Good morning, and welcome to Independence Contract Drilling Third Quarter 2016 Financial Results Conference Call. All participants will be in listen-only mode. [Operator Instructions] Please note today's event is being recorded. I would now like to turn the conference over to Philip Choyce, Executive Vice President and CFO. Please go ahead.

Good morning, everyone, and thank you for joining us today to discuss ICD's third quarter 2016 results. With me today is Byron Dunn, our President and Chief Executive Officer. Before we begin, I would like to remind all participants that our comments today will include forward-looking statements which are subject to certain risks and uncertainties. A number of factors and uncertainties could cause actual results in future periods to differ materially from what we talk about today. For a complete discussion of these risks, we encourage you to read the company's earnings release and our documents on file with the SEC. In addition, we refer to non-GAAP financial measures during the call. Please refer to their earnings release and our public filings for our full reconciliation of EBITDA and adjusted EBITDA and for definitions of our non-GAAP measures. With that, I'll turn it over to Byron for opening remarks.

Good morning, everyone and thank you for joining us today. Following our usual format, I’ll review third quarter results and provide observations on current and expected market conditions. Phil will detail our third quarter financials and then we'll take questions from call participants. The third quarter was transitional for ICD. We booked 774 revenue days in the quarter and on a very compressed five week time scale, we reactivated five rigs more than doubling our operating fleet, while deploying 5.2 million in reactivation and capital costs. Two of the rig reactivations included fluid system upgrades to 7,500 PSI and one included the addition of a third mud pump. Two of the rigs reactivated during the quarter were deployed to the Louisiana/Haynesville a new region for ICD, whereas in the Permian, operators are demanding high impact Pad optimal equipment. This is a basin we foresee as another key focus area for us complementing our Permian operations base. ICD is recognized as a premier employer and we had no problem attracting the required talent during rig reactivation. By virtue of being some of the first rigs back to work, we were able to utilize first move advantage to attract the best talent available in the market through an active and successful talent acquisition effort. Additionally, and subsequent to the end of the quarter, we signed two additional new contracts for rigs deployed in the Haynesville and deploying in the late fourth quarter bringing the number of ICD rigs contracted in the Haynesville to four. Importantly these are one year term contracts. Performa for these new contracts, 92% of ICDs available rigs are now contracted. Having said that, it’s important to note that several of our rigs are in short-term well to well contracts, rig pricing is very aggressive and full utilization during market stabilization may be choppy. I’d like to point out that ICD is working for partnering and contracting with mid to large cap publicly traded E&P operators and large well capitalized private operators, who embrace pad drilling at high impact long laterals using the full capabilities of Omni directional walking, 7,500 psi, dual fuel Pad optimal equipment. The operators using ICD Pad optimal rigs are now drilling low calorie wells. They’re planning long laterals and higher numbers of wells per pad. They represent the rise of a new progressive group of E&P operators that recognize that adopting technically advanced Pad optimal rigs in a wellbore manufacturing model, utilizing multi well complex pads in long laterals reduces the full cycle fuel cost base, provides permanent efficiency gains and delivers higher return wells at a lower cost. This represents a significant competitive advantage relative to their competitors that use legacy lower tech rigs. I’d like to talk for a minute about day rates now. Day rates for pad optimal rigs are not where we would like them to be, still in the mid to high teen range. Currently, we’re seeing aggressive public and private contractor pricing and do not expect any day rate improvement in the near term. It’s important to note that I’m specifically referring to true day rate, not the revenue for rig number which may include trucking, directional drilling, casing running and other services and not that blended extend outcome. As we’ve noticed on previous calls, the first sign of a healing market is contract tenure extension, which we’re starting to see, then followed by the rig improvement. In the current market recovery, aggressive pricing by many public and private competitors may push out the timing of day rate improvement and in any case, we see no current or near-term day rate improvement. I’ll talk for a second about cost structure, reflecting the aggressive redeployment of rigs, third quarter operating cost was higher than normal. The transition cost in the quarter included staffing in advance or rig mobilization increased overtime and on the capital side, working capital build. Also our reported incremental margin on revenue generated by rigs reactivated from standby was near zero, as we already captured the entire operating margin on those rigs to our standby rate. During the quarter, we rationalized our executive leadership team, SG&A and as a marginal manufacturer our rig manufacture cost base, taking an aggregate of $1.5 million on our forward run rate cost structure. We expect this forward run rate structure to be stable and scalable throughout 2017. In the third quarter cash operating cost at the rig level for operating rigs read at approximately $10,600 per day and we expect those cost to remain flat for rigs operating through the quarter. More importantly is our rigs on standby go back to work and our fleet begins to approach full effective utilization. We expect bully burdened operating cost to trend to about $12,500 per day. Along with the rationalization of our rig construction, overhead and field operations, we also completed a review of our equipment inventory and opportunities to standardize items across our rig fleet with minimal out of pocket cash cost ICD. As a result of this review, we identified equipment based on early 200 series specs and out of spec equipment relative to the current 200 series design as well as equipment where we’ve standardized on a different vendor. We believe there are opportunities to dispose of this equipment for cash or to exchange it for equipment that we’re standardized on. During the fourth quarter we intend to monetize or exchange these assets. We will likely book a fourth quarter non-cash charge of about $4 million depending on the realized sales price or the structure of equipment disposition. These are non-cash charges and we will use the cash generated through sales or equipment gain through exchange to further upgrade and standardize our fleet. Phil will provide additional details about this process later in the call. Our capital budget for the remainder of 2016 has increased from 1.3 million to 7 million, as we pay for additional upgrades completed during the third quarter and continue upgrading and returning rigs to service. As I conclude my prepared remarks, it appears that the North American land drilling cycle is bottomed, but it’s important to note that many rigs are in short-term well to well contracts and the industry pricing is very aggressive. This may result in choppy rig utilization going forward. If commodity prices remain in the $50 per barrel or $3 per mcf range, 2017 should be a solid recovery year for utilization firms because of the confines of the current day rate range. At this point, I’ll turn the call over to Philip, who will run through third quarter financials with you.

Thank you, Byron. During the third quarter, we reported a net loss of $7.2 million or $0.19 per share. Adjusted for non-cash charges associated with rig upgrades, our net loss was $6.5 million or $0.17 per share. Included in this net loss were approximately of $2.6 million or $0.07 per share reactivation cost of five rigs, severance cost associated with the consolidation, portions of our rig construction and field operations. Adjusted EBITDA, including the reactivation severance costs for the quarter came in at $1 million - approximately $1 million and was $3.6 million excluding those costs. Fleet generated 774 revenue days, representing 6% sequential increase from the prior quarter, slightly ahead of guidance as we reactivated one additional rig during the quarter. This included 222 days on a standby without crew basis. Our marketed rigs achieved 64.7% utilization during the quarter. Overall, we recognized revenue of $14.5 million, and pass-through revenues were approximately $1 million during the quarter. Gross margin per operating day, excluding rig reactivation and rig construction expenses were $7,806, in line with our expectations and guidance. Reactivation cost for the five rigs totaling 2.5 million exceeded our guidance principally due to the reactivation of an additional rig as well as additional cost associated with inventory items, purchased across all reactivated rigs that were expense when purchased. Rig construction costs that were expense during the quarter were $300,000 and pass-through costs were $1 million during the quarter. Selling, general and administrative expenses were $3.2 million including severance payments of approximately $100,000 associated with the consolidation of our rig construction and field operations. SG&A expense included $1 million related to non-cash stock based compensation and that included $100,000 benefit associated with stock award [indiscernible]. SG&A expense adjusted to remove severance expenses and non-cash compensation, represented 28% decline from the prior quarter and 6% sequential decline from the second quarter of 2016. During the quarter, depreciation expense was $6 million and tax expense was the minimum. At September 30, we had net debt excluding capitalized leases of $15.1 million, $5.8 million increase in net debt compared to the prior quarter or split relatively evenly between capital expenditures associated with the rig upgrades and working capital investment associated with the reactivation of five rigs. Our borrowing base under our credit facility was approximately $78 million at quarter end. Performa for adding the other rigs associated with our two new contracts, the borrowing base at quarter end would have exceeded our $85 million commitment level. Cash outlays for capital expenditures, net of disposal and insurance proceeds were $6.7 million. Our backlog of term contracts at September 30, 2016 was approximately $40 million, which excludes the two 12 month term contracts that were signed following the end of the quarter. Byron mentioned that we made improvements in our cost structure by consolidating portions of our manufacturing, overhead and field operations. We expect that this will manifest itself most noticeably the reduction in our rate construction overhead cost. We previously have discussed that these costs, assuming no rig construction activities during any predictable quarter could be approximately $750,000 per quarter. Going forward, we expect these costs to be approximately $450,000 per quarter, under the same assumption. Benefits to our SG&A cost structure will mainly be through a reduction in stock based compensation expense. Looking at the fourth quarter, we have approximately 800 revenue days under contract and additional potential 120 revenue days tied to renewing stock market contracts expiring later during the quarter. Rigs for two newly signed contracts are not scheduled to commence operations till January 1 of next year. Assuming no rigs returns to us or there is no idle time for different [ph] stock market rigs between customers, our best estimate is that our revenue days will range between 910 and 920 days during the fourth quarter, which we estimate approximately 10% will be earned on a standby basis. Approximately 40% of these revenue days will be from term contracts signed in 2014. We estimate our margin per day during the fourth quarter to range between $6,100 and $6,600 per day. The sequential decline compared to third quarter led to a reduction of rigs operating under legacy term contracts and increased number of rigs operating at current market rate. This margin guidance excludes reactivation costs associated with putting non-operating rigs back to work as well as cost associated with rehiring, trading and staging crews. Today we know of two rigs that we expect to return to operations at the end of the fourth quarter and there is one rig still on standby and one idle 200 series rig for which we’re in discussions regarding reactivation. For the fourth quarter, we expect reactivation cost to be similar on a per rate basis to what we experienced in the third quarter, the aggregate amount based upon the level of reactivation activity in the quarter. We estimate rig construction cost will expense in the fourth quarter to be approximately $300,000 and this is not included in the margin per day guidance. We expect SG&A for the fourth quarter to approximate $3.1 million of which approximately 950,000 will be non-cash stock based compensation. Depreciation expense should approximate $6.2 million and interest expense should approximate $500,000. Similar to the third quarter, we expect to recognize non-cash disposal charges in connection with the commission equipment related to 7,500 PSI upgrades on two idle rigs that will mobilize at the end of the fourth quarter. We also expect to recognize non-cash charge Byron discussed relating to the sale or exchange of drilling equipment. Tax expense should be flat with the third quarter. On the capital side, Byron discussed the increase in our capital budget for the fourth quarter, $7 million of cash outlays estimated for the fourth quarter include $3 million cash payment for rig upgrades that occurred during the third quarter as well as additional 7,500 PSI and related upgrades occurring during the fourth quarter and of course maintenance and inventory purchases. As rigs go back to work, we’ll also be investing in working capital which we estimate to be approximately$600,000 per reactivated rig. Thus we do expect to incur some incremental borrowings under our revolving credit facility as we have to upgrade and put rigs back to work. However, we do not see any capital strains under our current credit facility that will limit our ability in any way to respond to this increased demand in activity. And with that I’ll turn the call back over to Byron.

Well, thanks Phil. Operator, at this point, let’s open the lines for Q&A.

Absolutely, thank you sir. 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.

Good morning guys.

Good morning, Rob.

Good morning, Rob

A question for you I guess Byron, can you give us a handle - obviously you said the day rates remain weak in the mid to upper teens, where does that stand or what can you tell in terms of the range for the two new contracts in the Haynesville and I presume those rigs are getting an upgrade before they go 7,500 PSI mud systems and what impact if any would that have had on the rigs.

Well, Rob. The 7,500 PSI fluid systems are pretty much a requirement for the work that we’re doing. The people we’re working with are drilling long to super laterals and so that’s a cost of doing business for the type of work we’re doing. The day rate for that equipment is in the upper teens.

So, that would mean - upper teens would mean over 17 a day?

It just means upper teens, Rob. I don't want to get into details. You never know who is on these calls.

Got it, okay. And again these are obviously here the first one-year contracts we've seen signed in this latest up cycle. Can you comment for us on the prospects for locking up more of your rigs on term and what your appetite is and how you'd like to see that stagger throughout your fleet?

Sure. I think we've talked about this a little bit on the two or three previous conference calls. The way as this market improves, stabilizes and improves, the first thing you're going to see is contract extensions and one-year term contracts. And the driver for that is the client base seeing equipment demand, this type of equipment demand increasing, and they want to make sure that based on their drilling programs they've locked in the type of equipment they need. So, that's the stage we're at now. We favor term contracts and particularly based on our view that you're not going to get any type of day rate improvement in the near term, we would - to the extent that we can and it fits us and the parameters are right, we would favor term.

Okay, great. Next question would be along the lines of incremental, the CapEx, right. You're now starting to see this term take hold. I think that has been one of your hurdles that you wanted to see before you committed to upgrading rig one-on-one. Where does your thought process stand on that rig at this point? And then second, what is your updated thinking if any on building up the next 200 series rigs we've already kind of spent half the money if you will?

When one-year term becomes industry standard, we'll look at that and we're the nascent stage of that right now. So, we're not in the mode - we're not in a new build mode and we'll see how the next couple of quarters flush out in terms of term becoming pretty standard for pad-optimal equipment.

Okay. Thanks. I’ll turn it back for now.

And our next question comes from James West of Evercore ISI. Please go ahead.

Hey, good morning, guys. This is Alex on for James. How are you?

Hey, Alex.

So, you have one competitor out there building new build rigs. Could you speak as to what you think that means for the rest of their legacy fleet and whether it's able to compete in the new market that's quickly becoming standard?

I don't know who that is Alex. I really can't comment.

Okay. Fair enough. And then second question, as market kind of looks to go to one-year terms, do you guys feel you're giving up some potential day rate traction by being the first ones to sign one-year terms and?

We don't know. I think that we see substantial aggressive bidding in the market including the market for walking 1500 horsepower equipment. So, what we are seeing is that equipment coming into short supply, but juxtaposed against that when you see public and private competitors bidding very, very aggressively, it makes sense to term out.

Understood, thank you.

And our next question today comes from Tom Curran of FBR Capital. Please go ahead.

Good morning, guys.

Hi, Curran.

Are you already having discussions you had at least around the conversion of rig one-on-one and in those conversations, how far apart are you on day rate?

We're having no discussions in that regard right now, Tom, and until again we get to an industry-wide one-year type term, that's - we're too far apart with regard to our rate of return requirements and current market conditions.

Okay. And then turning to the Haynesville, you're very quickly ramping from no presence to what will be a four-rig presence as of the Haynesville current rig count that would make you one of, if not the biggest land driller there, do you foresee the need for any incremental infrastructure support costs there Byron or Phil?

Couple of thoughts, we have substantial inquiry. I'm sure the industry touches that. There is substantial inquiry coming out of the Haynesville and it's interestingly large with regard to the Permian. So, gas prices, you give a hedgable gas price environment of $3 or higher, I expect to see activity in the Haynesville ramp for the industry. It takes more than one basin to drive market improvement and this could very well be a second major basin for us. So, we're cautiously optimistic about activity levels and rig utilization drilling for gas in the Haynesville. And with regard to additional infrastructure, the answer is no.

Okay. That was some very helpful interesting color. Thanks. Fine.

[Operator Instructions] Our next question comes from Daniel Burke of Johnson Rice.

Good morning, guys.

Hi, Daniel.

Just this is a recap, then second half year CapEx spending has gone up by about $10 million versus plans earlier in the year. I mean how many - how many 7500 PSI upgrades are captured in that figure? I mean has that basically worked its way through the whole fleet or are there still –or are there some other upgrades in there?

We have three - we have three rigs at the end of the year that will not have been upgraded to 7500 PSI. So, there is five - and for this year we've done 7500 PSI upgrades, several third-mud pump upgrades and then we completed the rig 217 conversion 102 or 103 conversion to the rig 2017, the material components of the second half CapEx.

But I think it's fair to say that as we get - if we get any downtime between rig commitments, we'll make those upgrades.

Okay. That's helpful. And then, Byron, you've expressed some caution over the - I guess the time line over which we would see improvement in day rates in the high spec reclass. What needs to happen to get to that point? I mean as you alluded to earlier, we're starting to see the ability or term creep back into the market very nascent. How many rigs do we need to see go back to work? What happens next year?

The rule of thumb is that you get 80% utilization in a particular asset class and that provides underlying support for day rate improvement. Having said that, the first thing you do see is contract extension which we're seeing and then the day rate improvement follows on the heels of that. So, that's where we are right now. But the other thing to put into that mix is there are public and private competitors that for whatever reason are bidding substantially below this the mid to high teens range and there are some headwinds there that are caused by that type of bidding.

That's helpful to sync. And then maybe last one, maybe back to Phil, can you remind me, what's the next couple of term rules, legacy term rules to look for?

Yeah, we’ve had no changes to any of our term contracts until our last conference call. So, this update we have one - the next one expires at the end of the first quarter. We have one expire in the middle of the second quarter of next year, one expire in the middle of the third quarter and then one that goes through the middle of 2018.

Okay, guys. Thanks very much.

And our next question is a follow-up from Tom Curran of FBR Capital. Please go ahead.

Thanks for letting me back in guys. I was curious when it comes to the rig components that you're standardizing for, what are those and how competitive were the vendors as you went out to them and evaluate it, which models to go with?

All right, so as we go to super lateral type drilling and completions, you really need to go to 500 ton top drives and we've got some 350 ton that we used on the 100 series and the early 200 series that's probably about half of what we're rationalizing right now. And it's - so that's the driver. Then there is some iron work next that are in spec with what we're doing. There are some catwalks that are in spec with what we're doing and it just relates to longer and longer and longer laterals. And from a supplier standpoint, there is a very large amount of suitable equipment had substantially discounted rates in pricing from what you saw as list in the last up cycle. So, there is no shortage of equipment. Pricing is - on that side is very aggressive as well and there is no - we may be able to do a one for one swap. I don't know how it's going to work out, but we're - as we raise cash, we're deploying it to go to the type of specs - of equipment specs that are going to be supportive of super laterals.

And that’s all consistent with what I would have expected, Byron. As a result, are you yourselves trying to take advantage of the position your suppliers are in with perhaps longer term agreements or bulk purchase contract, anything like that where you can maybe lock in as you standardize?

Now we're not pursuing that. We don't want to get ahead of our skis, so we're being quite disciplined in our capital deployment taking a lot of cost out of our SG&A and our operating run rate. And so until we get some better clarity, we’ll be very capital disciplined and won't do anything like that.

Okay. Thank you.

And our next question comes from Matt Johnson of Nomura. Please go ahead.

Hey, good morning, guys.

Hi, Matt.

Good morning.

Congrats on the two new contracts in the Haynesville. Just wondering as we think if you get a permit in the Haynesville outside of those two basins, just wondering if you could give us your thoughts on how the rest of the lower 48 might evolve over the next year and what - from a geographic perspective where might be the best opportunity to win some new work?

Sure. Of course, our target market is Texas and contiguous states. So, our client conversations and our marketing and business development efforts are really focused there. When you step back and look at that, you've got the Permian, STACK, SCOOP, Eagle Ford and the various gas players including the Haynesville. Where we're seeing a lot of traction right now is the Permian in a big way and the Haynesville in a growing way and we get inquiry from other areas, but it's not in the volume of those two basins right now. So, I think it has a lot to do with the underlying basin economics and those two are in the sweet spot. So, I'd expect to see the bulk of it right now come from those basins and certainly we have the ability to work anywhere in that five-state area and we would respond very quickly to inquiry or rig requirements from those basins as well.

Got it. Okay. That’s really helpful. And then just kind of a follow-up in connection with that. How does day rate kind of factor into the decision-making process if you were to go outside of the Permian and the Haynesville staying within that kind of five-state area? Would you need a higher rate? Or are you kind of close enough to your [indiscernible] [00:03:08] logistics network where you would be incentivized to kind of go out and what current rates are?

Current rates in the mid to high teens are where we play. We're not going to participate in knock down day rate work. And from a logistics and a cost standpoint anywhere in that five-state area has pretty much the same cost structure for us, a little bit higher in New Mexico. Some of the states have different permitting and operating requirements, but they're not really germane in terms of driving a requirement for a higher day rate.

Great. Thanks for that.

And our next question is a follow-up from Alex George of Evercore ISI. Please go ahead.

Hey, guys, sorry. One more and certainly I guess more academic. But as the days required to drill a well decreases, when rigs are capturing a smaller percentage of the DNC CapEx price, do you guys see a need for the business model to shift away from a revenue per day model in order to, I guess, incentivize further technology adoption and I guess continue to invest in higher quality land rigs?

We talk about that and I think there is - we're looking at over a five, 10-year time frame and it's pretty difficult to do that, but you can make a case for that, but that have to be something that is driven and adopted by the E&P community. So, right now we don't see any. In the next several years, we see nothing that's going to take us from a traditional day rate environment.

Could that potentially sustain the [ph] new builds not necessarily by you guys, given where you played, but by the [indiscernible] community and potentially drive high utilization as a result?

Well, I think what you'll see is over the course of this cycle, you'll see pad-optimal equipment go to full effective utilization, you'll see the increased use of longer term contracts. You'll see varied improvement and then the main driver for what we do is pads as pads become broadly accepted by the entire E&P community as a much effective way to [indiscernible] from both an engineering and a cost standpoint from [indiscernible] their drilling program. That’s going to create demand for pad-optimal rigs and if you're going to go to the top of building big pads there is no particular region to do anything [indiscernible] and so you get into a new build cycle [indiscernible].

And well done on essentially full utilization [indiscernible].

Thanks.

Ladies and gentlemen this concludes the question-and-answer session. I will turn the call back to the management for any closing remarks.

As always, we thank you for your participation on the call for the questions and supportive [ph] shareholders and we always want to thank the employees of ICD for their exemplary safety record and exemplary all-time record in all the things that make us to [indiscernible].

This concludes today’s conference call. So, thank you all for attending today’s presentation. You may now disconnect your lines. And have a wonderful day.