Welcome to the Independence Contract Drilling Second Quarter 2017 Earnings Conference Call. [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 second 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 and 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 on -- during this 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 the definitions of our non-GAAP measures. With that, I'll turn it over to Byron for opening remarks.

Thank you, Philip. Good morning, everyone and thank you for joining us today. This morning, I will review ICD's second quarter 2017 operations and update our outlook for the remainder of the year. Philip will provide details on our second quarter financials and then we will take questions from call participants. ICD's second quarter built on the strength of the first quarter. Our pad-optimal 200 Series fleet was fully contracted in an environment of rapidly improving day rates for pad-optimal class rigs. We completed our final 100 Series conversion and contracted the newly-christened Rig 218 for 2 years. Day rates moved higher from the middle to high-teen range we experienced during the first quarter. We believe that the market has now stabilized in the high-teen low $20,000 range. We're currently in the final stage of contracting a rig in the low 20s to an international major, a new customer. Meeting the contracting requirements of the majors is another example of ICD's growing presence among the most demanding customer base in the industry. Our fleet continued to print industry-leading uptime and over the past 12 months, ICD's fleet wide uptime exceeded 98%. The use of pad drilling continues to expand as our customers migrate to larger, more complex pads as part of the economic optimization of their operations. E&P operators have promised growth and profitability at commodity price thresholds that we believe can only be provided through complex pad drilling programs, utilizing the most efficient pad-optimal rigs. Along with many in the analyst community, we expect the North American rig count to decline. However, the rigs that drop will be those operating at the margin, employed by smaller operators with the highest production costs who don't have critical mass to pay anything but the highest marginal rates for everything tied to completion and production. That dynamic does not impact ICD. While others may see a tapping on the brakes, at ICD, we currently see sustained steady demand growth for pad-optimal class rigs by operators with industry-leading cost structures, the type of operator represented in ICD's client list. Although we expect to see the U.S. land rig count decline for a protracted period, the quality of the remaining North American fleet will continue to ramp through a continuation of the rig replacement cycle. Much higher quality and more efficient rigs will replace older and less functional upgraded units. The resulting smaller U.S. fleet will be much more efficient, will drill more wells per rig year and lower development capital intensity in the context of a well-supported pad drilling program. During the second quarter, we signed term contracts, adding 1,371 days of backlog. Demand for our ICD's ShaleDriller fleet remains steady, with inquiry through year-end 2017 exceeding ICD rig availability. Additional demand is in the discussion phase for long term contracts commencing during the first half of 2018. Our fleet is well positioned with regard to capturing improving day rates. We have strategically implemented a staggered term contract exploration matrix throughout 2017 and early 2018, supporting a process that allows ICD to capture day rate improvements as contracts roll in re-rate while generating a growing backlog supportive of expansion of our ABL. From a fleet average perspective, at the end of the third quarter, ICD's legacy day rate contracts almost completely rolled to the new day rate environment. ICD's balance sheet is in good shape. Our capital spending plans for the remainder of 2017 total $4.4 million. Philip will provide additional detail on that spend later in the call. This is easily supported by our ABL against a commitment of $85 million and a borrowing base approaching $100 million. At June 30, we had net debt of $33.5 million. Recent term contracts have provided additional forward-looking cushion and ABL availability at second quarter end stood at $46 million. This provides ICD with the liquidities to strategically complete our current capital plan as well as quickly complete the 2 half built 200 Series rigs in inventory at a time of our choosing. In conclusion, during the past 12 months, we have high graded and expanded our customer base and the geographic reach of our operations. In the second quarter, almost our entire fleet was drilling on pads. Six rigs are operating using dual-fuel inputs. I expect almost the entire fleet to begin using our dual-fuel capabilities by the end of the year. ICD has a solid Haynesville presence. However, the Permian remains the focus of most of our fleet. The economically driven and rapidly growing use of pads in the Permian has increased demand for pad-optimal rigs in the basin. Wells have become more complex as well, with average laterals of 7,500 feet and well TDs of almost 19,000 feet. I expect the trend to longer laterals to continue. As I noted earlier, ICD continues to add new customers, including an international major and provide additional equipment to existing customers. Our expanding backlog of term contracts with a very demanding customer base illustrates the industry's high regard for ICD's rigs, staff and operations. With that, I'll turn the call over to Phil.

Thank you, Byron. In the second quarter, ICD reported a net loss of $6.3 million or $0.17 per share. Excluding noncash charges associated with assets held-for-sale and other items as summarized in our press release, our adjusted net loss was $5 million or $0.13 per share. Based on 1,111 revenue days in the second quarter, a 4% sequential increase from the first quarter, total revenue was $21.3 million, including pass-through revenue of $1.1 million. Average revenue per day of $18,201 came in slightly higher than our guidance. I want to point out that approximately 20% of our second quarter revenue days earned under higher day rate legacy contracts compared to 34% during the first quarter of 2017 and there were no standby-without-crew revenue days during the quarter. Cost per day of $12,926, excluding reactivation costs, came in higher than our prior guidance due to higher repair and maintenance expenses and new hire mentoring costs we discussed on the first quarter call. During the second quarter, we reactivated our last idle rig. Reactivation cost totaled $400,000 or $0.01 per share. Gross margin per operating day, excluding reactivation and rig construction expenses, was $5,275 which was in line with our prior guidance. Margins during the quarter declined 12% sequentially, principally due to a decrease in revenue days from higher day rate legacy contracts. SG&A expenses were $3.4 million, including $1.2 million of noncash compensation expense. Cash SG&A expenses of $2.2 million declined 16% sequentially as a result of lower professional fees and incentive compensation expense and a full quarter contribution from cost reduction initiatives. Depreciation expense, interest expense and tax expense all came in line with our prior guidance. At June 30, we had net debt, excluding capitalized leases, of $33.5 million. Our borrowing base under our credit facility was $89.1 million, exceeding the $85 million of commitments under the facility. Subsequent to quarter end, we entered into an amendment to our credit facility to extend it to maturity until November 2020 and apply covenant and borrowing base changes. Pro forma for these amendments, our borrowing base at June 30 approximated $95 million. Cost outlays for capital expenditures in the quarter net of disposals was $7.7 million. Note that accounts payable at June 30 included $5.4 million associated with second quarter capital purchases. Capital expenditures for the remainder of 2017 are expected to approximate $4.4 million. We have $6.4 million of assets held-for-sale that will offset capital expenditures as proceeds from sale are realized. At June 30, our contract backlog was approximately $71 million, representing 10.4 rig years of activity. Our average day rate in backlog for the remainder of 2017 is approximately $18,200 per day and increases to almost $19,000 per day for the first quarter of 2018 and over $20,000 per day in the second quarter of 2018 as our lower day rate contracts rolled the back half of 2017 and the first quarter of 2018. As a result, we expect to realize top line revenue and margin per day improvement beginning in the fourth quarter with our fleet at 100% utilization and as lower day contracts continue to re-rate higher. Third quarter guidance. In the third quarter, we expect our rigs will generate between $1,235 and $1,245 revenue days with a revenue per day relatively flat and raising between $18,000 and $18,200 per day. Fully-burdened operating cost per day should fall between $12,700 and $12,900, including cost associated with new hire initiatives. These per day expectations exclude pass-through revenues and expenses and our cost per day also exclude rig construction expenses. We expect our margin per day to be flat to slightly up sequentially, with a range between $5,100, $5,500 per day. Rig construction expenses are expected to be approximately $400,000 during the third quarter. SG&A should approximate $3.6 million, of which $1 million will be noncash. Depreciation expense should approximate $6.6 million, interest expense should approximate $750,000 and tax expense should be flat with the second quarter. And with that, I will turn the call back over to Byron.

Thanks, Phil. Operator, at this point, would you please open the line for questions?

[Operator Instructions]. Our first question comes from Connor Lynagh with Morgan Stanley.

Just one higher level one for me. It seems like a lot of your competitors are pushing more into the software space and drilling software offerings. I'm just wondering if you could talk about what you guys are exploring on this front, what you see is advantage and disadvantages of the different systems available out there.

Sure. The current systems that we've reviewed and we've reviewed 3 or 4 of them, enable you to eliminate directional drillers from the rig and allows the computer power of the rig, coupled with a more highly trained driller, to perform all the functions of the traditional directional driller. We continue to review the software. I think it's good stuff. I think that we'll -- eventually, we'll adopt it. And we're -- but as I mentioned, we're in the review phase. So the industry is going that way and we will as well.

Our next question is from James West with Evercore ISI.

Byron, I think you're at a kind of a decision point right now with respect to ICD in your fleet. So you're sold out, pricing is moving higher, you're gaining customers, pad drilling is increasing. What point -- in the near term contracts now, at what point do you start to pull the trigger on additional newbuilds?

Higher day rates, little bit longer term, although -- we get the right day rate. We do it for a year. And either a reopening of the capital markets to us or our ability to put together an industry partnership or some sort of structure, where we had financing available to us as part of a larger rig build and a larger multiyear commitment that would probably not be on day rate but would be associated with payments and bonuses and decrements based on metrics associated with well drills. So though either or a combination of those factors, James.

Okay. And Byron, are those types of conversations, a larger package with someone that has a program that, let's say, they're not concerned about oil at 45 versus 50 versus 55? Are those conversations starting to happen at this point?

Well, if you notice and if you look at our client list, our client list is populated by people with just those attributes. And so the answer is yes. But I would note that this is -- this would be something transformational. This wouldn't be a revolutionary change. This should be an evolutionary change for the industry. And as such, that's going to have to come from the top down within the E&P community, not from mid level up. And those are the type of conversations we're having. They -- as oil prices move around and we move into the budgetary cycle, it slows things down a little bit. But I think that our larger public competitors are moving in this direction as well. I think it's inevitable, that these types of structures occur because the industry, as it's being run now and as it's been run historically, results in an inequitable split of the value creation on the service side relative to the E&P side. So long answer, we're headed in that direction. I can't time it for you.

Our next question is from Daniel Burke with Johnson Rice.

Byron, I thought I heard you say early in your commentary that you perceive the market as having now stabilized in the high-teens to the low 20s. And what are the one -- did I hear the word stabilized? And if so, were you referring to your rigs or the broader AC rig market?

Yes, you heard stabilized. As a matter of fact, since we started the call, I've been slipped a note that I referred to an international major contract that's about to be signed. We just signed it. So that's in that higher end of the range that we articulated. So I think that for pad-optimal, the pad-optimal asset class, the market is stable to improving. And the -- and that's a function of, I think, the economics and system cost reductions associated with pad-optimal equipment and the migration of much higher-quality clients to the implementation of pads and complex pads as a way to execute their drilling campaigns. So for the pad-optimal class alone, I think the market's in good shape. Slower moving rigs of any drive type are at a disadvantage in that market. And although there is a market for that, it's overpopulated and so there's margin pressure still.

Okay, great. Then one that maybe piqued my interest as well as you spoke was you talked about almost the entire fleet shifting to dual-fuel usage in the second half of the year and certainly understand the value proposition there. But is there any particular catalyst that would presumably be driving at least more than a couple of your customers you've been working with for sometime over to dual fuel here in the relatively near term?

It cuts their fuel cost in half. So they pay fuel costs. And if we can take $500 to $1,000 a day out of their spread cost, that moves the needle. And the other thing you have to remember is where we've moved pretty decisively to a manufacturing model, so big pads, complex pads, the availability of pad gas. This is just part and parcel of all the pieces coming together that result in much more efficient, lower capital intensity operations on large complex pads.

Got it. Okay. So think of the pad as the enabler of easier access to fuel gas.

Pad is the enabler and the pad is the driver of the demand for pad-optimal equipment in any oil and gas price environment. So in a way, a challenging oil and gas price environment accelerates the adoption of pads and the demand for pad-optimal equipment. So we can be in a situation of 100% utilization and steady to improving day rates in a challenged oil and gas price environment.

Got it. And then maybe just to cram one last one in. In terms of the 2 partially completed rigs that have obviously been out there for sometime, I mean can we coax out of you any more details, sort of preconditions necessary to push those projects onto the capital schedule?

They're being marketed aggressively as we speak. And as I mentioned in our prepared remarks, we see pad-optimal demand that's in excess of what we'd be able to provide. And I think the industry is at 100% and there are some availability amongst our public competitors, but I don't think it's very much. So that equipment is being marketed. And as soon as we get terms and conditions that we feel are acceptable, we'll do it. We can do it very quickly because all the long lead items are in stock. So stay tuned.

Our next question is from Kurt Hallead with RBC.

You mentioned the evolution here of a different type of contractual structure, where the land drillers are going to get paid for the efficiencies that they're helping E&Ps with. I'm familiar with, I think, one of your competitors that operates on both sides of the border where they have a contract mechanism that's basically is a floor at 18, ceiling at 30 plus about 15% or 20% performance drilling kicker that's been in place since, I think, late last year. Is that the type of contract dynamic that you're talking about? Or it's a variant to that? Or it's something completely different?

I think a variant, Kurt. I'm going to -- I'll require a floor. The provision of a floor is going to result in my having to accept a ceiling. So I think that their spread-type cash flow structure you articulated is probably what it's going to look like in the end. Efficiencies and metrics under my control are things that we'll accept. When you think about drilling a well or you think about developing a field, there's geologic risk and mechanical risk and commodity price risk. I really don't want to take commodity price risk. I don't think my shareholders are paying us to speculate in commodity prices. Geologic risk is beyond the purview of our capabilities. So I think you get down to the mechanical risk part of the equation and are there more efficient ways to divvy that up between the E&P and the service company. So I think the structures that we're looking at wouldn't per se have a commodity price piece or a geologic piece. But they would have a mechanical risk component to them.

And do you think that's something that could transpire on ICD's part before the end of the year?

I don't know. We're not the rate-limiting factor in that progression. So it depends on the speed with which the counter parties move and respond. It's -- we've been doing this now for 1.5 years. I thought we were days away from an announcement earlier in the year and it didn't happen. So I'd like not to speculate, but certainly -- again, I think the whole industry is going this way, Kurt. And sooner or later, the dam will break and then they'll probably be a wholesale move to these debt structures.

Okay. And then maybe a follow-up to the drilling algorithm and software and so on. What would that cost be for you to -- would that be an upfront cost? Would that be something that the E&P company would pay for? And then what would that cost be?

Okay. So yes, we price it into the day rate. There would be a day rate adder. From the respect of what we would pay to put it on to our system, those conversations are very wide right now from people partnering with us and giving it to us for "free" to other payment structures. So we need to settle on which system we're going to employ because we can't have multiple systems. And so there's a supplier component to that. There's also an E&P component to that because we don't want to settle on something that's good from a supply standpoint that our customers don't like. So we're trying to push both ends to meet in the middle. And once we do that, there will be an uptick to the day rate or the cost, the revenue per day associated with the addition of that system. And then there will be some structure that would -- where we would compensate the provider, but those -- there's a lot of variability how that might look like. Net-net, our margins would go up.

Got it. And then, if I may, just one more here. What day rate, cash margin and general term would you need for a newbuild?

So we'd look for -- a newbuild from scratch, a 200 Series from brand new AFEs. Is that what you're referring to?

Yes.

Something in the mid- to high 20s for at least a year or maybe 2 years. And I think we're headed there. Look at it this way, the industry has made certain statements to the investor community about wells drilled, production rates, IP, so on. If day rates don't go to newbuild day rates, the equipment to produce those outcome, it doesn't exist.

Our next question is from Matt Johnston with Nomura.

So Byron, we heard this morning from one of your larger peers that they've decided to start upgrading 1,000-horsepower rigs to what they call Tier 1 status. And I'm curious, to what extent does the continued upgrade of those types of rigs act as kind of a tethering effect on your own day rates? Or have we reached a point or are we getting close to a point where there's almost a bifurcation within the bifurcation when we all think about pad-optimal rigs?

Yes. So nothing we do would be satisfied by 1,000-horsepower rig. So that's a completely different asset class. It's not something we would ever see in a competitive bid situation. With regard -- I don't know -- then our Tier 1, I have no clue what Tier 1 is because different of our -- different drilling contractors and competitors define these markets in different ways. And so again, we define the market for pad-optimal rigs by adopting what the E&P industry has defined as pad-optimal. And I like that definition because they're the people that write the checks. So that type of equipment would not have any impact on our market. And with regard to upgrades in general, you can't upgrade rigs to pad-optimal capabilities. You can't do it. And the issue is that even the best slow-moving, skidding, what have you, rig of any drive type is a highly engineered piece of equipment that was designed to do something very well. And when you ask it to do something else, all of a sudden, you get into this do-loop of engineering trade-offs. And you wind up with center gravity problems, you wind up with flow line problems, you wind up with grasshopper and electrical problems, you wind up with backyard layout problems. And you come then with your upgraded piece of equipment to the E&P community and say, great news, I've got this upgraded piece of equipment and I'll give it to you at a discount to pad-optimal equipment, but your well spacing has to be 20 feet, your rows have to be 30 feet apart and we have to have certain geometry and you have to bury everything because we can't walk over it. And so to your point of a bifurcation within a bifurcation, there's going to a lot of that type of equipment out there. It's better than skidding equipment. But if the market is going to be small, straight pads and you're going to drive your margins probably down to cash flow breakeven because of the vast amount of equipment they'll have that capability, you go up to the true pad-optimal rigs, of which there's 3 or 4 designs out there and 3 or 4 players and we're seeing expanding day rates and so on and so forth. So I think that if you look at the physical reality of what's happening and unfolding in the market, that discussion's over.

Our next question is from Rob MacKenzie with Iberia Capital.

Actually Byron, one of my questions is kind of the opposite of that last question a little bit. Can you update us on your thinking about the potential demand drivers and the probability of a 300 Series rig, the bigger rig, more capable for pad-optimal work you've been talking about for?

Sure. So with the advent of a couple of the large E&Ps and internationals, talking about mega pads, so taking the pad model to a much, much larger level, the -- there's a trade-off. And the trade-off is that they'd like equipment that racks back more pipe, it has more service mode capacity that is more hydraulic horsepower and you need more electrical power that can walk further. And the trade-off is that type of equipment is not going to move pad to pad as quickly. In this particular situation, people don't care so much because those rigs are going to be on pads for a much longer period of time. So there is a demand for the type of equipment. It's going to probably be a subset of the pad-optimal market, but that's -- because everyone is going to have to build that type of a rig from the ground up. There's no existing equipment that looks like that. That's probably the equipment where you're going to have the most success in terms of partnerships and some of the things we discussed earlier.

Okay, makes sense. Anything -- any update on kind of potential timing for that kind of arrangement?

We have a design in the IP vault. We need to do a little bit more engineering work to get the engineering drawings done. We're ready to go. We're talking to clients they tell us they want it. And we're just going to have to get to a point where it makes sense for both types of shareholders.

Great. And then my next question is coming back to 213 and 214. I think you commented on what kind of contracting status you need for newbuilds. Could you give us the same kind of metrics for those 2 rigs ?

I think that 1 year at current day rates would get us are there and we were marketing those aggressively. And I have all the faith in the world in Chris Menefee who's our VP of Business Development, that he'll get something into the box for us.

If you signed hypothetically one of those contracts tomorrow, how long would it take you to complete the upgrade and get that rig out and running?

Four months or less.

[Operator Instructions]. This time, I'm showing no further questions, so I would like to turn the call back to Byron Dunn for any closing remarks.

Thank you. I would like to thank all of our investors and all the analysts that were on the call. Once again, I want to thank ICD's employees because those are the folk that make this all work and I look forward to talking with you all next quarter.

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