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

Good morning, everyone, and thank you for joining us today to discuss ICD's Second 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 and 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 it over to Byron for opening remarks

Well, thanks, Phil. Good morning, everyone. We will follow a common format on our conference call. First, 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 updated financial guidance. We will then take questions from call participants. As this is our first call since our IPO in August, we thought it would be helpful to welcome our shareholders with a recap of who we are, how our business model works and our vision for the future. Also as a footnote, the timing of today's second quarter conference call was dictated by the close of our IPO. In the future quarters, our reporting will conform to typical quarterly timing. Independence Contract Drilling is a fast-growing, pure-play, pad-optimal, land-based contract drilling services provider for oil and gas producers in the Permian Basin. We have no legacy rigs in our fleet. ICD designs, assembles and operates our fleet to fast-moving AC ShaleDriller rigs, which are specifically engineered to be pad optimal. Pad optimal means ShaleDrillers are designed to be very fast-moving and maximize the number of wells our clients can drill per rig year and are ideal for the rapidly increasing use of horizontal drilling technologies. Since 2009, the percentage of U.S. rigs drilling horizontally has increased from approximately 30% to almost 70% today. Not only have more horizontal wells have been drilled, but the horizontal sections are getting longer. In fact, ICD has recently drilled a record lateral in the Permian Basin with an almost 14,000-foot horizontal section. The E&P industry is moving towards pad development of rigs drilling horizontal wells, and pad size is growing larger. Pad deployment of fast-moving AC rigs provides an opportunity for producers to maximize the production profiles and cash flows by drilling more longer-lateral wells per rig per year. But in order to do that, they have to be able to source pad optimal rigs from drilling contractors. That's where we become in. ICD ShaleDriller pad optimal rigs are designed specifically for the vast majority of the U.S. unconventional marketplace and feature 1,500-horsepower computer-controlled AC VFD drives, omnidirectional walking systems capable of walking over raised wellheads, biofuel capability and reduced cycle times in site-to-site moves to minimize truck load requirements. In other words, they're exactly what E&P operators have been asking for and exactly what they need to compete effectively in today's environment. Our pad optimal rigs and skilled crews offer customers a compelling value proposition, allowing them to drill more wells per rig year and accelerate production and cash flow from their most financially impactful and technically challenging assets. On a pad, ICD rigs go from the lease from a drilled well despite the next flow in the series in a matter of hours. Our AC VFD drive rigs provide longer bit life, fewer bit trips and allow customers to drill faster and minimize open-hole time compared to legacy SCR and mechanical rigs. ICD rigs walk omnidirectionally over raised wellheads and are self-leveling. They accommodate uneven drilling locations and misaligned wellbores. Also with our rigs, operators can change between diesel or a natural gas-diesel blend. This dual fuel technology not only lowers ICD's client fuel cost by as much as an estimated at $400,000 on an annual basis, but resulted in greener location with lower carbon emissions. Currently, 4 of our rigs are scheduled to operate on a dual-fuel basis. There is currently an industry-wide shortage of AC-driven and pad optimal rigs. Although the percentage of the U.S. land drilling fleet employing AC drives has increased from 9% in 2008 to about 37% by early 2014, the majority of the U.S. fleet remains comprised of legacy equipment. 60% of the fleet are with mechanical or AC drives, and almost 50% of the fleet operating at a 1,000-horsepower or less. Of the approximate 1,200 rigs drilling horizontally in the U.S., only 49% are being drilled by AC VFD units, meaning that over 600 suboptimal non-AC rigs are being pressed into service drilling horizontal wells. This demand for AC and pad optimal rigs is driving a U.S. land rig replacement cycle, and, we believe, a sustained period of supply-demand imbalance for the kind of rigs that ICD offers. Against that backdrop, it's easy to see why all 11 of our rigs are contracted into the future, and why since the close of our IPO on August 7, we signed a new contract for a 7,500 PSI mud pump-rated ShaleDriller to be delivered in the first quarter of 2015. This contract has a 3-year term, with a day rate in the high $20,000 range, consistent with an environment of improving contracting terms. We are in multiple conversations with other operators for rigs to be delivered in 2015 at similar terms. In addition, we signed a 20-month contract extension with an existing customer since completion of our IPO, with a step function day rate also reaching the high $20,000 range. Although all of our rigs are currently working or dedicated to long-term contracts in the Permian Basin, our target market includes Texas and contiguous states, New Mexico, Oklahoma, Arkansas and Louisiana. We have inquiries and are in discussion with operators in several basins in this target market area. Historically, we've worked in the Eagle Ford and Mid-Continent, and as the company grows, you should expect to see ICD rigs throughout this target market. Our rigs are in high demand, and we are in a strong position to move forward. With the capital we raised in our IPO, we will build 7 new 200 Series ShaleDriller rigs in 2015 and 9 new builds in 2016, and we're looking at opportunities to accelerate those build plants. In other words, we will almost double our fleet next year and compound this rate again in 2016. We are in continuing conversation with well-capitalized operators with the largest drilling budgets in our target market for the remainder of our rig builds scheduled in 2015, with demand for rigs well in excess of our build capacity. In addition, all of our future ICD pad optimal ShaleDriller rigs will be equipped with a 7,500 PSI mud pumps and systems which will accommodate our customers' plans to drill extreme lateral sections. We are also in a solid position from a safety perspective, which is something both we and our customers care deeply about. I'm especially proud that our operating statistics continue to be at industry-excellent levels, with our rolling TRIR below 1, and fleet utilization above 97%, a testament to the quality and training of our rig crews. ICD delivers best-in-class safety and safety management systems, and is one of the only land contractors who is SEMS II compliant. We're excited and ready to deliver on our goals for growth. We were very impressed with the interest expressed from many of you during our IPO roadshow in August, and we're thrilled to welcome you as new shareholders of Independence Contract Drilling. We look forward to seeing you again at the conference later this year. With that, I'll turn the call over to Phil to discuss second quarter financial results as well as our forward-looking guidance.

Thank you, Byron, and thanks for everyone for joining us today. I hope you all had the chance to see the press release we issued this morning. First and foremost, as Byron mentioned, we are very pleased with the results of our successful initial public offering in August. We issued a total of 11.5 million shares of common stock for net proceeds of approximately $117 million, which is net of underwriting discounts as well as other estimated fees and expenses of $2.1 million. We plan on using these proceeds to build more ShaleDriller rigs during the remainder of 2014 and 2015. Looking at the second quarter. We reported net income of $1.6 million, or $0.13 per share. Included in net income and earnings per share during the quarter are the following items not derived from normal operating activities. First, we recognized an income of $1.4 million, or $0.11 per share, related to a net noncash gain associated with the decrease in estimated fair value of a warrant that was originally put in place in March of 2012. This warrant is recorded as a liability on our balance sheet due to its dilution protection features. And we recognized a noncash gain or loss each quarter based on the increase or decrease in its estimated value until such time as the warrant is exercised or expires. The warrant expires on March 2, 2015. Second, we recognized income of $2 million, or $0.11 per share, net of tax, related to the receipt of insurance proceeds during the second quarter, associated with the previously recognized asset impairment. We expect to recognize future gains in subsequent quarters as additional insurance recoveries are received. Excluding these 2 items, we recognized a net loss during the second quarter of $1.1 million, or $0.09 per share, and recognized adjusted EBITDA of $3.9 million. Moving on to our revenues. During the second quarter, we ran 8 rigs, including a new build that entered our fleet during the quarter, and had a total of 636 rig operating days, which equated to 100% utilization rate compared to 420 operating days and a 97% utilization rate during the same period a year ago. On a sequential basis, our rig operating days increased by 4.8% compared to rig operating days in the first quarter of 2014 of 607 days. Looking forward at the third quarter, our rig operating days will increase as a result of the new build that entered our fleet during the second quarter as well as our new builds that commenced drilling operations in August. We estimate our rig operating days during the third quarter will range between 770 and 780 days. Our contract drilling revenues include pass-through revenues associated with cost rebuild to customers, including mobilization costs. Excluding these pass-through revenues on a revenue per operating day basis, our revenues increased to $22,026 per day in the second quarter of 2014 compared to $20,490 per day during the second quarter of 2013 and improved 5.3% sequentially in the first quarter of 2014 revenue per operating day of $20,918. Looking forward into the third quarter, we expect to see continued improvement sequentially in our revenue per operating day. On the cost side, our costs have remained relatively flat on a cost per operating day basis. During the second quarter of 2014, our cost were $12,740 per day compared to $12,768 per day during the second quarter of 2013 and $12,697 per day during the first quarter of 2014. These costs per day include all of our operating costs, including all ad valorem taxes, but exclude costs associated with rebuilds and mobilizations that are passed through to our customers. Looking forward at the third quarter, we expect our operating cost per day to be generally in line with prior quarters, but there can be some variability given the size of our current fleet and the nature of drilling operations. On a margin per-day basis, we saw improvement compared to both the second quarter of 2013 as well as sequentially. During the second quarter of 2014, our margin per operating day was $9,286 per day compared to $7,722 per day in the second quarter of 2013. Sequentially, our margin per day in the second quarter improved 13% compared to the first quarter 2014 margin per day of $8,221. I want to point out our costs and margins include allocated cost. And at the rig level, our cash margins per day during the second quarter were north of $10,500 per day. Looking forward to the third quarter, we expect to see continued sequential improvement in margin per day in the range of $500 per day, with variation based upon ultimate day rate utilizations, the realizations of where operating costs per day end up. As we've highlighted on our roadshow, we utilized our rig crews to assemble our new ShaleDriller rigs, and these crew costs are capitalized as part of the new rigs cost. To meet our aggressive rig fleet growth, we typically retain these key rig personnel for our new rigs prior to the construction process beginning. We exclude these preconstruction personnel expenses from our operating cost per day metrics. During the second quarter, these preconstruction expenses associated with these additional personnel was $500,000, which compared to $300,000 in the second quarter of 2013 and $300,000 during the first quarter of 2014. During the second quarter of 2014, our SG&A expenses were $2.1 million, including $600,000 related to noncash stock-based compensation. This compares to $2 million of SG&A costs during the second quarter of 2013, which included $500,000 of noncash compensation expense. On a sequential basis, our SG&A costs were flat compared to total SG&A during the first quarter of 2014. Looking forward at the third quarter, we do expect to incur some onetime SG&A costs directly related to the IPO as follows. First, expense is directly associated with the IPO that are not capitalized as operating costs of up to $500,000; an additional noncash stock-based compensation expense of approximately $200,000 associated with divesting of certain awards at the IPO. Of course, now that we are a public company, we are incurring additional SG&A costs. With respect to cash SG&A, our expectations are that we will ramp up to a run rate of approximately $11 million per year, and during the third quarter, these cash costs will be in the $2.1 million range. In addition, we will have additional noncash stock-based compensation associated with equity awards granted in connection with the IPO, divest over a 3-year period. We expect these new awards will increase our noncash stock-based expense included in SG&A by approximately $720,000 per quarter, with some variability based upon the performance nature of certain of the awards. For the third quarter, which will not [ph] include a full quarter of expense for these new awards, our total noncash stock-based compensation should be in the range of $800,000, plus the $200,000 onetime expense I previously mentioned relating to the acceleration of certain awards at the IPO. With respect to our depreciation and amortization, our expense was $3.9 million during the second quarter, of which $3.1 million was related to our contract drilling operations and $800,000 was related to amortization of intangibles and other corporate assets. With respect to interest expense, we recognized approximately $600,000 during the second quarter associated with our borrowings under our revolving credit facility. As a result of the IPO, we repaid all of our outstanding debt under our credit facility in August and incurred interest expense during the third quarter up to that time. Following the repayment, we continue to incur a noncash deferred financing cost as well as unused line fees. As a result, I would expect our interest expense for the third quarter, including the deferred financing cost in unused line fees, to be in the range of $500,000. I do not expect we will earn meaningful interest income on our cash balances, given we plan to rapidly reinvest our cash back into our business throughout the remainder of the year. Moving on to taxes. Because of our large NOL position and our rig construction plans, we are not on a cash taxpayer today with respect to federal income taxes and won't be one for some time. However, we will record income tax expense and benefits for both purposes. During the quarter, we recorded $667,000 of income tax expense. Excluding taxes related to the insurance recovery I previously mentioned, the tax expense or benefit we would have recognized would have been negligible. Moving on to our balance sheet and liquidity. At June 30, 2014, we have cash on hand of $2.9 million, $64.2 million drawn on our $125 million revolving credit facility, the construction of 2 rigs under way and 1 rig being outfitted with a multidirectional walking system. On a pro forma basis, assuming our IPO had been completed and net proceeds received on June 30, we would have had no debt and cash coming in of approximately $56 million. During the second quarter, cash outlays for capital expenditures were $36.3 million, which were principally associated with our rig construction activities. At the end of the second quarter, we estimate there were approximately $26 million of cash outlays for capital expenditures net of vendor deposits already incurred required to complete our rig construction activities in process at the end of the quarter. Subsequent to the end of the second quarter, we completed our 10th ShaleDriller rig, which commenced drilling operations in August. We expect our rig that is being upgraded to recommence drilling operations in mid- to late October, and our 11th ShaleDriller rig under construction will be completed and commence operations in mid- to late December. We have also accelerated our ordering for rigs to be delivered in 2015 and have made deposits on long lead time items for our next 5 drilling rigs. As we continue to firm up our rig delivery plans for 2015, I expect that we will accelerate ordering for additional rigs during 2014. With that, I'll hand the call back to Byron for closing remarks.

Well, thanks, Philip. I actually don't have any remarks. So, operator, at this time, would you please open the line for questions.

[Operator Instructions] And our first question from the line of Jeff Tillery with Tudor, Pickering, Holt.

I guess a couple of questions I had. Byron, you gave details on the 2 contracts that were signed since the IPO. I guess, if you could just give us color around the discussions you're having. And I guess, what I'm curious, in terms of duration, one of the contracts, I guess, is 20 months; one, 3 years. Is that typical for the duration that you guys are talking with customers about? As well as can you give us just kind of outliers? What would be the shortest duration and maybe the longest duration you had conversations about?

Sure. Let me give you a little -- the color I can, the contracts we've signed, and Ed Jacob is here with us, and I'd like to ask Ed to address the broader conversations that we're involved with right now. So these contracts, the comment was that the contract we signed was something we were in discussions with during the IPO. Once the IPO completed and we could give good delivery days for the rigs, we were able to sign that contract. It has a 3-year term. And it's in the high $20,000-a-day range. And in general, we're getting the longest terms and the highest day rates available in the market today. The contract extension was a negotiation with a large E&P company who has been with us for quite some time. And they had some particular needs, and that contract has got a step day rate. It'll go the mid-20s till the end of the year, and then it will toggle up to the high 20s for the remainder of the term of the contract, all together, a 20-month extension. And that was a structure that was associated with the particular drilling requirements of that customer. So those are the 2 that we've inked since the deal. And let me turn it over to Ed now, and Ed can give you some further color about the conversations we're having, tone of the market and so on.

Jeff, we're going to do everything in our power to get whatever the market will provide us. It's very important for us to get term. Having been in this business for a long time, term is very important, and when the market will bear it, you need to take advantage of it. Right now, the market is in a position where we are able to get multi-year contracts for our equipment going forward, and maximize that by the highest day rates that the market will bear. And then the market sets both term and day rate. If the market didn't, if the contractors were able to set it, we'd never let day rates fall below $10,000 a day and terms below 5 years. So it's really what the market's going to allow. And right now, the market is allowing a multi-year term and high-20 day rates.

So Jeff, it feels very firm, and we'll continue to -- we're in multiple discussions with other large E&P companies for additional contracts with those terms and conditions.

And then I guess, my second question is for Philip. As I look at both the new training -- new crew training costs and the reimbursable costs, I guess, how variable, just in terms of the total dollar amount quarter-to-quarter do you think about new training cost? I guess, is that going to be kind of a fixed dollar amount as we step forward and on a per day basis? And if they remain about that way, it goes down as we spread over more rigs operating days?

Sure. It'll be fixed. And they go up just a little bit as we aggressively kind of add rigs this next year, so it could you go up a little bit naturally but not much, maybe $100,000 dollars or something like that. So on a per-day basis, if you want to look at that way, you can take our rig operating days for the quarter end and calculate it, if you wanted to do that. As far as mobilization revenues, things like that, the rebuilds are a little harder to predict. The mobilization, they're going to be a couple hundred thousand dollars a quarter type of thing on average. It will grow a little bit as we add fleet -- add rigs to our fleet, but that may -- and then rebuilds on top of that, we might be another $100,000 on average.

Okay. And then my last question, just around the supply chain and lead times. You mentioned you've put deposits down for the next 5. Anything lengthening out kind of beyond your expectations or any changes going on supply chain that we should be paying attention to?

No, our supply chain people have done a very good job of keeping their finger on the pulse. So we have not been surprised with any of the key components of our rigs, and we have planned for the supply chain deliveries that we have suspected that go back to the last 6 months. So we feel very confident that our supply chain is in place. And the performance of what our supply chain has provided over the past 6 months gives us great confidence in our ability to meet our deliveries going forward.

And our next question comes from the line of Kurt Hallead with RBC Capital Markets.

Congrats on the successful IPO. I guess from my standpoint, I hear -- we're getting a lot of sentiment shift here on U.S. land drillers over the last couple of months from investors, and a lot of investors are always saying -- expressing their concerns that there's a chance the market could become oversaturated for rigs in 2015. And varying estimates out there would pay the incremental rig count, new rigs coming into the market around 200. Just curious when you're going through your process, having your discussions with your customer base, is there anything changing at the margin from a contractual standpoint that would maybe be a lead indicator of E&P's thinking the market's going to be saturated with rigs, in terms of duration or contractual terms or anything else you might be picking up on?

Kurt, not so far. The type of equipment we produce in the market, the submarket we compete in, I think, are a little insulated from some of the factors that may be impacting folk with older or less capable equipment. I think there's still a shortage of the type of equipment that we're offering. If there's a broad market downturn, they would -- it's going to take everybody down, but I think we will relatively outperform in a down market. And right now, everything that I'm seeing from a contracting perspective doesn't indicate any issues related to us or our equipment.

Okay. And then in terms of -- are you actually then seeing maybe other indicators that would suggest the market is heating up and whether, again, that's -- are you seeing contract durations are being -- for new rigs, moving up from whatever they were to something longer? And you mentioned day rates were moving higher. So just wondering on the duration front, whether or not E&Ps are getting more interested in locking in for a longer term?

So let me give you a little bit of color, then I'll ask Ed to step in and flush it out further. I don't know that it's heating up, but it seems -- it -- the market seems robust and solid, at least, for our type of equipment. Ed were you seeing any kind of leading indicators that would give you any pause?

No. I think that the most recent rigs that we have recontracted have seen anywhere from 15% to 20% increases in day rates on the lower end, which is an indication the market's still strong. I think that lead kind of market indicator for me, Kurt, is the additional contract length that the operators are willing to commit to. That to me is a positive sign that the market is still robust. It also gives an indication of what the customer's CapEx is planning to be going forward over that contract for a period of time. So what we're seeing, the market is being very strong right now. And the one thing that I'm always looking for is my -- after all these years, has been the length of term that's available. And when we start seeing pushback on that term is when we'll get a pretty good idea that the market is going to start correcting.

Got it. And then the other question I had was specific. Given that you are operating only in the Permian, can you guys -- I'm wondering if you can give us some update on what you're seeing in terms of the number of wells per rig that are being drilled, and what the efficiency dynamics are in context of how quickly you're able to drill those wells in terms of days.

Well, we're in multiple geographical areas within the Permian. What we're seeing in Southeastern New Mexico is more of the multi -- large multi-well pads in New Mexico from anywhere from 20 wells to 36 wells to 48 wells. We'll have 4 rigs operating in that market currently. But we have seen some of the other activity that has -- that was originally just 1 or 2 wells, now moving 3 and 4 and 6 wells. So we're seeing that the number of wells double per location from what we've experienced last year, which is another indication that we're going to see a lot more. But we may not need the rig count that we will use -- what we're used to for the past 10 years. But we're going to -- the industry is going to drill more wells, thus, the efficiency that operators are realizing is going directly to their bottom line. And I'm sorry, what's the other part of the question you asked?

Yes. The other one was in days per -- the number of days it's taking to drill these wells. Is that kind of plateauing or is it still coming down?

No, it's still coming down. I mean, I think that the challenge is not the drilling piece, the challenge and the bottleneck for our customers is really the completion and fracking. And the challenge -- what we're hearing from all of our customers across the board are the supply chains challenges that they are facing. I mean, they are moving into a manufacturing mode, so they're spending a lot of money. In fact, they are consulting with leading manufacturers about how a manufacturer of product, iron, equipment wellheads, how do they view the supply chain for a manufacturing industry and how those lessons can be applied to the drilling of wellbores. So -- but we've seen -- Eagle Ford, when we were first out there, we were drilling those wells in 35, 40 days. We got it down to 20, 22. And then West Texas, on some of the wells we're drilling out there, originally took 2 weeks, now we're down to 10 days in some cases. So we've seen -- we're still seeing a reduction in the days as our customers begin to utilize new technology.

Okay. Just -- if I may, just one more, just in the context. But all great color. As you look out at your expansion plan for rigs over the next couple of years, the fact that you currently have no debt on the balance sheet right now. When you build out those rigs, I'll assume that you're going to take on some debt. Is it that part of your game plan to take out 1 tranche of debt to then pay for those rigs over time? Or are you going to piecemeal your -- if you will, even if you're going to use that, are you going to piecemeal that over time?

Kurt, once we use the cash rate in the IPO, we'll continue to build. And Phil's put an ABL in place that he can give you the details on, off-line if you'd like, but we'll use debt finance to build the fleet. And I suspect that we'll run over 30%, 35% debt-to-total cap for some time, depending on market conditions, as we grow the fleet.

And our next question comes from Thomas Curran with FBR.

Phil or Ed, please refresh me. How would you bracket high 20s? In other words, what floor and ceiling does that assume?

I would say that the middle 20s is 25. Our high 20s would be $29,999. So the low -- so that -- I'm not trying to be cute, Tom, but having been on conference calls for a couple of decades and having been on the other side, this is an excellent way for my competitions to understand what the business drivers are. And so I'm very reluctant to give the specific on that. Because I've been on your side of the phone and listening to my competition. So I hope that answers your question.

It's helpful. So it's fair to say then that the high 20s starts with $26,000 then?

Look, we talked about mid-20s, high 20s. Right now, if your question is where our leading edge day rates, they're $26,000 to $28,000.

Okay. That's helpful. And then with the initial 2015 new build award, is the operator a new client or an existing one? And if it's existing, is it also a repeat client?

It is an existing customer, and it is repeat.

Great. And then Ed, with the longest lead time systems right now, BOPs and the variable frequency drives, given how long those lead times have gotten, have you already placed the orders for 7 BOPs and 7 variable frequency drives for 2015?

We have already placed the orders for all of our lead-time items, long-lead items. The VFD is definitely one, pressure control -- it's more than just BOPs. It's BOPs, Choke Manifold -- but again, we have relationships. We don't have vendors, we have partners. And that's -- we try to leverage our spend, and so we can't be everything to everyone. So we select our partners very diligently and give them every vision of what we're planning to do going forward. So we haven't seen those challenges in lead term -- long lead items, as maybe some of our competitors have.

Okay. And then, Byron, when we get to the end of 2015, assuming you've inked contracts across all 7 of the new builds, as current indications suggest is most likely, where all would you expect to be working at that point, including the contracts you would have signed across the 7 incremental 2015 deliveries?

Well, Thomas, we'll work wherever we get the best contract. So I don't know where that will be. It'll certainly be within Texas and the contiguous states, which we define as our target market. And we're getting inquiry from all of those areas. So I don't have an answer to the question. But as soon as we -- as soon as these things are inked and occur, we'll let the Street know.

[Operator Instructions] Our next question comes from the line of Marc Bianchi with Cowen.

Curious on the 2 remaining upgrade opportunities. Could you talk to maybe the time line of discussions there, the likelihood, and then just remind us, if you could, how long those would take and then the cost associated?

Sure. They aren't really upgrades, Marc. What we -- the opportunity we would have with regard to the 2 remaining 100 Series rigs is to populate a 200 Series substructure with all the equipment on those rigs. So we it isn't really -- it's not an upgrade, it's a swap out of the substructure. It's not clear to me you can take non-walking rigs and upgrade them to be efficient walkers. So I think there's a distinction there. In terms of opportunity, those rigs are in long-term contracts with a client who is using them and has for quite some time. And as long as they're on contract, there really is not an opportunity to bring the men and sustain -- schedule downtime and upgrade them. In terms of cost and time, let me turn that over to Ed.

Time, if we had sufficient time in the supply chain, we get the part started. It will probably take a month to make the transition or the change out of the substructure. And cost wise, it would be roughly in the $2 million range.

Per rig?

Per rig, yes.

Great. Okay. Those contracts are up at the end of first quarter '15, correct?

Those contracts being the -- those contracts for the -- yes.

End of the first quarter, beginning of the second quarter.

Got it. Okay. And among the long lead items that you've pulled forward on the next 5 rigs, how much more quickly are you able to get those rigs into service now with that effort?

Well, we're right now planning for 1 in the first quarter, 3 in the second, 2 in the third and 1 in the fourth. That's our plan at this time. There's a little bit -- a lot of what drives that is going to be what is the market dictating, what is the amount of term available and what is the day rate. And also it's a little bit of brinkmanship between us and our customer. If you want to push too hard, then they'll delay and vice versa. So it really is the game that you play when you're negotiating with your customer. Remember, our customers and the people that -- the decision-makers, they're driven by reducing cost, while at the same time, we're driven by increasing term and increasing our day rates. So it's very -- that's the challenge, is to make sure we're aligned when we enter into a contract. We're not necessarily aligned in our business drivers. Does that make sense?

Okay.

You follow me?

I do. I do.

And there seems that we have no further questions at this time. I'd like to turn the floor back to management for closing remarks.

Great. Well, thanks again everyone for joining us on the call today. I hope you can tell how excited and enthusiastic we are about the future for Independence Contract Drilling. We'll start meeting you all at our conferences during the remainder of this year and into next year. And I look forward to seeing all of you soon. So thanks again for your interest and support and for joining us today.

Thank you. This does conclude today's teleconference. You may disconnect your lines at this time. And thank you for your participation.