Byron Dunn - CEO Phil Choyce - SVP & CFO Ed Jacob - President & COO

Rob MacKenzie - IBERIA Capital Daniel Burke - Johnson Rice George O'Leary - Tudor, Pickering, Holt & Company Thomas Curran - FBR

Good morning, and welcome to the Independence Contract Drilling’s 2015 First Quarter Conference Call. Just a reminder, today’s call is being recorded. At this time, all participants are in a listen-only mode. [Operator Instructions]. A brief question-and-answer session will follow the formal presentation. At this time, for opening remarks and introductions, I would like to turn the call over to Phil Choyce, Senior Vice President and Chief Financial Officer of Independence Contract Drilling.

Good morning, everyone and thank you all for joining us today to discuss ICD’s first quarter 2015 results. With me today is Byron Dunn, Chief Executive Officer of Independence Contract Drilling; and Ed Jacob, President and Chief Operating 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. Additionally, 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 for definitions of our other non-GAAP measures. With that, I’ll turn the call over to Byron for opening remarks.

Thanks, Philip. Good morning everyone and thank you all for joining us today. Following our typical format, I will review ICD’s first quarter operations and follow with thoughts on what we expect during the second quarter and the rest of the year. Phil will discuss financial highlights and then we will take question from call participants. The first quarter came is pretty much in line with the guidance we provided on our fourth quarter 2014 call. We ended the first quarter with one 100 Series rig stacked and the rest of our fleet either working or on standby with all the rigs contributing the margins we anticipated. We added a new customer during the quarter, a significant player in the Permian, and successfully renewed an expiring contract in a well-to-well basis. Our operational performance remains strong and we maintained operational uptime during the quarter exceeding 98%. During the quarter, we completed the contraction of our 10th and 11th ShaleDriller and both began earning standby rates while the customer determine the location and timing for each rig's initial deployment. Standby rates are lower than contract day rates and after subtracting standby costs, generate margins in line with those aren’t well drilling. Because of the rigs operating on a standby basis during the quarter, our top line revenue numbers declined sequentially compared to the prior quarter, while our rig level margins remained intact. Our costs also came in line with our expectations. We incurred some incremental cost associated with the stacking of one idle rig during the quarter and we also began account accruing incremental ad valorem taxes for the first time on rigs constructed last year, which increased our fully burdened cost per day. On a run rate basis, the cash operating costs of our operating rigs was flat with the prior quarter. Since we have adopted a modular manufacturing model, and remember that means that the crew assigned to operate a new build rig built that rig, our headcount has declined in line with the reduction in rig delivery tempo while we maintain our ability to rapidly ramp production when market conditions improve. As we mentioned on the fourth quarter call, we plan to deliver three new built ShaleDrillers rigs 210 and 211 and 212 during 2015 all on long-term contract and have deferred for new construction ShaleDrillers into 2016. Both rig 210 and 211 were completed during the first quarter and began earning revenue on a standby basis. From a cost control perspective, as I noted, our field and manufacturing headcount, they actually track activity. We have a hiring freeze for corporate and support departments. And we are closely monitoring and evaluating our cost structure weekly. Some second quarter guidance. During May, I anticipate that rig 103, which has been working on a term contract, will be released following completion of that contract and will be mobilized back to Huston where we plan to retrofit it with a 200 Series substructure and omni-directional walking system. We also have three 200 Series rigs that have contracts expiring during the second quarter or are currently operating on a well-to-well basis. We’ve signed a multi-well contract for one of these rigs that will keep it substantially utilized through the second quarter. Of the two remaining ShaleDrillers with contract expiration, one has been released and another is expected to be released following the completion of its current well. We are marketing these two 200 Series rigs and expect to find work for them at spot rates. As we discussed on our last conference call, there is no developed spot or term market for rigs at this point, but we’ve seen some coalescing of short- term day rates in the $17,000 to $20,000 per day range for pad optimal equipment depending on application. On a macro level, as we progress to 2015 and into 2016, we believe that the use of pads to optimize operators' field development economics will continue to grow as will the well bore intensity of newer pads. The compelling economics of pad development should drive the demand and utilization for pad optimal equipment early and even in a modest recovery. Given that, we think the current downturn in demand for pad optimal rigs bottoms during the third quarter, flattens in the year end, and begins to recover in 2016. It’s important to note that I am not referring to AC rigs in this demand analysis, but pad optimal rigs as defined by operators. Pad optimal rigs are not just AC driven. At this point, in the rig replacement cycle AC is a given and not at distinguishing characteristic. Rather pad optimal rigs have six specific characteristics that define them as the equipment of choice for pad development and a well bore manufacturing model. Those characteristics are 1500 horse power, dual fuel capabilities, a 7500 PSI mud system for long laterals. They are safe by design and capable of fast conventional moves, four days released to spud with minimized rig-related loads. They have omni-directional walking systems capable of rapidly adjusting to mis-aligned wellbores and self-leveling the rig on slope pads, as well as walking over raised well heads. And finally, they have AC drives. Rigs with these characteristics will be first to achieve a 100% effective utilization and a recovery. Equipment does not meet these characteristics will fill the market niche previously occupied by SCR equipment and return to work on a slower tempo than pad optimal rigs and even in a recovery, we believe that SCR mechanical equipment regardless of moving system will generally be retired. With, that I’ll hand the call back to Phil to discuss first quarter financial results and second quarter 2015 guidance.

Thank you, Byron, and thanks everyone for joining us today. During the first quarter, we reported net income of $900,000 or $0.03 per share, excluding two items that were unrelated to our operations. To summarize the non-operating items that affected our quarter, first, we recorded net income aggregating $800,000 or $0.04 per share net of tax, relating to the recognition of insurance recoveries offset by additional impairment expense in the quarter. Second, we recorded a net loss on disposition of certain decommission in crew quarters aggregating $400,000 or $0.1 per share net of tax. Now, move on to the operating results for the quarter. We ended the first quarter with 951 revenue days representing a 3% sequential increase compared to the fourth quarter of 2014. On an absolute basis, we recognized revenue of $22.3 million compared to $23 million in the first quarter of 2014. The sequential decline in revenues is attributable to rigs that we’re learning standby rigs during the first quarter. As Byron notes, standby rates preserver margin will reduce our top line and revenue per day operating specific and drives the negative sequential comparison versus the fourth quarter. Moving on to our operating cost, we recognize $3.1 million during the first quarter compared to $12.7 million sequentially representing a 3% increase. On a per day basis, our reported operating costs during the first quarter were $13,035 per day. Our cost per day statistics benefited from a few rigs that earned revenue on a standby basis that contributed revenues equal to the contract margins, but did not accrue operating cost. Excluding those revenue days, our fully burned operating cost per day was in the range of $13,700 per day and in line with our cost guidance for the quarter. It’s important to note that our run rate cash cost per day at the rig level remain in line with the prior quarter and the sequential increase in fully-burdened operating cost per day was not the result of increases in rig-level cost. The material items that increased our reported operating cost per day in the first quarter with the following. We began accruing incremental ad valorem taxes this year on rigs constructed last year. We also incur costs associated with stacking of our one idle rig during the quarter. And finally, we experienced an unusually high level of repairs on one of our drilling rigs during the quarter. Although these repairs did not result in rig downtime, it did increase our reported operating cost per day. During the second quarter and the remainder of 2015, I expect a fully-burdened reported operating cost to run between $13,000 and $14,000 per day perhaps higher depending upon the dynamics during the quarter, although our rig level run-rate cost for operating rigs is expected to remain flat. On a margin per day basis, we recognized $9,747 per day during the first quarter in line with our guidance with a sequential decline in margin being entirely related to the cost items I just outlined. During the quarter, SG&A expenses were $3.8 million of which $900,000 related to non-cash stock-based compensation. Sequentially, these costs decreased 14% as a result of reduced executive compensation. On taxes, we’re currently forecasting a negative tax rate for the year of 12.5%, which result in our recording a tax benefit during the quarter. All of this resulted in us realizing adjusted EBITDA of $6.3 million during the quarter. At March 31, we had cash on hand of $11 million and $35.9 million of debt drawn on our $155 million revolving credit facility. Our borrowing base under the credit facility at March 31 was approximately $124 million and our availability under the credit facility was approximately $88 million, but facility does not mature until 2018. During the quarter, our capital expenditures net of insurance recoveries were approximately $26 million, primarily related to the completion of 12th and 13th ShaleDriller rigs as well as continue construction of our 14th rig, which is scheduled for completion during the third quarter of this year. Overall, our 2015 capital budget has not changed. We expect our total CapEx for the year to be in the range of $54 million, including approximately $13 million allocated to upgrade our 200 Series rig or begin construction of a 15th ShaleDriller rig. Now, I want to turn to our outlook for the second quarter. In the current operating environment, we would expect that our revenue days in the second quarter will range between 910 and 930 days. We expect our margin per day for these revenue days to be in the range of $9,250 to $10,000 per day. We also expect to incur incremental operating cost during the quarter associated with mobilizing and crewing rigs that currently are on a standby without crew basis, an additional cost associated with any rigs, which may be idle during the quarter. This cost could impact the second quarter in the range of $0.02 to $0.04 per share. On corporate level items, we expect our SG&A cost to remain generally in line with the first quarter. We expect our depreciation expense to increase in the second quarter in the range of $500,000 compared to the first quarter associated with depreciation on new rigs and change in useful life on certain items. And we expect our interest expense during the quarter to be in the range of $600,000 to $700,000. And with that, I will turn the call back over to Byron.

Thank you, Phil, and thanks to everyone for joining us today. The first quarter was challenging to the macro volatility, but the leadership team and employees of ICD have done a great job managing the business for our shareholders. We are all focused on keeping the ICD ShaleDriller fleet working at the highest level of excellence and at the best rates possible, and like all of you, for actively looking forward to a market recovery. Operator, with that, I’ll turn it back over to you and we’ll take questions.

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

I had a question for you, Phil or Byron, on your revenue day guidance for Q2. 910 to 930 revenue days seems to be assuming that everything except rig 101 and 103 probably stays working. Is that correct?

No, that wouldn’t be correct.

So in that number, are your assumptions that 101 stays stacked, 103 is in the yard, and that the -- one of the 200 Series rigs goes idle? Is that fair?

We have one -- we assume some of our rigs don’t operate until the second quarter -- until the third quarter.

Rob, we have a couple of rigs at around standby and we anticipate that at least of them returns to work. So there is a mix of things happening. You’ve got 103 probably coming down; I don’t know that for a fact. I think it seems likely as I mentioned. We’ve got standby rigs going back to work and we have a couple of chartered rigs coming back to us. But the timing is a little bit tricky as well. So when you blend all that together, you get the guidance in terms of days that Phil gave you.

Can you guys comment a little bit on the outlook for the couple 200 Series rigs that are rolling off contracts? How are you in terms of conversations with customers? What does the prospects look like for putting those back to work?

Yes. Ed is very close to that, I'm going to have Ed answer the questions regarding utilization and day rates in this environment.

Good morning, Rob. What we have on, of course, 202, we’ll be going back to our, 204 is one that is recently was released, and we anticipate 201 will be released by the end of the quarter as well. It’s hard to predict what the possibilities are going forward. I will say this that we have numerous conversations that are ongoing with customers. And as a result, if those come to fruition or at least some of those come to fruition, I feel confident that we can get one rig back to work by the end of the quarter, but probably both of them by the early beginning of the third quarter. Let me add this, the market is still very, very fluid. There is really isn’t any spot market out there, but I would say that we’re gaining in a lot of confidence in what we’re hearing from our customers relative to what they anticipate their activity to be in the second half of the year.

Right. And I guess the follow on that I would have there, Ed, would be notwithstanding activity levels, right? I would think that due to -- I think Byron's earlier point that as older rigs, be it less capable AC rigs or SCR rigs roll off, there would be people looking to trade up to better quality rigs, correct?

That is correct. That is correct. And we feel very confident in our position and the successes that we have enjoyed over the past 18 months to 2 years in how we’ve been able to compete with the top-end competitors that we believe - we’re confident that we'll do very well in the second half of the year.

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

I just want to make sure I heard Ed's comment correctly then. So by the time we get to sort of start of Q3 2015, the internal expectation would be then that all of the 200 Series rigs would be, I guess, contracted whether on standby or working, is that right? Am I counting my rigs correctly?

Well, I’m not going to say that I guarantee it, but I am confident that we’re seeing that by the beginning of the second quarter -- by the beginning o the third quarter, we’ll have those rigs contracted. A lot of this is really dependent on how much capital do our customers have remaining for this year and how -- when they’re going to deploy it. I mean we may very well have something, a contract signed and then maybe a two weeks span in there before the rig actually mobilizes. So if we don’t start getting those contracts signed until the second week of the third quarter and then takes us two weeks to mobilize, we just lost a third of the third quarter. So we’re dealing with a lot of variables here. I am just confident that we can get those two rigs contracted. And that’s what we’re betting on. We’re not -- in the case of the 100 Series, we preserved it for long term and these two 200 Series, we’re betting that we can get them back to work in a relatively short period of time.

That’s helpful.

Both those 200 Series rigs will be upgraded when it’s appropriate. Because, again, what you find is, you need those six characteristics I outlined to really play at the top end of the competitive curve. So you’re going to expect to see those rigs upgraded as well.

That’s helpful. Byron, it was also helpful to hear you map out that range of day rates, again, specifically, for pad optimal equipment at the upper end of the market. When you combine that day rate range with the expectation you all share that for those rigs, the bottom will kind of approach in Q3, is that close enough that the $17,000 to $20,000 a day range should be sticky? Or do you see the potential for that to dip a little lower between now and finding that market bottom for pad optimal rigs?

It could be all over the place. Again, as Ed mentioned, there is no developed market per se, so we’re trying to give you a range that we’ll stay within, but I wouldn’t try to peg it anywhere in that range. Ed?

I think all of us, all of us being all of ICD and our competitors, really we’re taking a historical guess at where we believe the spot market is going to be for these rigs. If we had a pretty good feel of what’s the rig count that’s going to be lost over the next 60 days and how many AC rigs are going to be -- are we going to be competing with, I think we’ve a better -- all of us would have a better handle on what is the floor for the spot market going down. Right now, based on what we see, we believe the guidance that Byron laid out in this comments is a really good estimate, forecast of where we see the spot market when it starts becoming more active.

That’s helpful. And to cram one more in and just a simpler one. Philip, I wanted to clarify one thing, the $0.02 to $0.04 a share you highlighted for sort of incremental costs for rigs on standby going idle, was that incremental to the $13,000 to $14,000 OpEx baseline, I assume?

Yes. That would be incremental to -- it would be included on our operating cost, but it’s unusual for the quarter and it relates to -- we have two rigs on standby with our crew. One we’ve been notified will mobilize during the quarter, another one we expect to mobilize by the end of the quarter. We’ll have to crew those rigs up, which is a little unusual situation for us. There is going to be cost associated with that. And then we do, depending on what happens with these 200 Series rigs, we’ll have some incremental costs associated with those rigs if they’re idle for the remainder of the quarter.

Daniel, this is Byron. I think the important thing to recognize is that the cash cost in the field has not going up. So as you model us going forward, your historical assumptions about rig level margins given the day rate cash operating cost spread is accurate. What we’ll do next quarter better is breakout for you the events that are happening in the quarter specific to the quarter that are not run-rate related. So there has been no step function increase in our cost structure. There has been costs that are classified as operating in the quarter that relate to some of the events Phil articulated. So we’ll break those up for you separately as we go forward.

[Operator Instructions]. The next question comes from George O'Leary of Tudor, Pickering, Holt and Company. Please go ahead. George O'Leary: Again, as already mentioned, helpful color on the rates that you guys are anticipating or maybe formulating in the spot market. I'm just curious, the rigs that have rolled off contract and are doing this kind of more well-to-well work, is there any duration to that work? Or is it really just picking up onesie-twosie type well drilling work?

That would be -- I wouldn’t say its onesie, but I would say its twosie and more. Typically, the operator will go two, three up to four wells, and that’s really typical historically, that’s what we’ve seen when we come out of these market corrections. And that’s really a good indicator, for me, as to the health of the market going forward is when we start seeing the well, the well contracts go from two and three to four to six, that’s when you start seeing six month to one year terms come in the play.

George, the other thing to recognize is just because we picked up two or four well contract, that doesn’t mean that’s all the particular operator has. They’re trying to maintain optionality on their side. And we very well could just roll forward on that basis with that particular operator. George O'Leary: Okay, that’s very helpful. And then maybe following onto that, do you guys have any -- you picked up a new customer on the quarter, any discussions with other customers that fall outside of your traditional partners, and any potentially new geographic markets that you're maybe looking to explore?

Let me give you some color then Ed can give you some detail. I’ve been very pleased in that we’re having conversations with almost all of the major E&P operators in our target markets. Our -- these conversations have expanded, I think, dramatically. And I think we’ve the ability and the track record now to work with any of them. So that’s been very -- I think it’s very positive. Ed, some detail.

I think those conversations, George, have expanded to not only our existing customers, which to me, that is healthy. That means we must be doing something right when we continue to have activity for repeat business. But also as a result of what our people are doing in the field, and really all across the company and their execution, that has enabled us to enter into conversations with some large integrated oil companies that were always on our wish list and now, we’re beginning to have the performance and capability to gain their interest as well. So I would say that our conversations are across mostly all publicly traded E&Ps, but predominantly the larger ones. George O'Leary: Okay, great. And then maybe I can sneak in one more, if I could. As you're having these discussions with customers, are you actually having discussions where it seems like your rigs may go in and replace lesser capable rigs? Or does it seem like some of these customers are actually planning on adding incremental rigs maybe in the back half of 2015?

I would say, both.

The next question comes from Thomas Curran of FBR. Please go ahead.

So sticking with the topic of customer conversations and honing in on one in particular, yesterday, Pioneer said that they're planning to start re-expanding their drilling program in the Sprayberry and Wolfcamp formations in July at a pace of two rigs per months through December. I guess two-part question. First, do you expect to be an opportunity for you, given your historical relationship with Pioneer? And then two, is that an opportunity where you've already started to have discussions?

Yes.

We’re not going to disclose particular customers, but yes is a good answer.

Okay, I'll leave it there but that’s encouraging. And then, Byron or Ed, again, could you give us an update on your estimate of where at year-end you expect the total industry fleet to be for both pad optimal and then total AC?

If I could do that I’d be at a hedge fund and making a significantly more money than I am now. I really can’t answer that, but I can tell you that what you’re going to see is The Street pushing the E&P community to maximize production profiles and cash flows in the most optimal way. Well, the most optimal way is pads, and not just pad, but large pads. And on any size pad, rigs that have those six characteristics I outlined, are going to be the rigs at choice. And it’s not just us, obviously, but [indiscernible] what I would encourage you to do is try to determine other competitors fleets with regard to those six characteristics. Those are the rigs that are going to go to work. And as typical in the industry, you get to 80% or so effective utilization and day rates go up. And as Ed noted, that will coincide with increasing term. So I think we need to look for those general market attributes, which I don’t see right now before we can make any sort of forward predictions about what percentage or what part of the fleet will be doing what. So I think we can see it coming, but we don’t have enough granularity right now to be able to make a useful call.

Byron, I certainly wasn't asking in terms of your forecast for how many would be working. I just meant total number being marketed, based on what you know about construction queues across your competitors.

We market everything all the time. So I am not sure, I think I’m misunderstanding your question.

And let me add a little bit to that, Thomas. A lot of that has to do with really the big four, and how many they really are going to produce per month between now and the end of the year, and I know what they report, but in real reality how many are they delivering. And I would look to people like yourself and the other analyst to try to nail that down from them. You have the better opportunity to find that information before I can. But I think that is the key question is how many -- if I say, I’m going to do two a month and I actually do one, or if I'm going to do four and I do two, that I think is the key question. And we’re just like you; we have to take a stab at it. and that’s why I have a financial person that takes care of my investments, because I am not good at predicting those things.

All right, Ed. I'll come back to you with my estimates for each then. Last question for me. When it comes to your rigs that are currently on standby, could you share some color on where they are regionally?

They’re here in the yard and they’ll mobilize to their first sites at the times that Phil mentioned h as our clients determine what they’d like to move them to.

And we have a follow up from Rob MacKenzie of IBERIA Capital. Please go ahead.

On your margin guidance for Q2, Phil, the $9,250 to $10,000, does that include the extra startup costs or not?

That would assume the start up cost would be in addition to that.

So not included. On the CapEx, I'm a little bit confused. You guys are talking about $26 million this quarter net of insurance payments, but in the cash flow statement, you're talking -- you disclose -- was it $21 million and change?

Yes, the difference would be accounts payable. What would be in the accounts line and what was paid in AP. The actual CapEx we did was the absolutely CapEx number for the quarter. The $26 million was the absolute number. We may not have paid cash that much. Some of that may come out in the second quarter in cash.

So I need to adjust the second quarter for what's in a-pay in the first quarter still?

Yes, you should do that if you’re -- yes.

And then your CapEx profile for the rest of the year, I think you guys guided -- I forget what's exactly here, 40 -- where's my notes? It’s here on the model. You guided $26 million to $30 million remaining for the year. What does that profile look like Q2, Q3, Q4? Can you help us out with the timing of those at least?

Q2, it will be able to more front-loaded into Q2 as we complete rig 212. I'd probably put 60% of the remaining CapEx and half of it in Q2 and then the second half of the year would be the second half when we do the upgrade.

And so the upgrade on rig 103, that cost is what? Roughly, $2 million?

That will be more than that. You’re going to put a new sub structure on the rig. Then you have to put the walking system on there as well and there is few things with the driller's cabin you have to do because of that. So it will be more than that. The incremental cost to it -- and there will be overhead that we allocate to as well. But the incremental cost to it on a run-rate basis is probably a $2 million to probably $3 million would be the incremental cost. There will be other cost to get capitalize to the rig that are really not incremental though.

Got it. So after that -- after the final 200 Series rig, what's left in your capital budget discretionary for further upgrades or…?

There is $13 million that we had allocated our budget. And it’s purchasing equipment that we can do two things with, we can build another rig or we can upgrade the 200 Series rigs. We could do the 200 Series rigs or we could start building a 15 ShaleDriller. Right now, nothing has been set in stone, but we plan on doing the upgrades.

Well, Rob, the answer to your question is there’s nothing, and that’s the CapEx budget that’s been approved by the board. If we saw opportunity above and beyond that we go back to the Board and ask for more money.

So then that begets the next question is, is what are you -- what would you guys look for not just on a rate, but I guess probably more importantly on utilization to commit the building a 15th ShaleDriller? And I presume you would do that on spec, given you want to get ahead of the next up cycle.

Term. We’d look for their reemergence and some sort of term structure. I think you can make -- I know what our weighted average cost of capital is. I know what our incremental returns are various day rates, you have to assume utilization. There is nothing right now form a return basis that would slow us down, but we’d want to see some term so that when we make those internal rate of return determinations, we can do it on the basis of a period of time and not have four well then off, then two well then off. So the answer to your question is the emergence of some kind of six-month term on the contracts we're signing.

Great, that’s very helpful. And then, Phil, can you just remind me how your borrowing base was re-determined last year when that happened?

It was a reappraise at the end of the year after the market had changed. And then we’ve had two rigs, obviously complete, that have been reappraised as well. They appraise when they’re completed.

Is there like a rule of thumb we can use like X percent or a certain dollar value per rig plus percentage of the AR?

On the new rigs were probably getting in the borrowing base, slightly more than $10 million. Some of the other rigs that are older, you’re borrowing base goes down. So probably rule of thumb for our entire fleet $9 million right now or something like that.

Okay. And still counting 85% of eligible accounts receivable?

Yes.

This concludes our question and answer session. I would like to turn the conference back over to Byron Dunn, Chief Executive Officer for any closing remarks.

Well, thank you all for joining us. It has been a challenging quarter. I think we’re started to see the light at the end of the tunnel and we look forward to having another conversation with you at the end of the next quarter. So thanks again.

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