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Independence Contract Drilling (NYSE:ICD)
Q1 2019 Earnings Call
May. 02, 2019, 12:00 p.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:


Operator

Good day, ladies and gentlemen, and welcome to the Independence Contract Drilling first-quarter 2019 financial results conference call. [Operator instructions] Please note that this event is being recorded. At this time, I would like to turn the conference over to Philip Choyce, executive vice president and chief financial officer. Please go ahead, sir.

Philip Choyce -- Executive Vice President and Chief Financial Officer

Good morning, everyone, and thank you for joining us today to discuss ICD's first-quarter 2019 results. With me today is Anthony Gallegos, our president and chief executive officer. Before we begin, I would like to remind all participants that our comments today will include forward-looking statements, which are subject to certain risks and uncertainties. A number of factors and uncertainties could cause actual results in future periods to differ materially from what we talk about today.

For a complete discussion of these risks, we encourage you to read the company's earnings release and our documents on file with the SEC. In addition, we refer to non-GAAP measures during the call. Please refer to the earnings release and our public filings for a full reconciliation of net loss to adjusted net income, EBITDA and adjusted EBITDA and for definitions of our non-GAAP measures. And with that, I'll turn it over to Anthony for opening remarks.

Anthony Gallegos -- President and Chief Executive Officer

Good morning, everyone. I'm pleased to say we are following up our better than expected fourth-quarter results with very good results for the first quarter this year, especially considering a pretty challenging market brought about by the oil price decline in the fourth quarter of last year and our customers' response. In fact, we are reporting adjusted net income for the second consecutive quarter. These results were made possible because of the intense focus on safe operations, on our continued successful integration and on cost control and synergy realization, which drove better-than-expected financial performance in our cost lines again during the quarter.

During the first quarter, we averaged 30.3 operating rigs, which represents 95% utilization of our marketed fleet. During the quarter, we had several wins in the form of contracts renewed and new and incremental contracts with existing customers. Overall, fleet utilization tracked our expectations very closely, and I'm pleased with how things are shaping up. The recent commodity price issues that resulted in a reduction in our customers' operating budgets as well as our customers' focus on operating within free cash flow had not materially affected the utilization of our pad-optimal fleet.

While first and second quarter utilization is choppy, it is still robust as pad-optimal rigs with good performance have and will continue to find follow-on work as the industry adjusts drilling programs and reallocates drilling rigs accordingly. So really, what we have experienced and will experience in the second quarter is just transitory downtime as we reshuffle the deck and redistribute the pad-optimal fleet across our customer base in our target markets with summary contracting opportunities being driven by fleet high grading and some based on incremental rig ads. Philip will provide more detail on his prepared remarks regarding first-quarter financials. However, I'd like to provide some additional color.

We exited 2018 with 32 rigs contracted. During the first quarter, we signed 6 contract extensions and dealt with three rigs where operators were not continuing the rigs drilling program, which resulted in the expected transitory downtime during the quarter. Two of these rigs were quickly recontracted and have already recommenced operations during the second quarter. The third rig is being upgraded to 300 Series specifications and will be equipped with 25,000 feet racking capacity and one million pounds hookload when the upgrade is complete.

The rig already had three mud pumps and four engines. This rig was a legacy Sidewinder rig and a very good example of perhaps an underappreciated value point associated with the organic earnings and free cash flow growth we can achieve from the Sidewinder fleet acquired in the combination. Once this 300 Series upgrade is complete, this rig's specifications will be the highest in the industry and should earn leading-edge dayrates in the market. And the total incremental capex for us to complete the upgrade for this rig is only $1.3 million, on which we will earn sub two-year paybacks and superior investment returns.

Our target date for this rig to reenter our operating fleet is the beginning of the third quarter. We have six additional legacy Sidewinder AC rigs operating today that can be upgraded to these specs at similar capex levels. Again, more low risk, organic high return, free cash flow-generating growth opportunities that we can execute upon. With respect to the second quarter, we continue to experience some transitory downtime issues, but it also appears to be the trough as rig inquiries over the past 30 days have increased.

We have a very good line of sight on numerous recontracting opportunities, and I fully expect transitory issues to resolve during the back half of the year and most likely in the third quarter as we deal with the few remaining rigs we need to reallocate among our customer base. Some have already been recontracted, and for the remaining, we have multiple opportunities for mid to late May or June reactivations. As we sit here today, we only have three idle uncontracted rigs, including the rig undergoing the 300 Series upgrade I previously discussed. So fleet utilization for the quarter should remain robust, troughing around 90% or so.

One final item on this topic before I move on. As we reposition our fleet among our customer base, we are experiencing some labor cost inefficiencies as we maintain staffing while rigs are in transition. Philip will go through the details, but while this allows us the opportunity to internalize many costs and perform operations we might normally outsource when our rigs are in full effect of utilization, it does create some inefficiencies. And I do expect higher daily operating cost during the second quarter for this reason but fully expect us to return to first-quarter daily opex levels or lower during the back half of this year.

Moving on to the pricing environment. As mentioned on our prior conference call, lower commodity prices and our customers' reduced budgets and continued focus to operate within free cash flow have put some modest pressure on dayrates and contract tenders, more so on recontracting idle rigs than with respect to contract extensions. Compared to March and April of last year, dayrates for ICD have improved but have declined slightly from where leading-edge rates were prior to the oil price decline that began late fall 2018. So we are still seeing dayrate improvements on renewals of older contracts but not the dayrate momentum we were hoping for 6 months ago.

In this environment, most of our new contracts and renewals are on a shorter-term basis, six months or less with a few exceptions. This does reduce our reported backlog number, but it also sets us up nicely to fully participate in what we believe will be a more constructive recontracting environment at the back half of this year once transitory utilization issues resolve and our customers' budgets begin reacting to the improving commodity price environment. This contracting strategy is a slight change from ICD's prior precombination strategy when we were operating a smaller fleet but one we're very comfortable with given our fleet size, strong balance sheet and more importantly, our very strong customer base. In that regard, over two-thirds of our rigs are contracted today with the top 30 operators in the United States as measured by rigs under contract.

In fact, one-third of our rigs are working for the top six customers. These customers are focused on optimizing well and fuel efficiencies through complex multiwell pad drilling, which we believe will drive incremental demand for our pad-optimal ShaleDriller fleet. And I believe these customers recognize the value that ICD provides them, not only through best-in-class rigs but superior service delivered by our top-notch personnel supported by industry-leading systems and processes. In fact, in February of this year, EnergyPoint Research rated us the top plan contract driller for service and professionalism based upon their most recent customer surveys, ahead of our larger competitors.

Prior to the Sidewinder combination, we were too small to be considered for this survey. Of course, most of our customer base is comprised of leading publicly traded E&Ps, which continue to talk about their commitment to capital discipline to live within cash flow. But they have been slow to ramp up drilling operations in response to recent commodity price improvements, which limits drilling rig demand visibility somewhat during the back half of this year. But I believe robust economic and industrial activity in the United States combined with supply shortcomings in certain oil-producing countries and continued discipline on the part of OPEC should continue to provide an upward bias on oil prices.

The question is how much our customers will adjust their drilling plans in response to the higher commodity prices. Regardless, I believe the pad-optimal fleet will again reach full effect of utilization during the back half of this year, most likely during the third quarter as high grading continues and budgets are adjusted, albeit slower than in past cycles in response to improved oil prices. Now looking at this market and what it means for ICD strategically over the next couple of quarters. As I previously mentioned, things are playing out much as we laid out on our prior conference call.

We expect to hit the trough during the second quarter but recover the full effect of utilization and a more constructive pricing environment during the back half of the year. In this environment, I do not expect our capital budget to materially change. We still expect to continue planned third mud pump additions were justified economically and will pursue other 300 Series upgrades similar to the one we have in progress as opportunities present themselves. With respect to our planned SCR to AC conversions, the first delivery of long lead time items from NOV will occur in a couple of weeks so we will be ready from that point forward to begin completing those conversions when opportunities present themselves.

Before I close my prepared remarks, I want to provide an update on our integration efforts. I'm extremely pleased with our progress. We've successfully hit every one of our critical integration milestones and remain confident that we will achieve our target for synergies of $10 million or more and be at that run rate as we enter the third quarter of 2019. Now as I close my prepared remarks, I want to reiterate where I believe ICD is positioned strategically, not only operationally but with respect to our ability to generate sustained earnings, free cash flow growth and financial returns for our stockholders on an absolute and per share basis.

And not just in strong markets but even in choppier market environments such as the one we are experiencing today. Today, I believe we are only one of two U.S. land-based contract drillers actually reporting adjusted net income for the quarter or for that matter over the past two quarters. Philip will provide additional details in his remarks.

But from a free cash flow basis, even in a choppy market that exists today, ICD's free cash flow generation, especially when looking at our current stock price, is very strong and will only improve as we move toward the back half of this year. Operationally, we have the right assets, are working for the right customers and the right basins and continue to provide exceptional services that are necessary to assist our customers in maximizing efficiencies and productivity in their overall drilling programs. And finally, we're beginning to execute on the high return free cash flow-generating organic growth investment opportunities that are embedded in the Sidewinder rigs we acquired in the combination. I want to assure you, we are focused on the big picture with a returns-focused orientation applied to all decisions which we make.

And these investments will generate superior returns and be made while maintaining robust free cash flow and without stressing our balance sheet. Our board, management team and shareholders are all aligned in this regard. In fact, you may have read in our recently filed proxy some of the executive compensation changes that we made post Sidewinder combination, including increasing performance of board rating and tying a large portion of those incentives to meeting and exceeding return on capital metrics. As you've heard me say before, while nothing has changed, everything is different here at ICD.

And with that, I'll turn the call over to Philip so he can walk us through the details.

Philip Choyce -- Executive Vice President and Chief Financial Officer

Thanks, Anthony. During the quarter, we reported adjusted net income of $2.9 million or $0.04 per share and adjusted EBITDA of $15.8 million, representing the second consecutive quarter in which we have reported positive adjusted net income. The quarter included a $2.5 million or $0.03 per share tax benefit. Excluding that benefit, adjusted income was $0.01 per share.

Merger and related asset disposal impairment cost on nonstaired equipment acquired in the Sidewinder merger are excluded when arriving at adjusted net income and EBITDA. With respect to the other items during the quarter, revenue per day of $20,755 and rig utilization of 95% came in consistent with our guidance, reflecting a small amount of idle time associated with transitioning rigs between customers. Sequential pricing improvements relate to improved pricing on contract roles. Cost per day of $13,302 came in below our guidance.

Sequential increases in cost from the fourth quarter of 2018 relate to seasonal payroll tax items and a shorter quarter of which to absorb fixed operational support costs. SG&A of $4.5 million, including noncash compensation expense of $400,000, came in consistent with guidance with sequential improvement in cash SG&A being driven by continued realization of merger synergies. Depreciation and interest expense came in consistent with our guidance. As we mentioned, we did record a tax benefit during the quarter associated with the application of our estimated effective tax rate for the year to the unadjusted net loss we reported during the quarter.

Tax expense for the year will be comprised of Louisiana tax and Texas margin tax. As I've discussed previously, given our NOL position and the full step-up in basis we received on the acquired Sidewinder assets -- we acquired in the combination, another, I believe, underappreciated free cash flow-generating facet of that transaction, we do not expect to be a cash taxpayer for federal tax purposes in the near term. Cash payments for capital expenditures net of disposals, insurance recoveries and capital lease additions were $9.3 million during the quarter. Our overall 2019 capital budget of $29 million remains unchanged.

As discussed on our prior call, capex is skewed somewhat toward the first half of the year. Thus, once working capital normalizes at the end of the second quarter post integration, we expect our EBITDA to free cash flow conversion during the back half of the year to normalize and substantially improve. Moving on to our balance sheet. At March 31, we reported net debt, excluding capital leases, of $122.4 million, up slightly from year-end relating to continued payment of accrued transaction expenses and other seasonal working capital investments.

There will be additional accrued transaction expenses between $4 million and $5 million that will flow through our cash flow statement during the second quarter, at which time we expect our working capital items to normalize. At March 31, we had total liquidity comprised of cash on hand and availability under our revolver in term loan accordion of $51 million. Our backlog at March 31 stood at $102.4 million, representing 13.2 rig years of work. As Anthony mentioned, terms on recent contracts and extensions have been predominantly short term in nature.

Now moving on to guidance for the second quarter of 2019. We expect to see the following: operating days approximating 2,580 days during the quarter; revenue per day is expected to be approximately flat with the first quarter; cost per day during the second quarter will range between $13,700 and $13,900, sequentially higher than the first quarter. The increase does not represent a true cost increase but rather relates to maintaining our existing employee base during the transitory idle periods Anthony discussed in his prepared remarks. We expect our cost per day to return to levels experienced during the first quarter or lower once those issues are behind us and our rig fleet reapproaches full effect of utilization.

Right now, we're expecting that to occur during the third quarter. SG&A expense will be approximately $4.3 million during the quarter, including $500,000 of noncash stock-based compensation. Estimated decreases in cash SG&A are directly associated with continued realization of transaction synergies. Depreciation and interest expense should be flat with the first quarter.

Tax expense is tricky to predict for the reasons previously discussed, but right now we would expect a small benefit realized during the second quarter. And finally, we will incur some additional merger-related expenses principally severance during the second quarter as we close out the integration process. We expect those to be in the $1.5 million range. And with that, I will turn the call back over to Anthony.

Anthony Gallegos -- President and Chief Executive Officer

Thanks, Phil. I have no further comments at this time. Operator, let's open up the line for questions.

Questions & Answers:


Operator

Thank you, sir. [Operator instructions] Your first questions will be from Kurt Hallead of RBC.  Please go ahead.

Kurt Hallead -- RBC Capital Markets -- Analyst

I appreciate those insights and your views on what's transpiring and the company's positioning within it. I think the focal point, I think I might want to take here initially is as you look through the remainder of 2019, and you mentioned you're getting increased inquiries and expecting to get back to kind of full utilization, when you kind of think about a full year kind of EBITDA and kind of full year kind of free cash flow, how do you see that evolving? And do you think you can potentially kind of get to a $70 million EBITDA number for the full year?

Philip Choyce -- Executive Vice President and Chief Financial Officer

The answer will be yes. We can get there. It's going to be -- second quarter is the trough. The third and fourth quarter, we expect to get better pricing than what we're getting today.

Our capex is going to be lower than what we did this quarter. Some of it is front ended. And we did have some working capital investments really related to the merger, and we're going to have some of that in the second quarter. So back half of the year, I expect when I look at our free cash flow, I measure it really by our net debt number.

And you're going to see that go down as we enter the third and fourth quarter. It's already starting. You don't see that at the company now, but so the answer is we believe we can get there.

Kurt Hallead -- RBC Capital Markets -- Analyst

OK. That's great. Appreciate that specificity. Maybe an additional follow-up.

Shortly after, I think -- and actually looking at your most recent investor deck here, you indicated some potential outcomes on free cash flow generation looking at synergies and adjusted backlog for dayrates and SCR conversions, etc., potentially with free cash flow somewhere between $80 million to $100 million. Given what's transpired over the course of the past couple of months, is there any reason to think that, that range, that potential range of $80 million to $100 million of free cash is any lower? Or are you pretty comfortable with that range still?

Anthony Gallegos -- President and Chief Executive Officer

No. Kirk, that's a great question. Appreciate that. Just to be clear though, I think what we signaled and put in those -- in that PowerPoint was an EBITDA in the range of what you're talking about.

And the take away from that, and the point we wanted to convey was in order for this company to generate $100 million-plus of EBITDA, we will not need dayrates in the upper 20-type range, meaning I think the benchmark that we used when we did that calculation was $23,000 a day type dayrates. Obviously, a normalized apex number, a rationalized G&A to support that. You start backing away from the EBITDA you generate, the free cash -- I'm sorry, the capex investment that when we acquired from a maintenance standpoint and you calculate your free cash flow yield, it's obviously very, very attractive. That was the point we were trying to make in that deck.

But to answer your question, yes, we can see when we get out into 2020 and certainly beyond, assuming the commodity holds up, demand is still there for the equipment, that we do think that's very realistic and very doable. And that's the path that we're headed down.

Kurt Hallead -- RBC Capital Markets -- Analyst

That's awesome. Thank you for that. Appreciate it. Thank you.

Operator

The next question will be from Taylor Zurcher of Tudor, Pickering, Holt. Please go ahead. 

Taylor Zurcher -- Tudor, Pickering, Holt, and Company -- Analyst

Anthony, I thought some of the commentary provided on pricing for the contract renewals be more steady than -- or excuse me, for extensions being a little bit more steady than for rigs changing hands, which maybe is intuitive. But a couple of questions there. One, if that dynamic continues to play out, do you see any of your E&P customers today I guess starting to become keen to that fact and starting to play the spot market a little bit more with multiple drilling contractors? And then secondarily, when you talked about inquiries increasing for I think you said May and June type time frames, what sort of E&P operators are driving that sort of uptick? Is it operators that have dropped rigs over the past couple of months? Or maybe some of the larger privates coming back? Any color there would be helpful.

Anthony Gallegos -- President and Chief Executive Officer

Yes. No problem. Thank you for the questions, Taylor. On the renewal situation, just to give you a little color, maybe help understand that issue a little bit better.

When we're negotiating a rollover contract with an existing customer, obviously, we're in a different position because often times, the rig has been with that customer for quite some time. There are certain efficiencies that have been gained from the relationship. The rig, the crews know the drilling program. Likewise, the customer understands the rig and its capabilities.

So we're just in a different position when we're negotiating a contract extension with an existing customer. On a situation where we're pursuing new work with a new client, obviously, your customer is going to look at HS&E, how you performed. That's kind of the first box that has to be ticked. Second, does the rig meet their equipment specification? And suffice to say with the drawdown in rig count over this year, there are other rigs out there that have capabilities similar to what our rigs would have.

So you're just in a much more competitive situation and dynamic when you're negotiating that contract from the incremental rig to go to work for that customer. So that's really the difference and the reason for the delta in those kind of rates. And certainly, we've been fortunate or unfortunate, depending -- are expected to perhaps negotiate both of those kind of opportunities here in the first quarter. But if you look at where we are in terms of the utilization in light of what's happened across the industry over the last four, five months, I think we've done pretty well.

The marketing team works really hard every day to make sure that we're aware of opportunities out there to contract our rigs, and that most importantly, we're able to secure those contracts. With regard to your second question in the inquiries, I would say where we're seeing the -- what we're seeing in the market is the public guys, they continue to stick to the mantra of living within free cash flow even though I think most people would assume that free cash flow will be higher in the back part of the year than what they budgeted. For the most part, the guys have kind of stuck to their guns on that. So there have been some high grade opportunities where we've been able to replace a lower performing rig with a customer.

You won't see that in rig count, but it would be incremental to ICD. And also the privates, the large privates is an area where we do see opportunities, not only from ICD rigs but possibly incremental rigs to the overall rig count. Hopefully that answers your question.

Taylor Zurcher -- Tudor, Pickering, Holt, and Company -- Analyst

It did, it did. And one follow-up which you touched on there is just the drilling efficiency dynamic that's I think been a common theme with the E&Ps are Q1. Is that -- it feels like a lot of them are still realizing incremental drilling efficiencies. And to me, there's a positive in that you sort of need this high-end rig and the negative is obviously that more rigs are getting dropped as a result.

And so curious with your fleet, are you still seeing incremental drilling efficiencies year-to-date in 2019? And overall, how do you see that dynamic playing out maybe over the next 12 months?

Anthony Gallegos -- President and Chief Executive Officer

Yes. I think from an equipment standpoint, the ShaleDriller rigs, the rigs that we own are as good and in some attributes, in many cases, even better than the standard industry offering out there. I think when you look across basins and even within basins where you might see productivity not be where you would think it would be is really more driven by the particular program, the particular wells that are being drilled, for example. You look out there, there's -- customers continue to test the limits of how long is too long for a lateral, for example.

It's just an economic equation to drill more footage. The expectation is they earn more dayrate. But oftentimes, the further out you get in a lateral, it can become more complicated, not just from a drilling standpoint but also from a completion standpoint. So I really would say it's inefficiencies, to the extent they exist, are going to be tied more to a particular drilling program in a particular well than maybe a particular customer and certainly a rig.

Taylor Zurcher -- Tudor, Pickering, Holt, and Company -- Analyst

Understood. And I'll try to squeeze one more in probably for you, Phil, which is on the free cash flow front. You laid out why that's likely to start ramping or improving in the back half of the year. From a use of cash perspective, I suspect that pay down is probably near the top of the priority list.

Should we expect you to build cash in the balance sheet in the back half of the year or start whittling down that debt balance either late '19 or early '20?

Philip Choyce -- Executive Vice President and Chief Financial Officer

The term loan is prepayable, so we can pay that down as we generated free cash flow. I think we'd probably do a little bit of both. The Board will make that decision with Anthony and I talking to them back half of the year. But I think paying down debt will be certainly part of that.

Taylor Zurcher -- Tudor, Pickering, Holt, and Company -- Analyst

OK, great guys. I'll turn back. Good luck.

Operator

The next question will be from Connor Lynagh of Morgan Stanley. Please go ahead. 

Connor Lynagh -- Morgan Stanley -- Analyst

I was wondering if you could verify or to give your commentary on spot rates. So it seems like some of your competitors over the past few weeks have kind of identified what I would guess would be your equivalent to your 300 Series rig having rates in the mid-20s. Do you agree with that? And if so, can you help frame for us how much of a mark-to-market opportunity you have in your fleet in terms of just rolling to higher leading-edge rate?

Anthony Gallegos -- President and Chief Executive Officer

Yes. No problem. Obviously, there's a premium in dayrate when you are able to bring to market kind of rig like we're talking about in 303, the rig we're upgrading right now that will be available here in just a few weeks. I do think that premium is $2,000 a day plus.

I think when you look at ICD and you think about where we are, I mean, everybody can do the math. I think you look at average dayrate for the company today, it's largely a function of legacy contracts, contracts that were put in place some time ago. The market can change quickly. It can change dramatically, which is what we've seen over the last six months.

So we're in this interesting situation where certainly on a year-over-year basis, you should continue to see our average dayrate increase. I think quarter to quarter, at least here in the first part of the year, it's going to move more sideways. But obviously, with the expectation for increased demand in the back part of this year and certainly rolling into 2020, we would expect to see that continue its upward momentum.

Connor Lynagh -- Morgan Stanley -- Analyst

That's helpful. And you had alluded to high grading opportunities before. I'm curious, are customers willing to pay so much for the efficiency that they would fund an upgrade like SCR to AC conversion or something like that? Or is this more incremental as we [Inaudible] here and there? How do you think about that?

Anthony Gallegos -- President and Chief Executive Officer

Yes. Not seeing opportunities where they would fund especially on the front end the conversion cost. What I referred to high grade opportunities, Connor, really what I was referring to is if a guy's got 20 rigs running and he's always going to have some really, really good rigs and he's probably going to have some rigs that aren't doing as well. If there's a hot rig that's being released from another customer, even if it's owned by another contractor with great performance, he's going to do like any of us would do and that's make the decision to drop his lower performing rigs and pick up something that may be higher performing.

Certainly, if it's more capable, that's even better for his perspective. The question is, is he willing to pay for that? And that's what we're feeling through right now. Obviously, we believe that there is a premium that the customer is willing to pay for, and that's why we moved forward with the 303 upgrade, which is under way right now. I do want to point out, we -- that's a very modest amount of capex we invested in that rig.

It was a big rig to begin with. It already had three mud pumps, already has four generators, but we have six more just like it that, depending on where the market goes, assuming customers continue to be willing to pay for the high-end equipment, those are very easy levers that we'll pull over the next year, one and a half years and move those through the fleet as well.

Philip Choyce -- Executive Vice President and Chief Financial Officer

And Connor, our four -- when we talked -- we talked about the 4 SCR rigs, three of them are drilling and one of them is idle. And then we have the one other -- the 34th rig is an AC rig. And when we bring those out, those can easily have these 300 Series features on them as well.

Connor Lynagh -- Morgan Stanley -- Analyst

Understood. Thanks for the call.

Operator

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

Daniel Burke -- Johnson Rice -- Analyst

Good morning, guys. I guess I just wanted to dig a little bit more deeply into the utilization outlook for Q2 and then the transition into what's expected to be a little bit more of a robust second half of the year. So it looked like you guided to, give or take, 3.5 idle rigs in Q2. You have three idle today.

I guess I'm just -- is the delta between three and 3.5, and I know I'm parsing this pretty finely, is that just a safety allowance? Or do you have line of sight that you'd still might have another one or two rigs returned by your operators here in Q2?

Anthony Gallegos -- President and Chief Executive Officer

No. We have three idle rigs right now. But what happened, we had some rigs come back to us right at the end of the first quarter and then it takes us a month -- days. We don't wind up exactly on the recontracting.

So it might be one. It feels like to me it's like we get these rigs -- it takes us one to two months, three months on the long end it seems to get the rig and back out. So it's really a matter of it's just the timing, so we had some rigs in April that we've recontracted that we have idle times on. So that's really -- it's not really a safety allowance.

It's what we think about what we're going to do. And so it's really just -- there's a lot of ins and outs in there right now. There's probably five rigs that we're dealing with in the second quarter and that most of them have been recontracted or we know when they're going out and it's just kind of where -- that's where the dust settles.

Daniel Burke -- Johnson Rice -- Analyst

OK. Got it. And that's helpful. I know it's easy to put it together in any greater detail than the way you already have.

I guess other question I would ask, Anthony, maybe -- and as much as right now, there is a lot of focus on returning some of the rigs to service. When you think about the SCR conversions and you're now about to start receiving some of the long lead time items, I mean do you have any level of customer discussions going on regarding those conversions at this point?

Anthony Gallegos -- President and Chief Executive Officer

Yes. As a matter of fact, we do, Daniel. It's -- this is a really exciting project for the company. It's exciting to me from an investment perspective of being able to take these rigs that are good rigs in their own right but really moving them to the next level without having to spend just an absurd amount of capital to make that happen.

And these, rigs with just a little bit of incremental capex, we can take them to, as Philip indicated, the highest specification in the industry. So there's some interesting work out there in other basins outside of it, the one that we talked about today where a rig like that would bring a lot of value, a standard 1,500-horsepower rig with two pumps wouldn't be able to do. So obviously, we're spending a lot of time on those opportunities but also talking to existing customers because there are scenarios and situations where we can displace competitor rigs or possibly even high-grade rigs that we may have with the customer and do something with that particular rig and put it with someone else. So I'm really optimistic and positive obviously about the opportunity that the 300 Series and even the remaining AC conversion rates that we have present for the company.

Daniel Burke -- Johnson Rice -- Analyst

OK. Got it. All right, guys. Well I'll leave it there. 

Operator

The next question will be from Thomas Curran of B. Riley FBR. Please go ahead. 

Thomas Curran -- B. Riley FBR, Inc. -- Analyst

Anthony, now that you're two quarters into integration, could you give us an update on how you're thinking about longer-term technology priorities? So for new initiatives, where will your focus be? Will it be on new apps for your software platform, automation, an extension of services you provide with the rig or perhaps on the hardware side related to specific systems or components on the rig? I realize that the 300 Series is still relatively new in terms of design, but I'd love an update on how you're thinking strategically about technology going forward.

Anthony Gallegos -- President and Chief Executive Officer

Yes. So thank you for the question, Tom. So the first thing, we talked about this before that we had to nail and get right was the integration of these two companies, and I think we've been pretty open with people. We confirmed that -- what we did every one of our critical milestones.

We're going to bag every bit of the synergies which have been raised once already in terms of our expectation. And we're going to be -- we are integrated now, and we're going to be at a run rate incorporating the synergies as we roll into the third quarter. As we think longer term, certainly, we have to make sure we have the right platform and we believe we do in terms of the equipment. The rigs that we have are obviously very capable.

Some of them, the subset have the opportunity to be upgraded even further, and we've got a line of sight on that in the plan. We just -- we want to make sure we get paid for it. But as we think longer term, ICD is a bit unique as it relates to how we're going about this. We've got competitors, much larger competitors that have gone out and invested a lot of money trying to go at it at their -- on their own, with their own solution to the problem.

But our strategy has been to leverage off of a lot of good work that's going on in the industry with third parties and be able to get to the same place with our rigs. And I'm confident that we're going to be able to do that. There's already work under way on that front. I can't talk about it at this time, but we will not be left behind in this regard.

But I do want to emphasize we have to have the right rig to be able to deploy that type of technology and be able to provide that kind of value to your customer. And we have that in place now.

Thomas Curran -- B. Riley FBR, Inc. -- Analyst

And to the extent you could share some additional color on the path you're pursuing, is it going to be more like a partnership, an alliance? Will it just be a standard vendor relationship?

Anthony Gallegos -- President and Chief Executive Officer

I think it'd be more of a collaborative type relationship. We're not going to go out and buy anybody or anything like that to execute on our strategy. So I'll look at it more as a collaboration.

Thomas Curran -- B. Riley FBR, Inc. -- Analyst

OK. And then on the contracting dynamics front, are you starting to have any customers come to you guys and proactively explore new commercial models, new structures for how you're compensated, how you price work or determine the revenue for drilling a well or sections of well once it's been completed?

Anthony Gallegos -- President and Chief Executive Officer

Unfortunately not. I wish I can say we have. Where we've had those conversations and we're trying to, Tom, like a lot of people, we're having to instigate those conversations. We're having to put ideas in front.

There's the question in the industry is how much value will be created by this technology or these types of technologies? And then what's the proper compensation? And there's all kinds of ways you can get there. But I think right now, suffice to say, the industry is very curious. I think there are some early adopters out there that are willing to take the ball and run. But I believe for the most part, right now, most guys are kind of sitting back waiting to see how this plays out and we'll jump on the bandwagon down the road.

Thomas Curran -- B. Riley FBR, Inc. -- Analyst

OK. Thanks for taking my questions. 

Anthony Gallegos -- President and Chief Executive Officer

And I was referring to customers, by the way.

Thomas Curran -- B. Riley FBR, Inc. -- Analyst

Got it. Makes sense.

Operator

And ladies and gentlemen, that will conclude our question-and-answer session. I would like to hand the conference back over to Anthony Gallegos for his closing remark.

Anthony Gallegos -- President and Chief Executive Officer

OK, guys. We really appreciate everybody dialing in today. Looking forward to seeing you guys on the road. We've got some investor conferences coming up.

I'm looking forward to talking to you again here in a couple of months as we talk about our second-quarter results. I hope everybody has a safe day. And again, thank you for your time today.

Operator

[Operator signoff]

Duration: 43 minutes

Call participants:

Philip Choyce -- Executive Vice President and Chief Financial Officer

Anthony Gallegos -- President and Chief Executive Officer

Kurt Hallead -- RBC Capital Markets -- Analyst

Taylor Zurcher -- Tudor, Pickering, Holt, and Company -- Analyst

Connor Lynagh -- Morgan Stanley -- Analyst

Daniel Burke -- Johnson Rice -- Analyst

Thomas Curran -- B. Riley FBR, Inc. -- Analyst

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