Welcome to the Independence Contract Drilling Incorporated Third Quarter 2015 Financial Results Conference Call. [Operator Instructions]. I would now like to turn the conference over to Philip Choyce, Senior Vice President and Chief Financial Officer. Please go ahead, sir.

Good morning, everyone and thank you for joining us today to discuss ICD's third 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 this call. Please refer to the 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.

Thanks, Phil. Good morning, everyone and thank you for joining us today. Following our typical format, I will review ICD's third quarter operations and follow with thoughts on what we expect during the fourth quarter and into 2016. Phil will discuss financial highlights and then we'll take questions from call participants. Third quarter results were in line with our expectations and the guidance we provided on our second quarter call. During the third quarter, ICD had 82% utilization of the available fleet, that being the fleet of 200 series rigs, not including the 2 remaining 100 series rigs in the yard for conversion to 200 series capability. Field cash margin at the rig level ran at almost $12,000 per day. Cash SG&A was $3 million and we ended the quarter with $91.5 million in drilling backlog. Fully burdened operating costs came in line with our expectations. And while we incurred incremental costs associated with stacked rigs in West Texas, on a run rate basis, the cash operating cost of our operating rigs was flat with the prior quarter. As a modular manufacturer, ICD has substantial flexibility to suspend or accelerate our rig build cadence and to ramp or reduce capital and operating spend in this regard very rapidly. As we discussed on our second quarter call, we have paused our rig new build program until market conditions improve. During the third quarter, we completed the restaging of our supply chain, deferring purchase of capital items that have been scheduled for 2015 through 2018. Given current market conditions, we expect ICD to generate substantial free cash flow in 2016, including maintenance capital spend. Including the spend associated with capital items that were not pushed forward and we will take delivery of in 2016, ICD free cash flow should be around breakeven. Through modification of our organizational structure associated with the suspension of rig build and the identification and implementation of measures associated with productivity enhancements, ICD eliminated $1.5 million in run rate operating expenses from our construction cost base during the third quarter, while maintaining our enterprise rig build knowledge base. With that overview, I'd like to provide some context on ICD's fleet status, our cost structure and liquidity and what we think market conditions for walking pad optimal rigs will look like for the next 6 or 9 months. Phil will then provide additional detail on third quarter financial metrics. So first I'd like to touch on ICD's fleet status with you. ICD walking pad optimal equipment is going back to work, while net-net skidding, SCR and mechanical rigs continue to stack. This is because walking pad optimal rigs bend operators' total well cost curve down, deliver more well bore per rig year and that well bore is of higher quality. One of our clients contracted an ICD ShaleDriller and a competitor's skidding SCR rig, employed both those rigs on similar pads in the same field to determine for themselves the relative efficiencies of the two designs. Despite a day rate on the ICD ShaleDriller being $5,000 per day higher than the competitor's SCR skidding rig, the productivity of the ShaleDriller's walking pad optimal and automation systems, its BiFuel capability resulted in an all-in well cost several thousand dollars per day lower for the higher day rate ShaleDriller relative to the skidding rig. Skidding rigs, in whatever configuration, are not pad optimal. They need to be leveled on uneven pads and they can't accommodate any deviation in a precisely parallel and square conductor layout without being broken down, physically moved and then re-rigged up. After the end of the third quarter, ICD executed a new contract, not a farm-out, extension or modification of an existing contract, for rig 204, taking it out of stack and back into the active fleet. We expect to end the year with a 92% utilization of our available rigs, again that being the 200 series rigs. Regardless of commentary from the contract drilling industry, operators selecting equipment for new contracts are voting with their wallets. Next, I'd like to briefly discuss our forward cost structure. As I noted earlier during the third quarter, ICD reduced forward operating costs by $1.5 million on an annual run rate basis, principally driven by the natural decrease in operating expenses associated with our modular manufacture structure as activity rates declined. During the fourth quarter of 2015, ICD will continue its organizational productivity enhancement program. And we estimate by the end of year 2015, we will have eliminated an additional $1.5 million in run rate costs. So as we enter 2016, we will have reduced annual run rate operating expenses by a total of $3 million. These reductions reflect some temporary changes in staffing, as well as permanent improvements in efficiency and changes in organizational structure. Once we re-engage our build program, many of these costs will be re-incurred as will the working capital build associated with activity expansion. However, when ICD ramps back into a new build replacement cycle, we estimate that our total operating cost base will run $1 million to $1.5 million lower annually compared with our precost reduction structure on a historical build rate basis. Liquidity, we announced changes to our ABL a couple of weeks ago. The amended credit facility has a leverage ratio covenant which increases from 3.75% in the first quarter of 2016 to 4.5% by year-end, reduces the minimum rig utilization covenant to 60% in 2016 and provides for the exclusion of some expenditures from consideration for purposes of calculating the leverage and fixed charge coverage ratio. The facility provides for aggregate commitments of $125 million and is priced at LIBOR plus 4.50. I want to note that ICD does not pay cash taxes, has very low maintenance CapEx in the $2 million or so range. So the quality of our EBITDA in terms of its relationship to true cash generation is very high. We have outstanding 2016 growth capital equipment purchase requirements of between $8 million and $9 million which we will fund and take delivery of. Although we have paused our rig build program, we have the flexibility to complete our final 100 series rig conversions when market conditions improve. And we will be in possession of the majority of long lead time items to complete an additional new build ShaleDriller. As I mentioned earlier, based on current market conditions, we believe that ICD will generate substantial free cash flow from operations in 2016 and breakeven cash flow after funding open purchase orders associated with growth capital spend. The last thing I want to talk about before I turn it over to Phil is forward market conditions. Our estimate is that the spot market for walking pad optimal rigs is coalescing into $15,000 per day to $17,000 a day range, with tenure assured around 6 months. While we believe that the market for walking pad optimal equipment will naturally firm into 2016 as legacy rigs fall off contract and are displaced by more efficient and productive rigs, a meaningful improvement in day rate and fixture tenure will require forward commodity prices ability and increases in capital spend by the E&P community. The early indicator of a sustained improvement in pad optimal contract drilling rig demand, indicating an approximate 80% overall utilization of the walking pad optimal asset class will manifest by the extension of contract tenure which will be followed with a lag by increasing day rates. We anticipate this will be a 2016 event for walking pad optimal equipment. In closing, I want to thank all of our employees for their loyalty and commitment to safety and performance. Our people, as well as our equipment, drive the ICD difference. I'll now hand the call over to Phil to discuss our third quarter financial results in detail.

Thank you, Byron and thanks, everyone for joining us today. During the third quarter, we reported a net loss of $3.4 million or $0.14 per share. Included in this net loss was a noncash disposal charge of $2.3 million associated with the conversion of one of our non-walking rigs to 200 series pad optimal status. Excluding this noncash charge, we reported a net loss of $1.2 million or $0.05 per share. We ended the third quarter with 880 revenue days, representing a slight sequential decline compared to the second quarter of 2015. During the quarter, our marketed rigs which exclude our two rigs scheduled for conversion, achieved 82% utilization. On a sequential basis, we recognized revenue of $21.3 million compared to $21.1 million in the second quarter of 2015. All of our rigs on standby returned to normal operations early in the third quarter and we had only one rig month of standby revenue during the third quarter. We're not forecasting that any of our rigs earn revenue on a standby basis during the fourth quarter. Total operating costs were $12.5 million during the third quarter. On a per day basis, our fully burdened operating costs during the quarter were $13,239 per day. Our cost benefited from 1 month of rigs operating on a standby without crew basis which favorably impacted our cost per day in the range of $300 to $400 per day. During the quarter, SG&A expenses were $3.8 million, flat with the second quarter. Included in SG&A expense was $738,000 related to noncash stock-based compensation expense. Depreciation expense was $5.6 million during the quarter. The sequential increase related to the activation of our 14 ShaleDriller rig during the quarter, as well as new build rigs previously earning revenue on a standby basis. We expect depreciation expense during the fourth quarter to approximate $6.1 million. During the quarter, we elected to change methodologies for calculating Texas margin tax which resulted in our receiving a cash refund for prior year taxes and reducing our forecasted tax liability for 2015. This benefited the quarter compared to our guidance and resulted in our recognizing a tax benefit during the quarter of $326,000. For the fourth quarter, we expect any tax expense or benefit to be de minimus. At September 30, we had net debt of $55.1 million. And our borrowing base under the credit facility was approximately $99 million at quarter end. In light of current market conditions and lack of visibility into 2016 and the timing of a market recovery, as Byron mentioned, we recently elected to amend our credit facility to reduce our aggregate commitment from $155 million to $125 million and to adjust several of our maintenance covenants which we believe allow us to maintain liquidity under the facility in the event market conditions continue to decline and persist throughout 2016. During the quarter, cash outlays for capital expenditures were $9.4 million, primarily related to completion of our 14th ShaleDriller rig,, conversion of one of our non-walking rigs to 200 series pad optimal status and the purchase of long lead time items for our second rig conversion, as well as equipment for our 15th ShaleDriller rig. During the remainder of 2015, we expect cash outlays for capital expenditures to range between $7 million and $9 million dependent on actual timing of equipment deliveries. This CapEx guidance includes cost to complete the current rig conversion as well as purchases of previously ordered long lead time items that can be utilized in our second rig conversion and the construction of our 15th ShaleDriller rig as well as maintenance capital expenditures. Now I want to turn to our outlook for the fourth quarter. Taking into account the reactivation of one of our idle rigs toward the end of the fourth quarter, we expect that our revenue days in the fourth quarter will range between 950 and 965 days. We expect our revenue per operating day to range between $23,100 and $23,400 per day. On the operating cost side, we expect our operating cost per day to increase slightly during the fourth quarter and range between $13,300 and $13,600 per day during the quarter. The sequential increase principally relates to the elimination of standby days during the fourth quarter. Byron previously mentioned various initiatives we're undertaking that will reduce operating costs on a go-forward basis. We do not expect those to meaningfully benefit the fourth quarter, but will benefit future quarters beginning in 2016. Other fourth quarter operating costs we expect to incur that are not included in our OpEx per day guidance are expected to be in the range of $350,000 to $400,000. On corporate-level items, we expect SG&A for the fourth quarter to range between $3.7 million and $3.9 million, noncash stock-based compensation representing approximately $900,000 of these costs. We expect fourth quarter interest expense to be approximately $975,000. We also will incur a one-time noncash charge of approximately $400,000 during the fourth quarter associated with the write-down of deferred financing cost due to the reduction of our aggregate commitment under our revolving credit facility. As Byron mentioned in his remarks, we're postponing construction activities upon completion of our current rig conversion that is underway. And we're in the process of assimilating key construction personnel into our operations and took actions in the third quarter that reduced our overall construction cost base by $1.5 million. However, to the extent construction activities are suspended or intermittent, we will begin expensing the remaining costs at our Galata [ph] facility that were previously capitalized as part of our reconstruction activities. For the fourth quarter, we estimate we'll expense approximately $550,000 associated with these costs, of which we estimate $50,000 will be related to noncash items. I think going forward into 2016, the amount of such costs that will be expensed will be based on the level of construction activity in our yard, if any. Assuming absolutely no construction activity, we estimate the aggregate amount of such costs that may be expensed, as opposed to capitalized during any particular quarter, could range between $750,000 and $850,000, of which $100,000 during any quarter would be noncash. And with that, I'll turn the call back over to Byron.

Well, thank you, Phil. I don't have any other comments. So Operator, let's turn the call over for questions.

[Operator Instructions]. Our first question comes from James West with Evercore ISI. Please go ahead.

This is Alex on for James. You guys stated that you expect utilization to run at about 92% as we exit the year. Could you shed some light as to when contracts roll off in 2016 and how activity could play out for the first half?

Sure. We have nine rigs on term contracts -- this is Philip. We have nine rigs on term contracts at the end of the year. We have one rolling off in the first quarter, three rolling off in the second quarter and one in the third quarter. And the rest of the contracts go through the end of the year or into 2017.

Okay. So nine rigs on term and then the remaining four would be on well-to-well spot contracts?

That would be correct, yes.

Okay. And then on 2016 CapEx, assuming no new ShaleDrillers, I just want to make sure I heard you correctly when you said $8 million to $9 million in long lead time items and then $2 million in maintenance CapEx?

That's what we're looking at, yes.

Okay. So definitely under $15 million if we don't see any ShaleDrillers. Well, thank you, that's it for me.

And our next question comes from Connor Lynagh of Morgan Stanley. Please go ahead.

Just wondering if you can give us some color on the extension and the new contracts. Are these new customers, repeat customers? Obviously, with the extension, a repeat customer, but more on the new signing. And how should we think about what kind of customers these are -- majors, midcap, private? Just wanted to get a sense of who's signing up rigs.

The additional rig, was an existing customer that was a large private. It was in addition to his -- he added a rig to his drilling program and as -- in light that this call is monitored by our competition, I don't want to get into any particulars because it's still a very competitive industry out there. So it was an existing customer that was a relatively large private.

How we should think about the day rates? Should we assume that your extension and new rig are in that $15,000 to $17,000 range that you identified as the spot market?

Yes and we set the low number at $15,000. We have seen some extensions or farm-outs from some of our competition that have been in that $15,000 level. That's the reason we stated that number. But we're pretty comfortable that that market is in the $15,000 to $17,000 range from what we've seen.

What kind of rates are you hearing people bringing rigs, like a new contract thing like you guys did? And this is the market, not specific to this contract question. That $15,000 doesn't feel like a real rate to me if that's a farm-out. So where do you feel like the real spot market might be?

Connor, this is Byron. We're only talking about the market for walking pad optimal rigs. There's 100, 125 of them out there. they're probably getting close to 80% utilization. So new contracts are anywhere from the midpoint of that range to the high teens and it just depends on application.

[Operator Instructions]. And our next question comes from James Wicklund of Credit Suisse. Please go ahead.

So you think the market comes into balance or at least hits the 80% mark of pad-type walking rigs in 2016. Translate that for me. What does that mean the rig count is going to do? Does it bottom in Q1 like one company said or what's your outlook on -- progress me through the year.

Okay, Jim. We don't look at the overall rig count too heavily because we don't really participate in that market.

You can just do the horizontal or however you want to do it.

Everything I've heard on previous conference calls from all of our competitors is pretty much in line with what we see. We believe that we're getting close to the 80% mark for the subset of equipment where we participate. I would expect that the rig count as we go into an improving market in 2016 and 2017 probably overshoots its ultimate high as equipment that has less capability is pressed back into work, people begin to build new walking pad optimal rigs which then displace that equipment. So just from a shape standpoint, I'd expect it to begin to ramp, overall rig count begin to ramp, second half of 2016, probably peak out in 2017, everything being equal. And then start to decline to whatever it's going to stabilize at, as walking pad optimal equipment is built and displaces this lesser quality stuff.

Okay. So you're going to be -- the industry is going to be building these rigs coming into 2017?

I think so.

What would you have to see before you would start building a new rig?

One year deals.

A one year kind of deal?

Jim, we wouldn't be building rigs because we expected 1-year deals at $17,000 or $19,000 a day. We'd be building rigs because we expected that the North American unconventional was becoming the swing producer around the world, that we're going through a final phase of the rig replacement cycle and where we wind up with 800 walking pad optimal rigs and a smaller number of remaining equipment. And we're looking at a day rate environment that's back to the historical highs and maybe beyond.

And our next question comes from Jeff Tillery of Tudor, Pickering Holt. Please go ahead.

Not to hear your fleets -- you have more time in the field and greater critical mass. Could you just talk a little bit about the usage of the rigs by the customers? Are you seeing the ability to walk [indiscernible] and the ability to walk over wellheads? To what extent is the equipment that you have being kind of fully used to the capabilities now?

This is Ed. Jeff, every rig that we have operating is on a program that requires it to walk over wellheads and to walk in multiple directions, every one of our programs. We're not on -- none of our rigs are drilling just single-well environments or two-well pads. So we're fully utilizing all the capabilities of our rigs. I would say that if there was one particular aspect of Byron's six pieces which define a pad optimal rig, I think there's more ability for improvement and efficiency with the use of the BiFuel component of that six characteristic points. But everything else is being utilized on every program we're on.

And then more qualitative and maybe go back to the specific example of the rig going back to work, but can you just give us context for what those discussions are like? Is it a customer directly soliciting ICD because they know the qualities that the rigs bring? Or is it more of a tender type environment where a couple of drillers are solicited and then the bid is submitted and then the ultimate rig is selected?

In this particular case, there were a few selective competitors that were contacted among us to determine what the market was. And then the operator came back to us and elected -- and selected us as the contractor to move forward.

And our next question comes from Rob MacKenzie of Iberia Capital. Please go ahead.

Byron, I wanted to kind of ask you to look at your crystal ball a little bit and go beyond your fourth quarter utilization guidance. Since you have some of the rigs rolling off into next year, is it your expectation that those will find follow-on work and/or new contracts fairly shortly after the contracts roll?

Rob, it's a short-term marketing environment or contracting environment. It's multiple wells are 6 months. So while I can't specifically comment on whether we'll see gaps or whether we'll have a saw-tooth nature to our contract, our personal contract environment next year. What I can tell you is there is a -- it's a force of nature, the way the operators are moving toward more capable equipment in this environment which is exactly what you'd expect, economics is a force of nature. And so when you have compelling economic advantages associated with this type of equipment and high-quality crews with very substantial safety records, that's the equipment that's going to go to work. And it's not just us; it's everybody out there that fields walking pad optimal equipment. So where we have 10% or 15% share of the market we play in and other people are larger than us. I think the experience that other people are having -- and we have similar equipment and safety records -- is quite similar to ours. And that equipment will displace legacy equipment and have the best utilization rate in whatever the 2016 environment is. And while I can't comment on whether we're going to seamlessly move or we're going to be extended through the whole year, what I will say is we will be, from a utilization standpoint, we'll be amongst the best performs in the industry on a relative basis.

Philip, I guess my next question is for you. Can you give us the deal for why you made the accounting change vis-a-vis the treatment of the Galata [ph] cost? It seemed to have no impact on cash flow, but would obviously depress your near-term earnings recognition.

Yes, so when you think about the Galata [ph] costs, it's really just gas when we're -- and there's a group of costs there, it's facility costs or some personnel. Those personnel are going to be deployed into our operations to support our operating groups, so all of our corporate groups. But we'll trap this cost separately under GAAP. The distinction is important under our credit facility. Byron had mentioned our amendments. For covenant compliances, costs will, under the credit facility, will be excluded when we calculate the EBITDA and things like that. So there's an important aspect there. And then when you look at our operating costs, our operating costs per day fully burdened, our guidance was $13,500-ish for the fourth quarter. We'll see that go down if we're operating 11 rigs or more next year. We've got idle rig costs; we've got rigs, the cost associated with mobilizing that rig. Those costs will go down and in the 11-rig case, you'd see those costs go down below $13,000 a day and Byron mentioned some other things. And with the support from the Galata [ph] yard, we'll see our OpEx per day numbers -- if we get back to 11, 12, 13-rig utilization, we'll see those get close to $12,500 a day. And we're keeping the Galata [ph] costs in a separate bucket.

All right. So the Galata [ph] costs would come in in the other cost line, correct?

They would. We haven't decided how we're going to do it, but it's important when you think about it, how we look at it for covenant compliance and things like that, that bucket of costs is distinguished.

There's no change in the cost structure. What's happened is we went from an environment where we were planning and ramping to build 10 to 12 rigs a year to a lesser environment. And then that lesser environment where we have intermittent use of the yard, it doesn't get capitalized onto the rigs. It's split out and this is an accommodation to you guys so you can see what it is and understand what the cost is, how it flows through. But it's nothing in terms of any change in our true cash flows.

Right, I understand that. Thank you. So in terms of obviously rig operating days, you had a boost from the 212 going to work. I think you're guiding, going forward here, continued growth in rig operating days. Have we seen, at least for ICD, the bottom in terms of utilization?

I don't know and again, if we had 1 to 3 year contracts, I'd tell you yes because they're multi-well or 6 months. I can't answer that. And I'll just revert to the early answer where the economic forces are pulling this and similar equipment with good crews and good safety records back to work for obvious reasons, because we're bending the cost curve of our clients relative to other equipment. And so we will -- I don't know if it'll be the bottom, but it'll certainly be the best or one of the best.

And my final question I guess is a tough one still. Tax rate, I think you guys zeroed tax benefit or cost in Q4. How should we think about that in 2016 at this point?

I think they're going to be de minimus. That's a loaded question, but it's really just going to be Texas margin tax. and with the way we're calculating it now, I don't think they're going to be meaningful at all. So I would say de minimus in 2016 going forward.

[Operator Instructions]. And our next question comes from Mark Bianchi of Cowen. Please go ahead.

I was curious, Byron and maybe Ed, you mentioned the $15,000 to $17,000 range, maybe $15,000 kind of being not a real rate. So something a little bit above that is perhaps a floor here? I'm curious if that is, in fact, your thinking, what's really driving that? What gives you confidence that will bottom out kind of at these types of numbers?

Mark, this is Ed. I think over the past few quarters when we have been questioned on our conference calls about what is the spot market, we have continually said there really isn't a spot market out there to relate to or to use as a metric to determine what the spot market rates are because there were so many farm-outs and a number of things. I think we're starting to see some -- it gives us some clarity more of what the spot market is going forward and that's the range that we have -- our market intelligence has given us as to what our competitors in this particular class rig are beginning to look at as what they're willing to put rigs to work for and bring them out of stack status. And that's the reason we determined that is the range. Is this the bottom? I was guilty in May of this year of saying that we've hit the bottom. And then all of a sudden, it was China and Greece and name your poison. And this market collapsed and the price of commodity went below $40. So that's really you guys' job; you tell me what the price of commodity is going to be going forward. And I can tell you if the bottom's hit. And I'm not picking on you, Mark, [indiscernible]. That's really about all the analysts, but I really -- other than seeing what our competition is doing, that's what we've reported in this.

And Mark, I gave you some thoughts of how to look at 2016 from a cash flow standpoint. The backdrop to that is we go sideways from here. So if the market -- if the oil price market improves and the operating market improves, hallelujah. And if we drop another circle of hell, then we have to readjust. But so the guidance we're giving you assumes that we progress into next year from an operational standpoint flat with where we're now which is what we expect right now as well. So but that's the context around the answers we've given.

Maybe just another topic that's widely discussed among investors and companies is this concept of improved drilling efficiency. We've seen a lot of E&Ps talk about not needing as many rigs to complete the same amount of wells that they had planned in their drilling programs for this year and into early next year. I get that part of that is probably dropping some lesser capable rigs and focusing on the higher end rigs, like what you have. But some of that could be perhaps better understanding of the geology, directional drillers having more experience with drilling the same well over and over again. So just curious to hear your thoughts on that, what you've seen for Independence and where you kind of see that going?

We definitely believe that that is the way the industry is going, is moving. And I think the reason we were able to bring out 204, it was a direct result of the efficiencies the customer has seen over the past 8 months with one of our other ShaleDrillers. So there's no doubt that the industry has become a lot more efficient. Now, I will contend that there's more -- and I've already given you one indication of where there's some efficiencies embedded into the system that hasn't been realized. And that's through BiFuel, but there's a number of others. And I can tell you several of our customers have put together what they call efficiency teams to try to determine where are the efficiencies or the low-hanging fruit that haven't been reached and the efficiencies that can be realized by working in a collaborative fashion to work together to a common goal. There's no doubt that the industry has transitioned from an industry that looks and exploits hydrocarbons to one that we're in the well bore manufacturing business. That's essentially what we're doing. And so I'm very, very bullish that this is an industry that's moving towards more efficiency versus less efficiency.

Mark, there is another thing just to think about. Historically, DC, mechanical rigs were [indiscernible] at the top of the well that they were a crane basically. When you start talking about AC programmable equipment, you've got a piece of equipment that's part of the big data value collection chain as well as a piece of equipment that can be part and parcel of a more holistic approach to selection of bits, mud, solids, control and so on. And so to the extent that that data and that capability is integrated into not only the data collection, but the data analysis and you can consistently pick the best bits, the best flow rates, to get hydraulic force power at the bit face, to maintain turbulent flow in the back side, keep the hole clean, to not damage formation, to drill gauge holes that give you good cement jobs, that allow you to produce at higher IPs with less drawdown and you minimize damage at the well bore, the whole industry is going that way. And AC programmable computer-controlled rigs are part of that process. I don't know how that's going to play out, but we're beginning to get inquiry from clients along those lines.

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

I just wanted to clarify one thing real quick. Can you just reiterate what you said about the day rate and cash margin expectation as you move forward into the fourth quarter?

The fourth quarter, the day rate guidance was $23,100 to $23,400. The overall, fully burdened OpEx per day of $13,000 -- is $13,400 to $13,600.

And then Byron, you mentioned earlier building -- a new build would be predicated on a 1-year contract. I guess that's a far cry from the 3-year contracts that were being awarded a few years ago.

Yes.

And quite frankly, with all the available rigs in the marketplace, I'm surprised that any E&P company would offer any contract at this point. So can you give me some color on what -- is that how -- are you expecting 1-year type contracts? Are you expecting this basically to be a free for all for a period of time?

I think the market that we participate in which is the walking pad optimal market will get to 80% of effective utilization of the available rigs sometime next year. And we'll see what happens. The rest of the market is probably going to be a free -- in analyst commentary, I've seen blood bath, free for all. Pick your adverb; don't know. But that's not the market we play in, Kurt.

Yes and then the market you play in that you suggest would be at 80%, potentially 80% utilization at some point in time next year, Byron, do you think that even when it's at 80% utilization, it's still going to be a well-to-well type of deal instead of a term contract type of situation?

I don't know, but historically, that's been the knuckle point where you begin to see extension of term and not necessarily day rate, but extension of term. Because there -- all of a sudden, you want one and you can't necessarily get it or you may have to wait. It begins to tighten up a little bit and that results I think in term extension. Ed, is it -- has that been your --

Kurt, I've been in this business for 40 years. In every market correction I've been told -- and this is my sixth -- every one I've been told is we'll never see term contracts again. And inevitably, we always get to 3-year and greater term contracts. I remember being told the day rates will never go over 10; we went to 10, then 15, then 20. Then, well, it's never going to get over 25 and then we went to 30. So and those were the times when the market -- when the rig fleet was at 2,500 rigs and the rig count was breaking 1000 and we started seeing term contracts. The rigs of choice, the rigs that perform, the rigs that provide value to the customer at the rig site will get term contracts. It happened in every market correction and I've see it for the past 40 years. There's nothing that tells me that this is going to be different than the previous ones. We've had just as many rigs available over previous cycles as we have to today. I might be wrong. You may be able to one day, Kurt, tell me, well, Ed, you missed it on this one. That's quite possible, but I'm betting that it's not.

And our next question comes from Thomas Curran of FBR Capital Markets. Please go ahead.

Byron, over the course of the call, you've given a very helpful synopsis of your industry outlook. I did want to clarify just one point on it though. Where would you estimate the pad optimal industry-wide utilization level is now? I know you've talked about how you think we'll cross that 80% threshold at some point next year. But where would you estimate we're now?

Tightening, because we're seeing day rates go up and we're seeing term extend, even though it's short. And I can't give you a number beyond that. I think there is 100 to 125 of rigs of this type out in the field. I think Kurt, the previous caller or the previous analyst asking questions, has done some work on that. And I think you'd have to check with him, but I think it's 125. So I think it is tightening, not yet at 80, but tightening.

Yes, I was closer to 150 myself, but both coming up.

Pick a [ph] number, yes.

Let me turn towards more of a bottoms-up approach. Appreciating that customer -- visibility on your customers' plans is about as low as it gets at this point heading into budget-setting season. But do you know among some of your longest, biggest fans if you wanted to, could you place even more rigs with them, even if they haven't finalized their overall CapEx budget, just based on your relationship? So whether it's a Pioneer or a Parsley, within your current operator base, are there operators that you could place several more rigs with? And you're just opting not to because you would prefer to maintain some minimal level of diversification? Or if need be, is that an option available to you?

I think there are two drivers of that particular question that you have. One is you have contracts that are still maturing that have still come -- that are still running their course. And so they still have contract liabilities and commitments they have to honor. And so they're not going to add any equipment until they get down to what they believe is a rig count that they can officially operate within. And then what we've seen and the discussions we've had is that at that point, they'll start high-grading. So the first thing is you have to have contracts to begin to roll off. And that should be taking place after the first of the year because most operators will contract the majority of their rigs in the beginning of the year right after budget season. Secondly, our customers are just coming off their re-evaluations of their assets and are putting together their budgets with -- considering their vision on what the price commodity's going to be over the next 12 months; what are their hedge opportunities going to be; what are the price decks going to be; what's their borrowing base going to be? So typically, we'll also say this. They'll be going through their budget process and I don't anticipate much activity taking place through the end of this -- of the -- this year, the fourth quarter and really, into January. If they're going to be ramping up any program or increasing their CapEx or maintaining their CapEx, they won't be making their plans to do -- finalize through January, mid-February. So I don't anticipate much taking place between now and really the end of January.

But philosophically, if the opportunity were available, is there any reason you wouldn't be willing to place four, even five rigs or more with a single operator?

When we finished the IPO last year, we were in contact with one operator who wanted to take all of the production available to us at this facility last year. Now, things have changed. The conversation we had with that operator was along the lines of dedicating one of our three pads to their production and then continuing on our more diversified production on the other pads. We certainly would not have any problem with engaging in a joint venture, a partnership, anything of those lines, that resulted in a substantial market share with a particular partner under the right contract conditions.

Okay. And then one for Philip, on the amended credit agreement, for the rig utilization ratio covenant, the new requirement of 60% utilization for 2016, 70% for 2017, how is utilization being measured for that covenant?

Kind of the way we would report it. The decommissioned rigs which we haven't classified any rigs as decommissioned at this point under the credit facility, but your 200 series rigs that are under upgrade potentially, we could classify as decommissioned as would be excluded from the calculation, if we needed to do that. But right now, we don't see that as a headwind.

Okay. So it would be on a marketed basis consistent with how you reported this quarter?

Yes.

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

No closing remarks other than to thank our investors, thank our employees, thank our clients. We look forward to working with all of you in the future and on speaking with you with the end of the fourth quarter and as we move into next year. Thank you.

And 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.