Good morning, and welcome to Independence Contract Drilling's 2014 Third Quarter Conference Call. Just a reminder, today's call is being recorded. [Operator Instructions] At this time, for opening remarks and introductions, I would like to turn the conference call over to Philip Choyce, Senior Vice President and Chief Financial Officer of Independence Contract Drilling.

Good morning, everyone, thank you for joining us today to discuss ICD's third quarter 2014 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 in our documents on file with the SEC. Additionally, we refer to the non-GAAP measures during the call. Please refer to the earnings release of our public filings for a full reconciliation of EBITDA and for definitions of our non-GAAP measures. With that, I'll turn the call over to Byron.

Thanks, Philip. Good morning, everyone, and thank you for joining us. Following our typical format, I will review the quarterly highlights and update you on our outlook going forward. Phil will then review the financial highlights for the quarter and our forward guidance. We'll then take questions from call participants. This was another great quarter for Independence Contract Drilling. We realized record revenues, gross margin and EBITDA. On a sequential basis, we increased our rig operating days by 23% since the second quarter, our margin per rig operating day by 8%, and contractual utilization remained at 100%. Our crews, operating personnel and our rig equipment continue to operate at industry excellent standards and exceed our customers' expectations. When I look at the operating metrics that our customers care most about and ICD's delivery on those metrics, I could not be more pleased with the value proposition we are providing customers. Across our fleet during the quarter, our operating up-time was 99%. Our TRIR, which is a standard measure of safety in the industry, was well below 1. All of our 200 Series rigs operated on multi-well pads and 4 of our rigs were utilizing their BiFuel capabilities. Independence rigs continued to demonstrate their superior, fast-moving and drilling productivity characteristics. On pad, the time between release for a completed well to spud or the commencement of drilling on the next well is 3 hours or less. In an exciting development during the quarter, we walked a ShaleDriller 200 Series rig, which we physically separated with adjacent drilling pads for our customer. This was an approximate 600-foot walk between the 2 pads and was completed in 12 hours, a substantial reduction in nondrilling but contracted time for the operator, and this has the potential to introduce a new productivity paradigm in fields with adjacent pads that historically required complete rig moves between those pads. Our rigs also continue to set drilling records. During the quarter, an ICD ShaleDriller built the curve from vertical to horizontal and drilled the entire lateral section of the well, a total of 15,000 feet measured depth in less than 100 hours, which set a new record for that operator. Our rig construction operations also performed exceptionally well during the quarter. We completed our 10th ShaleDriller rig and delivered the rig on time and on budget. That rig began operating immediately with exceptional uptime performance. Subsequent to the quarter end, our 100 Series to 200 Series conversion rig began operations on time and with exceptional uptime performance. Also subsequent to quarter end, we signed multi-year contracts for rigs 211 and 212, which will begin operation during the second quarter of 2015. In summary, I couldn't be more pleased with the execution of our strategy and at the pace with which we're delivering on our goals. At this time, all 10 of our rigs are currently working on or dedicated to long-term contracts and our next 4 new build rigs are contracted. We are operating in the busy Permian Basin, although as mentioned in our prior call, ShaleDrillers are ideally suited for work in all the basins in our target market, Texas as well as the contiguous states of New Mexico, Oklahoma, Arkansas and Louisiana. In fact, our most recently signed newbuild contract is for operation in East Texas. There's been a lot of industry debate over recent commodity price volatility and its impact on drilling programs in 2015. If the current environment of lower commodity prices persist, it's pretty reasonable to expect our clients to reduce their 2015 capital spend programs, release lower performing equipment and to pressure contract drilling day rates. In fact, some of our clients have informed us of anticipated capital spend and rig count reductions, but we won't have a complete picture of 2015 E&P capital spend until sometime in the first quarter. This is nothing new in the industry. And as ICD is well positioned in a strong commodity price environment, we are also well positioned for the inevitable air pockets. We are a pure play, providing a top-tier pad optimal differentiated rig that accelerates our clients' production and cash flows on their most financially impactful assets. Our uptime and safety records are outstanding. Our clients have large, liquid balance sheets, pay for quality and drill-through cycles. And as a modular manufacturer of our rigs, we can accelerate or decelerate our new rig build tempo very quickly and at a very low cost. Also, as Phil will detail later in the call, our balance sheet is very strong, and we've expanded commitments under our credit facility, expanded our liquidity base and removed some restrictive covenants. At this time, our net debt is 0. We continue to talk to well-capitalized operators in our target market for the remainder of our rig build scheduled in 2015, with demand for rigs in excess of our build capacity. At this point in time, everything that we're seeing from a contracting perspective indicates we will continue to contract our rigs. In fact, we are hearing that the most active operators in our target markets are emphasizing horizontal drilling and releasing equipment only suited for vertical drilling. With the majority of the U.S. fleet comprised of legacy equipment, 60% of the existing U.S. rig fleet with mechanical or DC drives, and almost 50% of the fleet operating at 1,000-horsepower or less, the trend to a greater share of long, lateral, highly complex horizontal completions will exacerbate the existing industry-wide shortage of AC rigs. In addition, the continuation of the existing trend to pad drilling and the adoption of larger pads by our customers will further drive demand for ICD ShaleDriller high-productivity pad optimal rigs, rigs that have omnidirectional walking capabilities over raised wellheads and are BiFuel. With that, I'll hand the call over to Philip to discuss third quarter financial results and our forward-looking guidance. Phil?

Thank you, Byron, and thanks, everyone, for joining us today. I hope you all had had a chance to see the press release we issued yesterday evening. Before we get into the details on the third quarter, I want to summarize a few housekeeping items relating to our IPO, which are completed in August. We issued a total of 11.5 million shares realizing net proceeds of approximately $117 million after deducting underwriting discounts, as well as capitalized offering costs. Our total issued and outstanding shares following the offering are 24.6 million, which included restricted shares issued in connection with awards granted at the IPO. Now moving on to the results for the third quarter. During the quarter, we reported the net loss of $1.4 million or $0.07 per share, included in net loss during the current quarter are the following items not derived from normal operating activities: First, we recognized an expense of $611,000 or $0.03 per share net of tax, related to a noncash charge associated with an increase in the estimated fair value of our warrant that was originally issued in March of 2012. For purposes of the third quarter, the share price utilized for value in the warrant was $11.75 per share, which was our closing price at the end of the quarter. When we value the warrant at the end of the fourth quarter, we will use the ending price -- share price on December 31. The warrant expires on March 2, 2015. The post-IPO strike price for the warrant was $11.37. Second, we recognized expense of $700,000 or $0.03 per share net of tax related to our initial public offering. The costs related to acceleration of stock-based compensation at the IPO as well as costs associated with predecessor audits and legal and consulting costs associated with IPO corporate restructuring activities. Excluding these 2 items, we recognized a net loss during the third quarter of $300,000 or $0.01 per share. During the quarter, we recognized adjusted EBITDA of $5 million. Details on our calculation of adjusted EBITDA are included in the tables to our press release. Now moving on to our revenues. During the third quarter, we ended the quarter running 9 rigs, including 1 new build that entered our fleet during the quarter and had a total of 779 rig operating days, which equated to 100% utilization rig compared to 462 rig operating days and a 98.9% utilization rate during the same period a year ago. On a sequential basis, our rig operating days increased by 23% compared to rig operating days in the second quarter. Looking forward at the fourth quarter, our rig operating days will increase as a result of the new builds that entered our fleet during the third quarter as well as our recently upgraded rig that commenced drilling operations in October. We currently estimate our rig operating days during the fourth quarter will range between 910 and 920 days. During the quarter, our revenues totaled $19.1 million. On a revenue per operating day basis, which excludes pass-through revenues, our revenues increased to $23,264 per day in the third quarter compared to $21,447 per day during the third quarter of 2013 and improved 6% sequentially from the second quarter of 2014 revenue per operating day. Improvements were not only driven by increases in contractual day rates but by exceptional operating performance in the field during the quarter. As Byron highlighted in his remarks, our overall fleet uptime was approximately 99% during the quarter. On the cost side, during the third quarter of 2014, excluding pass-through costs, our costs were $13,191 per day compared to $12,437 per day during the third quarter of 2013 and $12,740 per day during the second quarter of 2014. These costs per day include all of our allocated costs. Compared to prior quarters, our costs per day during the quarter were slightly higher than what we had been experiencing. Breaking it down, approximately $200 per day of the sequential increase relates to increased allocations associated with additional operating support personnel to our drilling superintendents and maintenance personnel, which we had brought on ahead of our rig build plans. As our rig operating days increase during the fourth quarter, these costs will decrease on a per operating day basis. The other $300 per day simply relates to additional costs incurred for supplies and maintenance, which can be lumpy between quarters, especially with the fleet of our size. On a margin per day basis, we saw continued improvement compared to both the third quarter of 2013 as well as sequentially. During the third quarter of 2014, our margin per operating day was $10,073 compared to $9,010 per day in the third quarter of 2013. Sequentially, our margin per day in the third quarter improved $787 per day compared to the second quarter 2014 margin per day of $9,286. Looking forward to the fourth quarter, we expect to see continued sequential improvement margin per day. Overall, our contractual day rates will increase in the fourth quarter and the overall level of margin improvement will be based upon our overall operations and uptime during the quarter. We expect margin improvement to most likely be in the $200 to $400 per day range. As we have highlighted previously, we utilized our rig crews to assemble our new ShaleDriller rigs, and these crew costs are capitalized as part of the new rigs' cost. However, we typically retain key rig personnel for our new rigs prior to the construction process. We exclude these preconstruction personnel expenses from our operating costs per day metrics. During the third quarter, these preconstruction operating costs associated with these additional personnel were $700,000, which compared to $500,000 during the second quarter of 2014. We do expect the reduction in these costs during the fourth quarter. During the third quarter of 2014, our selling, general and administrative expenses were $3.6 million, including the aforementioned one-time IPO-related items. Excluding these one-time IPO related items, adjusted SG&A expenses were $2.9 million, of which $800,000 related to noncash stock-based compensation expense. This compares to $2.1 million of SG&A costs during the third quarter of 2013, which included $500,000 of noncash compensation expense. On a sequential basis, our SG&A, excluding the one-time items mentioned above, increased 40% compared to total SG&A during the second quarter of 2014. The increase was a direct result of about half quarter of post IPO run rate costs. On our depreciation and amortization expense. During the quarter, our expense was $4.2 million, which compared to $2.3 million during the third quarter of 2013 and increased $315,000 sequentially compared to the second quarter of 2014. The sequential increase was related to additional rigs entering the fleet during the second and third quarters. With respect to interest expense, we recognized $482,000 in interest expense during the third quarter associated with borrowings under our credit facility prior to repayments following completion of the IPO in August. We also have ongoing costs associated for unused line fees as well as noncash interest expense associated with amortization and deferred financing. Moving on to taxes. During the quarter, we recorded a tax benefit of $352,000, which equated to an effective tax rate of approximately 20%. I will point out that the expense associated with our warrant charge is not deductible and is a permanent difference for tax purposes, which reduced our overall effective tax rate associated with the tax benefit during the quarter. Absent the warrant charge, our effective tax rate would have been approximately 31%. Moving on to our balance sheet and liquidity. At September 30, 2014, we had cash on hand of $13.2 million, no debt and nothing drawn on $125 million revolving line of credit. During the quarter, we accelerated down payments for long lead time items for 5 rigs. These down payments were approximately $17 million during the quarter. At the end of the third quarter, we estimated there were approximately $9 million to $10 million of cash outlays for capital expenditures net of vendor deposits already incurred. We're required to complete construction activities on our upgraded rig delivered in October as well as the rigs scheduled for delivery in the fourth quarter. Subsequent to the third quarter, we did amend and restate our credit facility. The amendments increased our total commitments under the facility by $30 million to $155 million. The amendments also amended various covenants to bring them in line with our status as a public company. Also importantly, the amendment allows us to incur additional $20 million of equipment financing indebtedness, if we so desire, related to the construction of additional rigs and purchase of additional rig equipment. We believe these amendments position us ideally for next year with significant liquidity to maintain our base build of 7 rigs next year, accelerate our build cadence if market conditions warrant and to take advantage of opportunities if market conditions are not as favorable. With that, I'll hand the call back to Byron for closing remarks.

Thank you, Philip. I don't have any further remarks. So operator, would you open the line for questions, please?

[Operator Instructions] The first question we have comes from Connor Lynagh of Morgan Stanley.

I was just wondering about the new contracts you guys signed this quarter being after the third quarter. How do the day rates compare to the contract you signed during the third quarter?

Sure, Connor. This is Byron. What we're going to do is talk to you in terms of our fleet average contract revenue and our fleet average margin. And so if you look at the contracts we've signed and our existing contract backlog, you'll see that just as our revenue per rig, our contract day rate per rig increased Q2 to Q3. You can expect it to increase Q3 to Q4, and Philip can give you guidance about what that range should look like. And as well, our gross margin per rig based on what we see and what we've signed will also increase Q3 to Q4 as it did Q2 to Q3. So that's how we're going to answer that type of question going forward.

That's fair. I guess, all I'm asking is you haven't seen any signs of day rate pressure at this point. Is that correct?

No, I think day rate pressure is coming. So yes, right now, it's a mixed bag. I don't think you're going to see a lot of granularity until our E&P customers go through their budgetary cycle, so sometime in Q1. But the conversations we're having reflect lower commodity prices. And in a lower commodity price environment, people are going to be talking about lower revenue than higher day rates.

Okay, fair enough. And the 2 new contracts, were those with existing customers or new customers?

One was with existing -- we drilled for both of these customers before, a slight better way to answer it.

Next, with Klayton Kovac of Tudor, Pickering, Holt.

So you mentioned taking advantage of the market if it's not favorable. Does this mean M&A or opportunistically repurchasing stock, for instance?

We have no plans to repurchase stock, and I don't think that would be a good use of our capital at this point. When you consider the demand for our rigs and the fact that we'll be a consumer of capital for some time, given our plans to build out our fleet, so that's not on the table. And from an M&A perspective, over the course of time, people bring various things to us. And so we've seen everything that's out there that, I think, that everyone else has. And we've -- there's nothing that we have seen that would not compromise the strategic underpinnings with the formation of this company, which is a pure play, newbuild fleet, pad optimal and so on. So M&A is off the table as well. I think what Philip was referring to in his comment was that as a modular manufacturer, if things got bad, we have the ability to decrease our build tempo as well as increase our build tempo in an up market. And we would -- we may -- in that type of an environment, we may decide, for example, to upgrade our 2 100 Series rigs to 200 Series substructures in that environment. So I think that's what he was referring to, but no buyback and no M&A.

Okay, okay. Great. And then just as a follow-on, you mentioned one of the recent new build contracts was for work in East Texas. Are you starting to see more demand come out of that region? And should we expect more rigs to have there, more new builds?

Yes, Klayton, this is the Ed. We're looking at a lot of different geographical areas across our geographic market, which is from Louisiana to the east, New Mexico to the west, Oklahoma, Arkansas to the north. We've had some interests in both Louisiana in that brown, dense area at Louisiana, east Texas, Oklahoma, Texas Panhandle, and we're going to take -- rig is really mobile, and we're going to take advantage of the best opportunity that's presented to us by our customers.

Next, we have Marc Bianchi of Cowen.

I guess, first question, could you just address the rollovers that are upcoming, remind us what you've got that's rolling maybe at the end of first quarter -- end of fourth quarter, end of first quarter and then beyond?

Sure. We got 5 rigs that will come up for renewal in the first half of next year. My expectation right now is that those will be recontracted, but that's not for certain. Two of them are 100 Series rigs, the other 3 are 200 Series rigs. Every one of them has been noted by the respective customer as some of the best-performing rigs in their fleet. And again, in a lower commodity price environment, I think what you'll see -- you can expect to see drop of slower equipment, lower performing equipment. So right now, I would expect them to recontract, but don't know that. Ed, any further color you'd like to add?

No, no. I would agree with that. We stay in close contact with our customers regularly. And part of that is to ensure that the value we're providing them is meeting or exceeding their expectations. And part of providing good value to our customers is excellent communication between us and our customer. And it's throughout the organization, from HSE personnel, from our support personnel, from operations and from marketing, we're touching all the levers within our customer to ensure we're delivering the value that they want. And so we're pretty confident that on a competitive basis, we'll stand up to any of our competitors out there.

No concerns, Marc. High rolls, no concerns right now.

Got it. And then maybe this is one is for Phil. On the $200 per day of cost increase that was related to, I guess, to paraphrase, adding some headcount ahead of new equipment that's coming, how long would it take to kind of absorb that? When will we start to see that come back?

I think it'd come back in the first quarter, and we'll get some of it back in the fourth quarter. So maybe half in the fourth quarter and the rest of it in the first quarter. And then it will come back again. It's going to be lumpy as we bring these drilling superintendents and maintenance guys on. We'll typically bring them on ahead of our rig build. And so you're going to see a lot of rigs are going to start coming out at the end of March, and then in the second quarter and then on. So we'll see it probably ramp up just a little bit there in the second quarter next year.

Okay, okay, good. And then maybe is that the reason for the $200 to $400 range from third quarter to fourth quarter, if we're looking at margins?

Look, if you're looking at sequential margin improvement, we're definitely going to have contract improvement on our day rates. It will -- how much of that goes to the bottom line will depend on our uptime, which is exceptional in the second quarter -- in the third quarter. So we'll see how we end up at the end of the third quarter, and then we -- and that would assume $100 a day improvement in costs and things like that compared to the third quarter.

[Operator Instructions] Next, we have Rob MacKenzie of Iberia Capital.

Byron, I guess, I got a follow-up for you on the new contracts on 211 and 212. Can you give us a feel for the term on those contracts? Because if I assume those work through all of next year, at a minimum, I see that even in a weak environment, you guys are roughly 17% locked up for next year at this point.

Yes. Let me give you -- I think that's a correct conclusion. And without getting into the details of the contracts, which I'd like to avoid for competitive reasons, from a strategic standpoint, it's our explicit strategy to favor the term over day rate. So we will always look toward term contracts. And if you do the math, and you can run this yourself, you'll find that even if you take a higher day rate in a shorter-term contract, the downtime associated with moves and with time between contracts, if you assume you have to change 4x a year, you need a -- you need at least a $2,000 a day higher day rate in that shorter contract to breakeven with a lower-priced term contract because of the costs that are associated with shorter terms. So strategically, you'll see us favor term over day rate. And I think that will result in, even though the nameplate day rate may be a little bit lower, better financial results.

Okay, great. And coming back to the rigs that are rolling off contract in Q1, I guess, 101, 103, 201, how do you characterize where you stand in terms of renegotiating those with the existing operator or new operators?

Sure. We constantly are in contact, as Ed said, with our existing client base in daily communication. Obviously, our marketing group is talking to other interested parties in that equipment, but we've been notified by the folks that are currently contracting that equipment that our rigs, if not the best, are among the best in their current fleet. And we haven't entered into detailed negotiations at this point. But I have no -- I would expect them to continue with the current -- their current operator. And if we discover sometime early next year that, that's not the case, I'm confident that we've got other people lined up behind who will take that equipment.

Okay, great. And I guess, one more, if I may. You talked in the press release about CapEx in the fourth quarter being $9 million to $10 million for the remainder of 2014 delivery. Can you bridge us the gap for all the CapEx expected in Q4? And has your CapEx budget changed for next year at all?

Our CapEx budget has not changed for next year. The -- how much the additional CapEx that we'll make in the fourth quarter above the $9 million and $10 million will be for those first couple of rigs that come out. You might add another $10 million on for that, for the rig that comes out on the first quarter, and we'll bring some other components then for the other 2 rigs as well potentially by the end of the year. So maybe $10 million. There's a lot of timing when you're getting around the end of the year on when the equipment arrives.

Next, we have Tom Curran with FBR Capital Markets.

Byron, as you're making this transitioning to the new negotiating environment, do you sense that the far greater emphasis you place on term overrate compared to some of your competitors has or could provide you with an advantage in being able to still secure however much term is going to be continued to be offered out there?

Rob -- Tom, excuse me, Tom. This is Ed. I mean, us favoring term, we just didn't invent that. I mean, this is -- our competitors understand the economics of this business very well as well. And I'd say everyone is going to be pushing for both term and day rate, and both will be dictated to by the market. I think the one thing that will determine or give us a competitive advantage would be our continued performance and value proposition at the well site. With that in mind, I think that we are positioned with the quality of our equipment and the quality of our operation. And particularly, in the market that we're in, in the -- mostly in the Permian, gives us the greatest opportunity to recontract our rigs from a position of strength in this market environment. But the market is going to dictate the length of term and the length -- and how much the day rate is. The other thing, I think, that we're very focused on and cognizant of is that the Permian still delivers excellent return on investment for our customers as opposed to some of the other geological place in the U.S. And as long as we have that position, I think that's favorable for us. If -- because one of the things that's coming out of this budget process we're going to be looking for is where our customers, if any, if there's any shift in investment and to geographical areas, which may require us to relocate assets. That's a key point. And I think the Permian, so far, has shown that it has still an excellent investment opportunity for our customers in a retracted commodity price environment.

I guess a follow-up would be then, if and as you start to see day rates decline, irrespective of what's happening with the term associated with them, are there certain thresholds at which you already know there are customers, be it in the Permian or elsewhere, that you're negotiating for, that they're using an SCR, maybe even so mechanical rig. But if the day rate for ShaleDriller hit a certain level, they would not only be interested, but be interested and willing to take it for nice terms?

The answer -- short answer is no. And the second thing to think about is when you're talking about the comparison of ShaleDrillers to slow-moving DC rigs to mechanical rigs, you have to take into account that you're not comparing apples to oranges, and it's not just a dollar-to-dollar comparison. You have to think about -- we're talking about drilling 16,000-foot laterals for our clients now. You have to worry about open-hole time. You have to worry about hole collapse and how long that hole is exposed to drilling fluids. You have to talk about -- you have to make correction runs. You have to talk about straight holes. We just built and drilled this 15,000-foot lateral 100 hours, okay? That's a differentiator between us and DC equipment and mechanical equipment, that isn't really a dollar-to-dollar comparison. So I think that there's 2 things going on. There's an economic obsolescence of some of the older equipment, but in addition, there's a technological obsolescence as we go to these extreme laterals, and that you don't just decide at a certain breakpoint you're going to use lower-quality equipment because it just doesn't compute. So I think it's a more complicated question than you've asked. And I think it's a case-by-case discussion with our clients that depends a lot on the geologic and mechanical risk associated with their drilling programs.

Okay. I was actually asking, Byron, if at a certain lower day rate for one of your rigs, a customer who's currently using, say, an SCR rig might now be interested and also be interested and willing to offer you term?

Look, I don't think the conversations go that way. And again, we're not competing on price. So we've never gone out and competed head to head on price with people we're competing against. It's just total value proposition that Ed spoke of it's what we're offering. And so there's much more complicated conversations. Ed, I think you've got some...

Tom, let me add one other thing to this. It maybe give you a little more color. From the previous cycle, ICD was just created. We didn't have any market recognition. So that posed a real challenge to us as a company. We've had now a cycle that has gone through where we've had some time to show our value proposition and what we can provide to our customers. So we're beginning to reap the benefits of market recognition that we didn't have previously. So now we have some data and history to where we've shown that we've executed what we've said we were going to do. That, I believe, brings us an advantage to the table and puts us in a stronger position than we were the last cycle. So I think sometimes, that is overlooked, wherein previously, we were still telling our story but didn't have anything to back it up. Now we can back it up because talk is cheap. It's all about execution, and now we've had enough time that we've executed and through our repeat business and contracting with people that drilled through the cycles. These were the times when those people upgrade their fleets and pick the best performers for their drilling program through the down cycles. That, I believe, is what puts us in a better position, more competitive position today than where we were 12, 18, 24 months ago.

Next, we have Kurt Hallead of RBC Capital Markets.

So a lot of pertinent questions already asked, so kind of risk -- run the risk of kind of reiterating some stuff. But you mentioned, I think, in 2 different times, you've got some rigs that are coming up for renewal in the first part of next year, you feel confident about it, but things are not certain. In similar context, you referenced the fact that there's some discussions going on, I guess, at E&P level that would indicate some reduction in rig count. So I guess, I'm just trying to marry up 1 and 2 in terms of reduction of rig count. Do you think that it pertains to those rigs that are coming up for renewal in the early part of next year? And I know you mentioned that you guys get the rig fleet of choice with newer rigs and efficiencies and everything else. I guess I would assume that you're probably at less risk of seeing your rigs remain idle for any extended period of time. So any commentary around that front?

Sure. A couple of things. It's not just the rig, it's the crews, it's the safety record that we have. So we've got good equipment. It's the right equipment, but we also have crews manning the rigs who have a stellar safety record, a TRIR well below 1, which allows us to work for anyone. We've got an uptime of 99%. So those 2 stats are near and dear to our client's hearts, and we're doing exceptionally well. So it's the pack -- again, it's the value package that we offer, and I think that the common sense thing is going to occur in a soft commodity price environment, people will take a look at their existing fleets. They'll high grade. They'll drop off equipment that's less safe. They'll drop off equipment that is lower performing. I think their -- I don't know this, but it's certainly in the conversations we've had with many of our customers. There's a move toward a greater share of horizontal drilling and a lesser share of vertical drilling, which again argues for fast-moving AC equipment. So that -- if that's a -- or a true trend in a paradigm shift, I think that's going to increase the demand for AC equipment, generally fast-moving AC equipment, in particular, and equipment that isn't, those things will suffer. And in that macro regard and also, in the context of what Ed said about being in continuous communication with our customers and trying to team with them as well as being a service provider, there's nothing I see at this point that gives me any pause with regard to our ability to recontract the equipment that's rolling, either with this existing client base or with other people who are in the queue and would be interested if that equipment were to become available.

Next, we have a follow-up from Rob MacKenzie of Iberia Capital.

I wanted to try and bridge the gap on your guidance, and make sure I heard you correctly. I think either -- Byron, you said you expected average daily operating cost to come down about $100 a day sequentially, but you guided up cash margins $200 to $400. Yet when I look at the average of the contracts that I think you've signed, day rates would seem to go up more, leading me to wonder where your consistency is in that guidance.

Yes. So if you look on a sequential basis, where we come out there, if you look at the third quarter, we had a 99% uptime, which obviously, we strive for every quarter. It can move around a little bit as rigs have inspections and things like that. So it's hard for us -- if we have 99% uptime in the fourth quarter across our fleet, then we would have a higher -- then you would have a higher revenue per operating day and a higher margin per day. We're comfortable with the $200 to $400 kind of just right down the middle of the fairway where we can go, but obviously, we're going to try and do better than that.

Rob, it's Byron. As I look at our business, one of the things I look at with the management team is flow-through, and flow-through is incremental EBITDA and incremental revenue. And in the case of Q2 to Q3, our flow-through ratio was higher than our spot EBITDA number. And I think that will be the case in Q4 as well. So we're enjoying a higher -- a larger percentage flow-through than the spot numbers are, and I think that persists through the fourth quarter.

Great. And then could you help us a little bit with expected timing as to when the contract on the 210, 211, 212 might start?

Into the first quarter for 210, and then 211 and 212 would be during the second quarter.

Use a midpoint. I don't -- we don't know what the exact dates are. But I think for modeling purposes, if you choose a midpoint as we get closer to those rigs moving, we can give you just some better guidance, so you can get your rig dates in the quarter correct.

And next, we have a follow-up from Tom Curran with FBR Capital Markets.

Just a few housekeeping follow-ups. Ed, with the vendor advance payments you made on 5 more of the planned 2015 newbuilds, have you now ordered the long lead time items for all of the planned 2015 newbuilds?

This is Philip. We have -- not all of them -- for the last 2, we ordered long lead time items during the fourth quarter, at the beginning of the fourth quarter, so that would be on top of the $17 million that we submit. But we have everything locked up in the Q for 7 rigs next year.

Great. And then with the record you just set in moving one of the ShaleDriller's between pads, covering that 600 feet span in 12 hours, what would that mobilization ordinarily have required time-wise, rough estimate?

To move ordinarily from pad to pad, if it's infill, we couldn't -- we would have to move the entire rig with trucks, and that would typically take us anywhere from 3 to 4 days. And so we are able to do this within 12 hours. So I mean, it's substantial savings to the customer in time. As well, we've cut the trucking costs about 2/3 because now what we're moving is the backyard piece, which are the engines, some mud tanks -- the engines and substructure and mud tanks. But we actually walked the substructure and the mast with some setback from one pad to the next pad. I don't know if that's a record that's been set. It's a record for us. It was the record for our customer. But I have not heard of any other -- anyone else doing that.

Minimum of 2 records isn't bad, right?

That's right, that's right. It depends on who's asking, for the record. Sometimes, 2 is not good enough, sometimes people want 3. So I've always tried to raise the bar on it, Tom.

Understood and appreciate that. I'll close with one longer-term, higher-level question. Byron or Ed, when you think about the next major innovation you'd like to introduce with the 200 Series or maybe that would lead to a 300 Series, what would it be? Technologically, what would be the next major enhancement or innovation you're focused on right now?

Okay, Tom, a couple of ways to think about that. And the first is that in a lot of cases, these things flow from offshore to onshore where you see changes offshore and they show up onshore. Second thing that I can add and then we'll see -- have Ed weigh in, the move -- safety is paramount. So to the extent you can automate operations and take people either off the rigs, smaller crews or get them out of harm's way, that's always on the radar screen. So the jump from DC to AC was a real paradigm shift. I don't see -- if I look offshore as sort of my horizon for paradigm shifts, I don't see one. But what I do see is a continued focus on getting people out of harm's way and reducing the number of people on crews. Ed?

Well, I mean, a drilling rig is an applicator of other people's technology, whether it be bit technology, motor technology, MWD, LWD technology, fluids technology. We're just an applicator. But as these laterals get longer, and most of these wells that we're drilling were wells that we drilled 50 years ago vertically. So we're drilling formations that 6,000, 6,500-foot vertical, and then we're putting these huge laterals in there. If we think about some of the wells we drilled later that were in 10,000, 12,000-foot depth range, put 15,000-foot vertical section in there, we're talking about some massive measured depth wells. And so I can see -- and I think some of my brethren out there who are my competitors also see that we're going to have to -- there's going to be a greater demand for generating horsepower on the surface and transmitting it to the bit hydraulically. So that's going to require more generator capacity on the surface and more pump capacity on the surface to get it to the bit, to drill these longer laterals at deeper depths. That's what I believe is the horizon that we're going to be challenged with. The other thing is -- and I think that my brethren would agree with me on this, we need to get the man out of the derrick because we're drilling these under balanced wells. We just need to get him out of the derrick for safety reasons in case we have a failure of the rotating head. And those were the 2 main things, I would say, that I can see on horizon ahead. Completely getting to automation, I think, is a goal. And I think our offshore brethren are doing a much better job. But the biggest difference between offshore and onshore is that automation is installed permanently offshore on a jackup or semi or platform rig. We have to take that environment and put it in the land environment where we're rigging it down and moving it every 15 days. That puts a stress on that technology that is not in environment that lends itself to being very successful. That's a long-winded answer, but that's where I believe the next horizon is with this industry.

At this time, we're showing no further questions. We'll go and conclude our question-and-answer session. I would now like to turn the conference back over to management for any closing remarks. Gentlemen?

Well, thank you, everyone, for joining us on our third quarter conference call. We look forward to speaking with you throughout the year next year and continue to outperform and to create value for our clients and our shareholders. So you all have a great Thanksgiving.

And we thank you, sir, and you also have a great Thanksgiving. And also we thank you to the rest of the management team. The conference call has now concluded. At this time, you may disconnect your lines. Thank you, and take care, everyone.