Independence Contract Drilling Inc (ICD) 2015 Q4 法說會逐字稿

Good morning and welcome to the Independence Contract Drilling 2015 year end and fourth quarter conference call. Just a reminder, today's call is being recorded. At this time, all participants are in a listen only mode. A question-and-answer session will follow the formal presentation.

At this time for opening remarks and introductions I would like to turn the call over to Phil Choyce, Senior Vice President and Chief Financial Officer of Independence Contract Drilling.

Good morning everyone and thank you for joining us today to discuss ICD's fourth quarter 2015 results. With me today is Byron Dunn, Chief Executive Officer of Independence Contract Drilling and Ed Jacob, President and Chief Operating Officer.

Before we begin, I would like to remind all participants that our comments today will include forward-looking statements, which are subject to certain risks and uncertainties. A number of factors and uncertainties could cause actual results in future periods to differ materially from what we talk about today. For a complete discussion of these risks, we encourage you to read the Company's earnings release and our documents on file with the SEC.

Additionally, we refer to non-GAAP measures during the call. Please refer to the earnings release and our public filings for a full reconciliation of EBITDA and adjusted EBITDA and for definitions of our non-GAAP measures. And with that, I'll turn it over to Byron for opening remarks.

Thank you Phil. Good morning everyone and thank you for joining us today.

As in prior calls I will review ICD's fourth quarter operations and follow with thoughts on what we expect during the first quarter and some observations on the environment we anticipate during 2016. Phil will provide details on our fourth quarter financials and then we will take questions from call participants.

Despite continued commodity price pressure and a continuing relentless decline in the North American rig count, ICD's fourth quarter results were good. During the fourth quarter, ICD had 87% utilization of the available fleet, that being the fleet of 200 series rigs and not including the two 100 series rigs in the yard for conversion to 200 series capability. Our average fleet day rate was $23,700 a day.

We implemented initiatives during the quarter to decrease our cash cost at the rig level by approximately $600 per day for a forward cash cost run rate of $10,800 per day at the operating rig level. This equates to an expected fully burdened cost run rate of approximately $12,500 per day also at the operating rig level. These are true costs at the rig level. Our forward GAAP costs may differ due to the inclusion of stacking costs and other allocations.

We ended the quarter with approximately $75 million in drilling backlog. Our 2016 utilization rate on that backlog alone is just under 50%. Our utilization rate in the first quarter of 2016 including rigs working in the spot market and on standby without crew remained at approximately the 87% rate we achieved during the fourth quarter of 2015.

During the fourth quarter ICD set several new operational drilling and efficiency records for our clients, for a multi billion dollar market cap independent, ICD completed a 12-well program with an aggregate reduction of 70 days from that customer's target AFE drilling curve. A stunning saving in rig days but more importantly in cycle time driving a material reduction in our clients realized total spread cost versus his budget.

In another case for another multi billion-dollar independent, within six months of entering a new field, ICD drilled five of the top ten lowest cycle time wells ever achieved including the number one well and a well with the lowest cost per foot ever achieved in the field which included the running of three casing strengths.

These record-setting deliveries have become standard for ICD substantially improve our clients economics and supported ICD utilization rates above industry averages. The important takeaway from all of this is the ability to field rigs and crews capable of material cycle time reductions while dry rig demand and company performance, not rig day rate per se.

With drilling costs shrinking to 15% to 20% of total well costs and spread costs running around $75,000 per day, an environment where cycled reduction time is the key differentiating parameter, we don't believe that there is any forward market clearing day rate for slow-moving legacy mechanical SCR or non-pad capable rigs.

We continue to review and streamline our operations and implemented additional reductions in staff and cuts in operational expenses during the quarter. During the fourth quarter of 2015 we reduced forward operating costs by $1.5 million on a run rate basis associated with staff reductions and efficiency initiatives in addition to the various efficiency initiatives discussed on last quarter's conference call so in aggregate we entered 2016 with run rate cost reductions in excess of $3 million annually.

ICD rig manufacturing costs are extremely flexible and scalable on a real-time basis. During the third and fourth quarters of 2015 we suspended our rig build program and destaffed rig manufacturing while maintaining our IP and capability to rapidly re- ramp rig build and ability to build at one of the lowest costs per rig in the industry. As a modular manufacturer ICD has substantial flexibility to suspend or accelerate our rig build tempo and to ramp or reduce capital and operating spend in this regard rapidly and efficiently.

During the fourth quarter we also completed the restaging of our supply chain deferring purchase of capital items that had been scheduled for 2015 into 2016, 2017, and 2018. In early 2016 we further deferred deliveries we had anticipated taking in the first half of the year.

Day rates and our fleet status. As was the case in the prior quarter, there is no formal market for rigs within our target market area. Rig utilization will not improve through day rate reductions. As I mentioned previously we don't think there is any market clearing day rate for legacy rigs now or in the future.

Contracts currently being discussed are associated with the equipment that has a demonstrated ability to reduce cycle time. These contracts are highly bespoke and typically well to well.

Day rates under discussion for these bespoke arrangements are in the mid teens. Note that I'm referring here to pure rig day rate which does not include trucking, directional services, casing running or other services that are sometimes lumped into a revenue per rig calculation, rather I am discussing a true rig day rate.

I want to note that we are discussions with new customers for new incremental deployment of available ShaleDrillers, but to date those discussions have not yielded a contract. Currently we have two rigs stacked, two rigs on standby without crews, with another expected to go on standby during the first quarter, one 100 series rig in the yard and a second 100 series rig being modified to 200 series specifications. We expect to complete that modification before the end of the first quarter 2016.

The rest of the fleet is working. We have a 2016 contractual backlog of 5.8 rig years and even in the current environment we have only had one early termination and that was of a farm out arrangement. Importantly, rather than releasing ShaleDriller rigs, our customers are generally choosing to place them on standby while evaluating options and market conditions.

In terms of liquidity Phil will provide detail on our ABL and liquidity in his remarks but I wanted to touch on where we see capital spend headed into 2016. We will of course fund maintenance capital spend, complete the conversion of the 100 series rig in the yard to full 200 series specifications and fund contractually required equipment purchases, altogether about $10 million.

Any other spend will be opportunistic. Things such as the addition of a third mud pump or upgrade to a 200 to a 7,500 PSI fluid system in order to win a contract in terms of forward market conditions. So with the upfront admonitions that I am looking through a glass darkly, let me first observe that given today's commodity prices apart from drilling to hold a lease through reserves, field extensions or reservoir expansions, current activity does not create current value.

And predictably the market for contract drilling services remains weak with the expectation of further declines in the North American rig count during the first half of 2016. However I think the street and industry analysts have made a pretty good case for a gradual improvement in commodity prices through a combination of supply limiters, deferred or terminated capital spend accelerating decline curves and demand improvement driven by fiscal and monetary intervention with oil price gradually improving during the second half of 2016.

I think a good case is also being made that the current very large industry under and this investment is setting the stage for a powerful reversal in the global hydrocarbon supply demand relationship and a market of scarcity some years in the future. So given all that, from a land contract driller perspective what factors will support utilization and day rate near-term, and also provide a compelling and sustainable advantage in a recovery?

As I discussed earlier, efficiencies and cycle time reduction are currently far more important than day rate in winning work. The hard economics of employing an omni directional walking pad optimal ShaleDriller to cut 70 days in cycle time for a savings of $5.25 million versus AFE totally overwhelms the impact of a few thousand dollars per day savings by utilizing a legacy non-pad optimal rig with no ability to cut cycle time.

From a supply standpoint, Sell-side research reports have estimated that only 150 or so 1500-horsepower AC truly pad optimal rigs are the total North American land fleet. So as commodity prices ramp, hopefully later this year, we will come to the point of 80% or more utilization of this asset class, well ahead of any other rig asset class which well in turn support rig count and day rate.

The management team at ICD remain sharply focused on our cost structure and liquidity base. We currently target free cash flow breakeven or better in 2016 that will require that our rigs working in the spot market continue to be employed.

I want to thank all of our employees for their loyalty and commitment to ICD safety culture and our exemplary execution and performance for our customers. Our people as well is our equipment drives the ICD difference.

I will now hand the call over to Phil to discuss fourth quarter financial results in detail.

Think you Byron and thanks everyone for joining us today.

During the fourth quarter, we reported a net loss of $5.2 million or $0.22 per share. Included in this net loss were the following non-cash items.

First, non-cash impairment charge of $3.6 million associated with one of our 100 series rigs which had been decommissioned pending its conversion to 200 series pad optimal status when market conditions improve. The impairment charge approximates the carrying value of the substructure and other equipment that will not be utilized by the rate when converted.

Second, a one time non cash charge of $400,000 associated with the write-down of deferred financing costs due to the reduction of our aggregate commitment under our revolving credit facilities during the quarter. And third, $300,000 associated with the disposition of assets largely attributable to our ongoing rig conversion is expected to be completed during the first quarter of 2016. Excluding these non-cash items, we reported a net loss of $945,000 or $0.04 per share.

During the fourth quarter, the fleet generated 962 revenue days representing a 9% sequential increase from the third quarter. Reflecting full utilization of a new build rig that entered the fleet mid third quarter as well as reactivation of a previously idle rig during the quarter. During the fourth quarter our marketed rigs, which exclude our two 100 series rigs scheduled for conversion achieved 87% utilization.

On a sequential basis, we recognize revenue of $23.7 million compared to $21.3 million in the third quarter of 2015. None of our rigs earned revenue on a standby basis during the fourth quarter.

Total operating costs in the fourth quarter were $14.4 million. Included in our operating costs were approximately $462,000 or $0.02 per share net of tax associated with Galayda Yard rig build operations that previously had been capitalized. As discussed on last quarter's conference call, as construction activities become intermittent or cease, all or a portion of these costs associated with rig build will be expensed by us for accounting purposes.

On a per day basis fully burden operating costs, which exclude these Galayda Yard expenses, are $13,298 per day. Approximately $300 per day of these costs were associated with reactivating one of our idle rigs during the quarter.

During the fourth quarter SG&A expenses were $3.1 million representing a sequential decrease from the third quarter, which reflects various cost reduction initiatives as well as a reduction in cash based incentive compensation. Included in SG& A expense during the quarter was $1.1 million related to non-cash stock-based compensation.

Depreciation expense was $6.1 million during the quarter and fourth quarter tax expense was de minimus. Both in line with our prior guidance. Interest expense after eliminating the $400,000 non-cash interest charge also came in line with our prior guidance.

At December 31, we had net debt of $57.4 million and our borrowing base under our credit facility was approximately $99 million. During the quarter, cash outlays for capital expenditures was $7.9 million.

Now I want to turn to our outlook for 2016. As Byron mentioned, given market conditions we have very limited visibility. Byron also mentioned that we have a few rigs that we expect to go on standby while market conditions remain depressed. Standby rates reduce our top line revenues but preserve our operating margins and expected cash flows.

Also as Byron mentioned, the customer farm out arrangement elected to early term that portion of the contract. This rig will continue earning standby revenues under the original contract.

Taking these items into account, we expect that we will have between 940 and 955 revenue days during the first quarter of 2016, of which we estimate 175 to 190 revenue days to be earned on a standby basis. We estimate our margin per day on these revenue days to range between $9,500 and $10,000 per day. This is a fully burdened margin per day and the only other operating costs we expect to incur not within this guidance are past due in nature as well as costs associated with our Galayda Yard. We expect the Galayda Yard expense to be consistent with the fourth quarter of 2015.

The sequential decrease in margin per day relates to additional costs we expect to incur during the first quarter associated with one-time cost per rig being placed on standby and the one rig that became idle during the quarter. Our reported operating costs will also depend upon when rigs actually go on standby rates during the quarter. But we currently estimate that our fully burdened OpEx per day during the quarter will range between $11,600 and $12,000 per day. In addition to these amounts we will recognize past due costs and Galayda Yard costs as previously mentioned.

Our reported top line revenue number will depend upon when rigs actually go on standby rates during the quarter as well. But we currently estimate that our revenue per day during the quarter will range between $21,250 and $21,750 per day with the sequential decline being attributable to standby revenues and an increase in the number of revenue days earned as spot market day rates compared to the fourth quarter. We will recognize pass through revenues in addition to these amounts.

We expect cash SG&A for the first quarter to approximate $2.5 million and non-cash stock-based compensation to be approximately $1.2 million. This reflected decrease in cash incentive compensation and an increase in non-cash stock-based compensation from historical run rig levels.

Now I'd like to discuss what we can say about 2016 as a whole given our limited visibility. Our aggregate backlog of work from contracts with original terms greater than six months was $74.4 million at year end. Of this amount, approximately $53.3 million is realizable in 2016 and the weighted average number of rigs in backlog in 2016 is approximately 5.8 rigs or 48% of our currently marketed rig fleet of ShaleDriller rigs.

Breaking up the backlog by quarter in 2016, we estimate that our average rigs in backlog by quarter as follows. First quarter, 8.5 rigs, second quarter 6.2 rigs, third quarter 4.5 rigs, fourth quarter 3.7 rigs. We also have rigs operating in the spot market on short-term contracts and any revenue days earned in the spot market or on a short-term contract basis will be in addition to what we have in our backlog.

As mentioned some of this backlog will be earned on a standby basis, which reduces the overall revenue number we actually realized compared to this reported backlog number. On Galayda Yard costs, looking past the first quarter, and assuming no additional construction activity after completion of our rig conversion during the first quarter. We expect those costs to range between $700,000 and $800,000 a quarter through 2016.

We expect overall cash SG&A for 2016 to decline from prior levels and approximate $9.6 million and non-cash stock-based compensation to increase from historical levels to approximately $4.9 million. Depreciation expense in 2016 should remain relatively constant from the fourth quarter level. Tax expense should be limited to Texas margin tax. Because we have fully reserved all NOLs for accounting purposes we do not forecast that we will recognize any tax benefit during 2016, even though we will be in a net loss position for both purposes.

With respect to capital expenditures and liquidity, we expect the borrowing base on our revolving credit facility to fall as regularly updated and adjusted the severe downturn in market conditions. Assuming a 10% to 20% drop in appraisal values, our year-end borrowing base under our credit facility will likely fall to the $80 million to $90 million range.

The plan to reduce our capital expenditure budget to only things that are required to maintain our fleet and industry leading uptime, complete the rig reconversion that is underway and opportunistic upgrades to our rigs. Operating under those parameters we expect our capital expenditures during 2016 will approximate $10 million. We intended to defer all equipment deliveries under outstanding purchase orders until market conditions stabilize and improve.

And with that I will turn the call back over to Byron.

Thank you Phil and thanks to everyone for joining us today. The fourth quarter was challenging due to the macro volatility but the leadership team and employees at ICD have done a great job managing the business for our shareholders.

I would again like to thank all of our employees for their loyalty and commitment to safety and operational excellence. Our people and our equipment make the ICD difference. We are all focused on keeping the ICD shareholder fleet working at the highest level of excellence, at the best rates possible and like you, we are looking forward to a market recovery.

We will now begin the question-and-answer session.

(Operator Instructions)

James West of Evercore ISI.

Hi, good morning guys.

Good morning.

Byron, I know you are at 80% or so of utilization. What about the rest of the pad optimal fleet out there today? What do you guys estimate is the utilization of the 150 plus or so pad optimal rigs that are in the market?

From what we can tell, James, listening to other folks' conference calls and talking to folks in the field we think it tracks. So if you take a look at other people's equipment that has a similar characteristics plus or minus some percentage we think that all these things track.

So presumably when we go into the upturn whether that's second half or next year, you will be able to achieve pricing power fairly quickly, given your utilization rate.

I certainly hope so.

Right, okay. And last for me is, how are you thinking about new build rigs in this environment given that the pad optimal fleet is in the high 80% utilization range, we know those are the rigs of the future. These are the ones we are going to be using and the ones that are demanded by customers. Do you wait until the up cycle emerges? Do you go ahead and build now? You guys -- you are a growth company, you are built for growth. So without building rigs you put yourself in a different position of being stagnant in a market that actually seems to be coming to you.

I think that's right but again the key for us will be term not day rate. I think we mentioned that on previous calls. So as the market tightens one of the attributes of that would be term for equipment in short supply and again once we see that emerge from the market place, we will take a look at building again.

And your term, I'm assuming probably a year at least before you would start [building] rigs?

Yes.

Okay perfect, thanks Byron.

You bet.

Connor Lynagh of Morgan Stanley.

Hi, good morning guys.

Hi, Connor.

I got disconnected during the prepared remarks. So I apologize if you addressed this already, but I think last quarter you gave spot market commentary suggesting that rates were in the 15 to 17 range. Can you comment on where your contract re-signings fell relevant to that range?

Connor, this is Ed. How are you doing this morning?

Fine. Thanks. How you doing, Ed?

Fine. I think that what we have seen for what activity there has been in the spot market which has been limited, we believe it is in that mid- to high teen range and we have been saying 15 to 17, 15 to 18 and we have seen it in that spread.

Is there something that made you increase the higher end of that range?

I think we will start seeing some -- we've seen some increase to go from 17 to 18 as we've seen more desire by our customers to add 7500 PSI mud systems and third pumps.

Interesting. Wonder if you guys --

Connor --

Sorry, go ahead.

A little more color. We are in conversation with people for available ShaleDrillers as we mentioned in our prepared remarks. None of the conversations are really day rate centric. Again, if you look at our ability to reduce cycle time, the cycle time savings just overwhelm any minor $2,000, $3,000, $4,000 reduction in day rates and so the focus really is on that, rather than day rate.

Understood, understood. Can you give us some color on what some of your larger competitors are doing? Have you seen any sort of break in the ranks as far as relative pricing discipline on the higher spec rigs?

You know, Connor, for the first time in my long career, I have seen contractors actually exhibit pricing discipline. I mean, I am really proud of our industry from a contractor standpoint, that the contractors, the competitors that we have that are playing in this high-end space have really done an excellent job of maintaining pricing discipline. Haven't seen anyone break from those ranks. And I'm happy that we are doing that because I think it indicates that -- it indicates to the investment community that we do have some economic discipline and knowledge about what is driving this boat, that it's not day rate driven. It's really about efficiency driven.

Yes, absolutely. Thanks for the color guys, I'll turn it back.

You bet.

Rob MacKenzie of Iberia Capital.

Thanks. Question for you Byron and maybe Ed as well. Byron, do you worry at all that waiting for (inaudible) rates to get locked up on term contracts might position you too late in the [window] for the next cycle?

We always think about that and so we have to balance where we think the market is headed with the six-month delay in delivering a new build. Obviously, being stagnant is not part of our forward plan. Growth is important to us. So we think about it all the time, and we want to make a good solid capital decisions. I think that as the market firms, you are going to get term for particular asset classes and that's a commitment from our customers, that they see the same thing we do. So it's a constant balance and that's a long answer to your question and the short answer is, yes.

Okay. Good. And I guess a somewhat related follow-up would be obviously you guys came out with a really good design with the ShaleDriller. What is next? Are you working on any other innovations out there that can help you extend and maintain your competitive position?

Let me take a stab at that and then let's get some color from Ed as well? The things we're looking at right now are enhancements to the rigs capability. Things like a third mud pump, 7500 PSI mud systems. If you stand back and look at the design as it stands, as you all know, we went to the E&P community when we started the company and asked them what they were looking for. They came back with four operational characteristics, two moving characteristics, and those things have stood us in good stead. I don't see step function changes in those base requirements. I do see an interest in higher capacity and higher pressure mud systems. Ed, anything to add to that?

I think we are seeing and have been told by our customers, both potential customers who went forward and existing customers that the length of the laterals are getting longer. We used to use 5,000, 6,000 foot laterals were kind of the flavor of the day and it was the norm. Now we are looking at 10,000, 7,500, 10,000 foot laterals as being the norm. So that requires a lot more hydraulic horsepower and it requires more consistent hydraulic horsepower to drill those laterals. However, I think we are seeing also in -- several of our competitors have talked about it and one major integrated oil service company has talked about it, is the role that data is going to be used -- the data that is being acquired downhole and how is it going to be used to extend and improve even additional efficiencies. And I think that's going to be close to the next step but we are going to see laterals getting longer versus staying where they are.

Just to amplify on one of those points. The Big Data generation capability of AC computer-controlled rigs is enormous and so this is on the horizon but the use of that data in optimizing drilling programs I think is enormous and I think its underutilized right now. We have several conversations with folk who would like to be able to tap into that and our computer control systems are tailor made for this. So this is something I think you will hear about as we move forward but it's not a driver of utilization today.

Great, thank you guys, I will turn it back.

Kurt Hallead ahead of RBC.

Hi, good morning.

Hi, Kurt.

We somehow got -- lost contact with your conference call at some point early on as well. So if I am asking something that was already discussed I apologize too. Focus here on free cash flow and CapEx so you indicated $10 million of CapEx in 2016, most of that is going to be maintenance from what I can understand and then the comment about flat to maybe slightly positive free cash flow. So what are the -- what are any additional levers that can be pulled potentially maybe from a working capital standpoint to drive a little bit more free cash flow in 2016?

Kurt, from a working capital standpoint we are pretty efficient. We have a very consistent fleet and that aids us in looking at the capital intensity of our operations from a working capital spare parts perspective, payables, receivables, there is probably not a lot left to do there. So it really comes down to maintenance CapEx, expansion CapEx, in terms of getting the upgrade of the 100 series done, making some performance enhancements on the existing fleet as we have discussed and then we've got a bucket which is open PO's, and we are in conversation with vendors who are our partners in this and we have moved those around and those are -- I think that's probably the low hanging fruit if there is any. And all I can say is that is ongoing and I am very, very pleased with the way that our vendors have partnered with us and are working with us in this environment. So that's -- those are the things we will be looking at.

Okay and then with respect to your commentary about stock pricing. Some of the other competitors have indicated more in the mid teens for sounds like similar equipment. You guys are suggesting higher teens. What do you think we could chalk up the differential for that commentary to?

I don't know. I can't answer that question. I don't have any data on what other people are talking about or what they are offering so it would be pure speculation Kurt and I don't know if that is helpful.

Okay. I appreciate that. Now on a standby, can you explain a little bit about what is going on with standby and what does that mean? What are the E&Ps telling you in terms of -- hey, we are going to keep you on standby because we are going back to work in a month or two months or -- can you help us understand the standby dynamic a little bit?

The dynamic is they don't want to lose the equipment because, again I think that utilization isn't great but it's more robust than for other asset classes and in these particular cases there is uncertainty about what they want to do next or were they want to do it, but they don't want to do to lose their call on the equipment.

Okay and the standby rate compares to contract rate with a discount on that?

It will depend on the nature of the contract. These would be, if it's a standby without crew rate, the margin will be the same that we earn. That is the key. The contract rate could be on a -- it could be half the rate on a standby without crew -- on a standby without crew basis. But the margin will be intact. We won't have the operating costs while the rig is on standby.

Great. Appreciate that color. Thank you.

Thank you, Kurt.

Daniel Burke of Johnson Rice.

Good morning guys.

Hi, Daniel.

Byron, I think you mentioned that achieving that free cash flow target will require rigs working spots remain employed and that's intuitive and certainly spot rigs are carrying lower margins than your term rigs but can you address what that free cash flow threshold entails for you guys on the spot side? Is it maintaining two rigs working in spot similar to today or is it rolling term rigs? Just trying to get a better understanding of how you're thinking about contracting for the year.

We are not assuming any of the rigs that aren't working go back into the fleet until later in the year at best.

Okay. That's helpful and on the standby side, Philip, what are the contract expiry dates on the standby? Can you share that with us?

On the standby rigs, one goes into 2017, one late 2016, another one early third quarter.

Okay, that is helpful. And last one for me, appreciate addressing the borrowing base. Can you remind me, Philip, are all 14 rigs included in the borrowing base presently?

No, there are 11 rigs in the borrowing base.

Okay. You still have the option to slide incremental rigs if needed.

Yes, you can -- that can move around.

Yes, that can go up, yes. It could go down. It could go up but there are 11 right now.

Okay. Great. I appreciate it guys. That's all I had left.

Thanks Daniel.

Brian Uhlmer of GMP Securities.

Good morning, good morning. Thanks for the time.

I had a quick question about stacking and reactivating rigs. I think you'd stated that you spent about $300 per day for reactivating a rig and those op costs and that equates to just shy of $300,000. Is that accurate, number one? Number two, was this more one off to that specific rig and some mobilization expenses such as that? Or is that a number we should look for some of these rigs that go on standby and end up stacked and then get brought back? Can you talk about the process of rigs that go down and may be brought back later on in the year?

Brian, this is Ed. I will address first part, the technical requirements to stacking a rig, and we do -- when the rig is released, the most important thing is for us to do a number of things that preserve the asset. And that has a direct effect on what it's going to cost to bring the rig back out. But the cost to bring a rig and reactivate a rig is essentially driven by the length of time that, that particular rig has been stacked. And in the case of 204, we had preserved it for a long period of time which means you take all the rubber products -- there are a number of things that you have to do to preserve it, removing fluids, putting preservatives fluids in it. A number of things like that and that's what we are doing on everything and that's really what drove 204, a lot of that cost too and I will let Philip talk about the details of the cost.

A lot of that is labor that is required to bring the rig to crew it up, to bring it back out, prepare it and then put it back to work for the customer. And we do that because we want to make sure that the rig performs when it goes back to work because I think a lot of what is going to be the focus of our customers going forward as all these rigs that have been stacked in the fleet, regardless of the competitor, the contractors, as they go back to work a lot of the attention by our customers is going to be how do they perform once they go back to work. And I think it's essential that we take the proper steps both in planning to preserve it and then bringing it out so that we do go back and perform just as if the rig had been working for a long period of time; and I will go back to Philip from the financial side.

On the $300,000 that's about right. Half of it was really recommissioning cost, not purchasing of the thing that Ed alluded to. Half of it is really crew and us recommissioning the rig before we send it out to the customer to start drilling operations.

Okay. And then on the standby rigs without crew, I would assume that the crews that you guys have, are a good cause of why you are operating so well, and beating records in the training of that crew. Do you furlough those guys or do they keep insurance or do you -- do they get a partial salary or you trying to keep -- where you can hire them back real quick. Or do you just pay them severance and hope that you get them back? How are you handling that especially on a standby rig that theoretically could get brought back to work pretty quickly?

I will address this in a general way. This is still a very competitive business. But it's important that you retain your intellectual property and your leadership. That is really the key in my opinion. Others may have different opinions. I have some contractors the put a lot of emphasis on people, I have some competitors that put very little emphasis on people. I believe the difference between contractors, we all have somewhat the same equipment, but the differentiation between contractors are the people.

And I believe it's essential that we maintain our leadership and our intellectual property and have a process in place to train those people that we add as the rig count goes up. So we are going to keep all of our leadership personnel and our key employees and then if the people that came in on the bottom that have the least amount of time with us, those are the ones unfortunately, will be laid off. But its essential that we keep our leadership and our intellectual property to have any chance of being successful going forward.

Okay and does that account for the two drillers and assistant drillers or does it go beyond that? Are you keeping four to six extra hands per rig that gets laid down, just sitting around but not doing revenue-generating work? Is that an accurate type count?

No, we are -- we are moving them around throughout the fleet. What we do is the rigs that are stacked without crews -- excuse me, the rigs that are on standby without crews, we will use a minimum complement of people to maintain those -- that equipment but we will put them together where they are in a cluster, and so you don't need a full crew per rig or a number of people per rig. You can maintain several rigs with the same complement of people and we do that with both our field personnel, our field technicians, and our supervisors and leadership that we have in our facility here in Houston that shares that responsibility. Philip, do you want to talk?

Yes. We don't really have people -- for five people extra on a rig. That's not what we do. The key people are reassigned to different positions in the rig so if you sit where we are today, we will have rig managers embedded in drillers positions, drillers embedded in -- further down so when it turns around those people we will reassign them to different responsibilities on the rigs while -- until the rigs on standby go back to work. So we don't have extra people sitting around the rig site that we are paying.

Brian, this is Ed again. I will make one other statement. I can't help myself. But to be successful as a driller you have to be lean and mean and a junkyard dog. We don't have the extra people sitting around. We are going to make sure that our equipment is preserved, we are going to make sure our leadership is preserved, we are going to make sure our intellectual property is preserved but there is no place in the business in this environment for excess costs to be sitting around.

Perfect, thanks. That was one long question and so my unrelated follow up hopefully will be a little bit quicker. A manufacturing acquaintance of mine was telling me about how they are selling case and running tools, and monitoring equipment, etc., to more drillers who want to do more case and running on their own and the trend towards trying to do your own directional drilling. Can you talk about how you guys look at those services on your rig and your crews if you do any of that work now and how you see that evolving to provide you guys with a bigger piece of the pie on the same rig?

We don't do any of that work now and we look at these things and assess them but right now we don't.

Okay. So, no immediate plans. You would say not a 2016 focus?

I wouldn't say it's not a 2016 focus but I would say that there is nothing that with any immediacy that we will begin to do that type of thing.

Good deal. Thank you very much. I will turn it over.

This concludes our question-and-answer session. I would now like to turn the conference back over to Byron Dunn for any closing remarks.

Thank you all for joining us. We are sorry about the technical difficulties. We will look into it and see what caused that. If you have any questions or missed any part of the prepared remarks, please give Phil or I a call and we will be happy to go through it with you in detail. Thank you for being on the call and we are looking forward to the market improving as we go through 2016.

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect your lines. Have a great day.