regard to forward day rate capture with recent contract signings and full effective fleet utilization. We have strategically implemented a staggered term contract exploration matrix throughout 2017 and early 2018, providing a process that allows ICD to capture day rate improvement as contracts roll and rerate while generating a growing backlog of - supportive of the expansion of our ABL and the internal funding of future rig build. Since last quarter's call and commencement of the final 100 Series conversion, our projected 2017 capital spend has increased from $14 million to $22 million. Recent term contracts have provided additional forward-looking cushion and ABL availability at first quarter end stood at $48 million. This provides ICD with the liquidity to strategically complete our current capital plan as well as opportunistically complete the two remaining 200 Series rigs, for which we have sunk approximately half the new build costs. During 2016, we streamlined our field operations, eliminating costs such that our fully burdened operating costs per day should run around $12,600 per day during 2017. This is slightly higher than previous estimates and reflects an expanded training cycle for new hires. As I mentioned on the year-end conference call, robust utilization of ICD equipment through the downturn allowed us to keep our most talented and experienced people, however many less experienced rig workers left the industry during the downturn and current base hires are to a great degree completely new entrants to the industry. And as such, they'll require a longer training period than we've experienced to date. During the past 12 months, we expanded and solidified our customer base and the geographic reach of our operations. Although the Permian remains the focus of most of our rigs we now have rigs operating simultaneously in three of our four target market regions, the Permian, Eagle Ford and Haynesville. We continue to add new customers and provide additional equipment to existing customers, all large publicly-traded or private E&P firms that are well capitalized, have aggressive complex pad drilling growth plans, paper quality and drill-through cycles. Our expanding backlog of term contracts with these customers illustrates their high regard for ICD's rigs, staff and operations. From time-to-time, I've been asked by investors what our view is or what's changing in the North American land contract drilling industry? And I'd like to take a moment today and provide a brief review of what we think current market trends in the industry are. Overall, we believe the 2017 marks a new upcycle and this new cycle will be sustained, but will manifest vastly differently from previous cycles. Rather than a simple supply-demand cyclical swing where the industry continues to carry on as before once balance is restored, we believe this cycle is driven by technological innovation across all facets of the oil and gas industry and will require that the industry work fundamentally differently, not only in the future, but today. In short, we believe that to survive the industry participants must work differently and smarter, not just harder and not in the old way. One of the manifestations of working smarter in the North American land drilling industry is the industry's adoption of large pads moving to mega pads and employing a manufacturing model to the construction of high quality, long lateral, and completable wellbores. The accompanying broad change in location design, reservoir/production engineering and the application of omni-directional walking pad-optimal rigs allows a very short cycle just-in-time approach to clients' production curves and acceleration of production, better control of working capital and a dramatic decrease in full cycle spread costs. These changes allow innovative companies to meet financial goals in a $50 oil price environment. But we believe these changes also set the bar at an overall efficiency level, which provides for the longer-term continuation of the current commodity price regime. With the advent of mega pads, we're seeing emerging demand for a new rig specification, which we have captured in the ICD 300 Series design, 1 million pound mast, extended walk radius with a full setback of 25,000 feet of drill pipe, higher capacity mud systems, three pumps operating simultaneously. The 300 Series nicely complement ICD's ShaleDriller 200 Series and represents an additional growth opportunity for ICD. Another emerging trend we see is a drive to incorporate the AC computer-controlled rigs seamlessly into the total information ecosystem select majors and independents are putting in place. This is not a piecemeal implementation of directional drilling software or an automated pipe racking system, it is the fusion of all these separate systems; rig automation, directional drilling, real-time down-hole data and Big Data operations collection into a single engineering command-and-control IT process that will drive a further step-function reduction in oil and gas field development cost basis as well as driving further increases in well construction efficiency. I'll now hand the call over to Phil, and he will discuss our first quarter financial results in detail.

Thank you, Byron. During the first quarter, we reported a net loss of $6.3 million or $0.17 per share, excluding non-cash charges associated with our final 7,500-psi mud system upgrade and other items summarized in our press release. Our adjusted net loss was $5.3 million or $0.14 per share. Included in this net loss was approximately $700,000 or $0.02 per share of reactivation costs for 2 rigs, one of which will mobilize during the second quarter. Adjusted EBITDA, including the reactivation costs, came in at $2.6 million and was $3.3 million excluding these costs. The fleet generated 1,073 revenue days, representing a 15% sequential increase from the prior quarter. This included 69 days earned on a standby-without-crew basis. Overall, we recognized revenue $20.2 million, pass-through revenues were $1 million during the quarter. Gross margin per operating day, excluding reactivation and rig construction expenses, was $6,019. Revenue per day and margin per day during the quarter were both negatively impacted due to a force majeure event in one of our rigs operating under a legacy contract. This event will slightly impact our second quarter as well. Excluding standby basis revenues, our revenue per day would have been approximately $19,161 per day. Our fully burdened operating costs per day were $11,930 and eliminating the impact of standby days were approximately $12,639 per day. Reactivation costs during the quarter totaled $700,000. Rig construction costs that were expensed during the first quarter were $200,000 and pass-through costs were $1 million during the quarter. SG&A expenses were $3.7 million, including $1 million of non-cash compensation expense. Cash SG&A expenses of $2.7 million included new hire training costs and payroll taxes associated with incentive compensation payments and equity compensation vesting. Depreciation expense, interest expense and tax expense all came in line with our prior guidance. At March 31, we had net debt, excluding capitalized leases of $29.3 million. Our borrowing base under our credit facility was $89 million, exceeding the $85 million of commitments under the facility. Cash outlays for capital expenditures, net of disposal were $8.6 million during the quarter. This included $5.6 million of payments for equipment purchase during the prior year. Accounts payable on March 31 included $5.3 million associated with equipment purchased during the first quarter, which will flow through our cash flow statement during the second quarter. Our approved capital budget has been increased from $14.1 million to $22 million, mostly as a result of our decision to complete our final rig conversion, which is scheduled to mobilize in a multi-year contract early in the third quarter. We currently have $3.9 million of assets held-for-sale that will offset capital expenditures as proceeds from sale are realized. Our CapEx budget excludes remaining incremental costs associated with completing our last two newbuilds, for which we have finalized complete AFEs for our board to consider as market conditions continue to improve, combined incremental costs for these two newbuilds is estimated to be $22 million. At March 31, our backlog of term contracts, including the contracts signed for rig conversion was approximately $71 million. Approximately $52 million of this backlog is expected to be realized during the remainder of 2017. We entered 2017 with four legacy term contracts in place. One legacy term contract expired at the very end of the first quarter. One expires in the second quarter, and one during the third quarter of this year, and our final legacy contract continues until the middle of 2018. In the second quarter of 2017, we expect our rigs will generate between 1,110 and 1,125 revenue days, and our margin per day to range between $5,100 and $5,400 per day, with revenue per day ranging between $17,900 and $18,000 per day and cost per day ranging between $12,600 and $12,800 per day. The margin per day declined sequentially as our percentage of revenues generated from legacy contracts during the second quarter falls to 18%, compared to 34% during the first quarter. Lease per day expectations exclude pass-through revenues and expenses and our costs per day also excludes reactivation costs and rig construction expenses. Reactivation costs associated with our final idle rig that will mobilize in the second quarter are expected to be $300,000 and rig construction expenses are expected to be absorbed into our rig conversion costs and de minimis. We should expect SG&A for the second quarter to approximate $3.5 million, of which $1.2 million will be non-cash stock-based compensation, depreciation expense should approximate $6.5 million, interest expense should approximate $700,000, tax expense should be flat with the first quarter. And with that, I'll turn the call back over to Byron.

Thanks, Phil. I want to take this time to thank all of our employees for their loyalty and commitment to ICD safety culture and their exemplary execution and performance for our customers. And with that operator, would you open the line for questions?

Absolutely and thank you, we will now begin the question-and-answer session. [Operator Instructions] Today's first question comes from Rob MacKenzie of Iberia Capital. Please go ahead.

Hey thank you and congrats. Byron, I wanted to follow-up on your perspective comments about the industry. I know we talked about this a number of times, but how do you see the penetration of land rigs being in essence incorporated into the ecosystem of computer models and data et cetera? How do see that playing out in terms of penetrating the industry and is that in your mind, primarily driven by the operators or will the pushes by the likes of Schlumberger and others be affected in driving that as well?

Rob, we see this right now being driven by operators. As a result of the run rate commodity price environment we've been in, they've been through - they've taken a number of steps, all associated with efficiency and cost base and it strikes me that ours is one of the most - one of the slower industries with regard to the adoption of software and computer systems with regard to improving efficiency. So I think that's where we see it coming from. Now obviously, there are service providers who have software systems that are out that address some and in a couple of cases, all of the issues we see arising. How I see penetrating? I think I guess, we see it coming from the top down and from our view, if we are a participant in that evolution, you risk relevancy. That's just not us. That's everybody in this industry. So we're in close contact with a number of our larger operators who are moving in this direction. We have a lot of flexibility because of the design of our VFD and computer control systems. We can integrate with anyone. And so these are - I think its early stage, but I think it's very powerful and you're going to see this unfold quarter-on-quarter over the next several years.

Okay, thanks. And then specifically for ICD, it would seem that some of the drivers of that mega pads as you mentioned, manufacturing type concept would go hand-in-hand with what you guys have introduced as your 300 Series rig. Do you see kind of operator contract to build that bigger new rig that maybe slightly less mobile, maybe than a 200 Series rig, but more fit for purpose for these mega pads and time that into the software integration all at the same time?

Yes, so what we're seeing is several operators wanting to target the lower Wolfcamp horizons. And they not only want to drill deep, but they want to keep the laterals as long as the shallower horizons and that necessitates a different piece of equipment, the flow rates required to maintain turbulent flow on the backside, the hydraulic horsepower you need after all the frictional losses to turn mud motors, the power requirement, the lifting requirements. So when they start talking about those developments, they are looking for a different piece of equipment. We've had three or four operators come to us, looking for equipment spec to do that work. And to a great degree, it doesn't exist in the industry and so that lends itself to different types of conversations with the operators because no one is going to build this on spec, right? So and the real question is, you don't really need one, you need five. And how can we work together to provide that solution to you in a fashion that benefits both our shareholder basis. And to the remaining part of your question, most certainly, in the fielding of that type of equipment, you're going to incorporate a holistic software solution that not only captures rate of penetration - rate and bit, but all the information you can glean from rotary steerable downhole tools, Big Data from the rig generally and that's going to flow back to the operator. So I think the answer to that part of your question is, yes. And we'll see how this plays out because if we truly are going to be drilling on 20 well pads and greater to the Wolfcamp C, D and lower. The equipment necessarily doesn't exist. Let me also say, this is a subset of the pad optimal universe. We view this as highly complementary to the 200 Series fleet. This isn't a substitute. This is a complement and we think that we will be on the forefront of this move as well.

Great, thanks very much. And then just calling up any kind of update on where you guys stand in the process of signing contracts to reactivate to build 213, 214?

Ongoing and assuming we have something that we can announce, we will.

Okay, thanks. I'll turn it back.

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

Hey, good morning.

Hi, Kurt.

Good afternoon, and get close to afternoon I guess. Byron, I just wondered if you give us kind of an update on how you see the trends on pads and the number of wells per pad, specifically as it pertains to your opportunity set as you get through '17. Is it growing? Is it stagnating? What's your take?

Yes. So understanding that we talk to - our conversations are primarily with those types of operators because of the nature of our fleet. We see all those things. We see pads getting larger, we see wells getting deeper, and we see more adoption of pad drilling as an economic solution to the drilling campaigns of operators in our target markets, and what you'd expect in it isn't because we're selling this well is because the economics dictate. So with a very powerful economic driver, the industry is moving in that direction. And we're seeing a number of people using pads expand, we're pads expand and we're seeing wells deepen.

Okay. And then that dovetails right into the dynamics around the super sec rigs and so on. So you are in a very unique position given that you don't really have many legacy assets per se. What are you seeing from the customers' standpoint about interest in automated drilling processes and/or a potential move to even the autonomous sort of drilling processes that have been discussed in the past?

Yes. Well, in general, if you think about it, this is a dangerous profession. And to the extent you can take people out of dangerous locations on rigs, you're better off. Now it doesn't necessarily mean you're going to lower costs, because let's just say, you got a racking system. Well, if the racking system doesn't work and you have to wait three days for parts or to get it repaired or what have you, you still need to rack, so you still need people to be able to do it. So it's not clear, I think to a great degree, you can get people out of dangerous locations. It's not clear to me that - it's not as clear to me you can costs down as quickly because of the requirement for backup. And what you're talking about are bits of the bigger picture. So there is bits out there that allow you to remove the directional driller or to have the driller become a directional driller, there is bits that automate a rig, there is bits that relate to the capture of down-hole data, there is bits that relate to the capture of Big Data from the standpoint of rig operating systems. What we're looking at is the combination of all of that into systems that allow you to lower your working capital requirements, to lower your cost base, to get rig crews permanently lower. And so I think that's where the industry is evolving to. To a great degree, that's happened internationally in markets like Saudi Arabia. So I think that the model - the template exists. It's just on its way here to the States.

And then, obviously, you've been seeing - industry has had a significant increase in rig activity more than anybody industry you're otherwise would have anticipated. It's kind of a bizarre twist where stocks have been coming under pressure and oil prices have had a lid at $50. And with that oil price lid at $50 and the increasing oil services costs. Are you picking up on anything now that would suggest there is a risk to E&P appetite for rigs as again their selling price gets kind of capped out and their costs are going up? Are you picking up anything that would suggest any risk as we head into the back half of the year?

I think that there is a risk for margin. I think to the extent that suboptimal equipment has been pressed back into service because optimal equipment is at 100% utilization and you can't get it. I think that sets the stage for day rate increases for that optimal equipment, and falling off of the margin for suboptimal equipment, depending on the economics of the field, the operator and the efficiency of that particular rig. So I don't know how to play out. But I think those are the moving parts.

Thanks Byron.

You bet.

And ladies and gentlemen, our next question comes from Taylor Zurcher of Tudor, Pickering, Holt. Please go ahead.

Good morning, guys. Thanks.

Hi, how are you?

Doing well. I'm just trying to calibrate your Q2 fleet average revenue per day guidance with where you're seeing spot market rates today. And then how that consequently might flow through to your results over the back half of the year as rigs roll off contract. And so as we think about all the moving pieces there, is there any sort of guidance or help you could provide in framing where for your spot market rigs, where that average spot market rate was in Q1?

When you look at our revenue per day in Q1, there was a blend of things in there. There is rigs. There were some rigs re-priced in the first quarter. It wasn't a large number of re-pricings that occurred in the first quarter, most of that occurred late in the first quarter into the second quarter. There is contracts we signed in early fourth quarter of last year that are flowing through the first quarter of 2017 and will flow through the second quarter of 2017 as well. So when you look at the second quarter to blend of the legacy contracts, we've had higher day rates and improving day rates that were signed in the first quarter of this year, and also several contracts that were signed back in October of last year that were slightly at lower day rates than what we're seeing today, I think, Byron has mentioned on the call. We're talking about high-teens to $20,000 days to talk now. And we do have some contracts that were signed last year that we're operating under that are lower than that.

So when you look at it sequentially, what you see are legacy contracts at much higher day rates rolling off kind of one by one replaced by rig pricing at current churn rates and also rigs that had been contracted short-term last year also re-pricing at current term rates, which is why I made the comment that rolled altogether, the dynamic of this in total should result in positive EBITDA incrementals Q1 to Q2, Q2 to Q3 and so forth and that's taking all this complexity into account.

And then maybe I missed this, but for the one rig on standby has that rolled back off of standby now? Or is that rolling off contract already? Or is that soon to come up standby in Q2, I guess, I'm wondering?

That rig went off standby during the first quarter. So we're through with the standby-without crew days.

Okay. And maybe one last one from me, bit of a high-level one. Clearly, it seems like some of your competitors and really everyone has their own sort of special definition for what a super-spec rig really is. And so as we think about the differences between maybe some of your omni-directional rigs versus skidding system, are you seeing a pricing delta today at the high end AC rig with all the bells and whistles with omni-directional system versus the same rig with the skidding system? Or have you not seen that yet?

Okay. The definition of pad-optimal was established by the E&P operators. So when we formed the Company, we went to the operator community and said we believe that the general North American land fleet is not configured to economically and technically address where you are going to with your drilling operations. So what do you want? And they defined that for us. So what you've got is the couple of things out there. You've got the industry self-defining super-spec or pad capable or whatever you want to call it. Then you got the people that write the check defining what they want. And the people that write the check want omni-directional walking systems capable of walking over wellheads, 7,500 psi mud systems, dual fuel capability, 1,500 horsepower systems, fast typical moves of 48-hour or 4 working day move from pad to pad or quicker and an AC drive. At this point, the AC drive is not a differentiator. That's pad-optimal as defined by operators, I have no earthly idea what the definition is of all the different monikers I've heard swung around from the industry, self-defining fleets. So I can't answer the question other than as I have.

Okay. That makes sense. Thanks a lot.

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

Hey. Good morning, guys. Maybe a straightforward one and maybe I missed this. But Philip, could you clarify maybe how the force majeure event you mentioned affects the Q2 guide?

It doesn't affect. It's baked into the Q2 guide. It costs us about a penny in the first quarter, but it's baked into what we talked about in the guide.

Okay. Do you have clarity on when that rig returns to contracted status?

It already has. It is several weeks now.

So, Daniel, what happened was, we had hurricane force winds for a couple of days. Hurricane force wind gusts and sustained 60-mile hour winds out in the Permian. And we had one rig out there that had a full setback of pipe and the sail effect put some torsion in the mast and we just swap mast out. It was a force majeure event. It was a non-event operationally.

Okay. And thank you for that. That's helpful and that sounds like a windy day. Let's see, another one, looks like you guys, in terms of inking the Series 100 to 200 conversions to a multi-year contract here of late, is there a spread between the pricing at this point on a multi-year contract versus the spot pricing for a rig like that? Are you guys seeing that? Does that not exit at this point?

Right now, we're not seeing that much of a spot market. I think we've gone - at least in our world, we've have gone back to term discussions and the day rig guidance we've got is good, we're giving you is good. And our market has tightened up. I don't think to the extent people are looking for pad-optimal equipment, they're not looking for it on the spot market. They want to term it up because if you don't, you can't get it.

Okay. Got you. And then maybe last one just on the 300 Series, Byron, you've alluded to stacking that rig in the past. But as you kind of narrow down the specs and continuing to talk to customers about it, what type of premium in terms of capital would it cost to assemble that rig versus the Series 200 pad-optimal class?

On a run rate basis [indiscernible] learning curve $3 million.

Okay. And you were right to highlight that you wouldn't do one of these, you'd probably be building a tranche if you could find the right counterparty, the right opportunity, but I would also have to assume given its subset of industry demand where it's most applicable, you'd also be looking for a longer duration contract than you would necessarily even on a Series 200 type newbuild?

Absolutely. Yes. I don't want to call these partnerships. But we would be looking for an arrangement between us and the operator that had a longer term and had some sort of financial structure that compensated them for whatever they were giving and compensated us for what we were providing. So we would derisk that. We wouldn't go out and just build it.

Okay. Guys, that's really all I had left, but Byron thanks for those thoughts.

You bet.

And our next question today comes from Mark Kelley of FBR & Company. Please go ahead.

Thanks for taking the questions guys. I believe, you mentioned on the fourth quarter call that you weren't seeing much difference in pricing between the six-plus-month contract and the 15-plus. Had there been any changes in that regard given the new contracts that you guys inked thus far in 2017?

Day rates have gone up. You've seen a real move upward in day rates since the fourth quarter and that's why we changed our guidance range?

Okay. Great. And then in terms of just breaching the $20,000 a day mark, I guess, maybe in a more general sense, can you give us bit of a time line on how or when you can see that happening?

No. I think there is a psychological component to that as well as a financial component. If everything stays the same as it is now, that will happen, but I can't put it in a particular quarter for you.

Okay, perfect. Thanks so much guys.

And our next question is a follow-up from Rob MacKenzie of Iberia Capital. Please go ahead.

Hey. Quick question for you, either Byron or Philip. On the rig you said the legacy contract you said extended into mid-2018. Is that for rig 212?

Sounds like we talked about which rig it is. So I don't think we're going to get into which rig it was.

Thank you.

Sir, there are no further questions. I would like to turn the conference back over to the management team for any final remarks.

Well, once again, I'd like to thank all of our investors. We take our relationship with you very personally. The management team is focused on providing the best possible financial results for our investor community, and we look forward to speaking with you again at the end of the second 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.