Independence Contract Drilling Inc (ICD) 2015 Q2 法說會逐字稿

Good morning and welcome to the Independence Contract Drilling's 2015 second quarter conference call. Just a reminder, today's call is being recorded. (Operator Instructions) A brief 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 second 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 in our public filings for our full reconciliation of adjusted EBITDA and for definitions of our non-GAAP measures. With that, I will turn it over to Byron for opening remarks.

Thanks, Phil. Good morning, everyone and thank you for joining us today. Following our typical format, I will review ICD's second-quarter operations and follow with thoughts on what we expect during the third quarter and the rest of the year. Phil will discuss financial highlights and then we will take questions from call participants.

The second quarter results were in line with our expectations and the guidance we provided on our first quarter call. The overall tone of the operating market remained soft during the quarter, with the rig count declining, but at a slower rate. No firm spot market developed and opportunities for work were dependent on rig capabilities.

Although we thought we saw an overall market bottom forming during the quarter, recent commodity price declines, dollar strength and what seems to be the transition of the US to global swing producer status, have driven the continuation of the overall negative market tone we observed throughout the second quarter and now to date.

Having said that, there's an important distinction to make with regard to the tone and texture of the US land contract drilling market. Although the overall market tone is negative, the bifurcation of the market by asset class has accelerated. I believe we have witnessed the establishment of long-term structural unemployment for mechanical and SCR rigs, with non-walking AC rigs in that structurally disadvantaged class working as swing services providers.

Again, AC drives alone are no longer a distinguishing rig capability characteristic. With the expanding adoption of pad drilling by the broad operator community, as a tool to lower operator drilling costs, the combination of the drive and the rig as an efficient delivery system, not the drive alone, now sets the baseline in the industry.

Conversely, we believe that demand in fleet wide utilization of pad-optimal equipment has likely bottomed and future unemployment of pad-optimal equipment is frictional in nature, as opposed to structural and is poised to improve in sequential quarters.

During the second quarter and to date, standby rigs of the pad-optimal asset class returned to work, farm out activity decreased and inquiries for year duration term contracts for pad-optimal equipment were circulated.

Well capitalized, smaller operators, contracted pad-optimal rigs at spot in the prevailing lower price environment. Now discussions of term contract extensions with these operators have commenced.

I want to be very specific again with the definition of pad-optimal equipment. This definition is set by the operators, not the contract drilling community and only includes those rigs that are rated at 1,500 horsepower, offer bi-fuel capability, are outfitted with 7,500 PSI mud systems to accommodate long laterals, are capable of sub-40 conventional moves, have integrated Omni directional walking systems capable of rapidly adjusting to misaligned well bores, self-leveling the rig on uneven pads and walking over raised well heads, and finally, are powered by an AC drive.

That asset class will benefit from full effective utilization and day rate improvement earliest in any recovery scenario. All of our rigs that were on standby, earning day rate or margin during the second quarter, have returned to active drilling programs during the third quarter and we have had no early termination of rig contracts.

We ended the second quarter with one 100-series rig stacked, a second 100-series rig moved to Houston for modification to a 200-series integrated Omni directional walking system and upgrade of its mud system to 7,500 PSI. And with the exception of our last 100-series rig, which is now slated for upgrade to 200-series substructure, 7,500 PSI mud system commencing during the fourth quarter, and two 200-series rigs whose contracts ended during the second quarter; our fleet is working with all rigs contributing to margins we anticipated.

We added two new customers during the quarter and signed new contracts in the spot market. Operational performance remained strong, with operational uptime during the quarter exceeding 98%.

During the quarter, we substantially completed the construction of our 14th ShaleDriller rig, ahead of schedule and on budget. The rig mobilized to location ahead of schedule during the third quarter.

Costs also came in line with our expectations. We incurred some incremental costs associated with stacked rigs in west Texas, but on a run rate basis, the cash operating costs of our operating rigs was flat with the prior quarter.

From a cost control perspective, as a modular manufacturer, our field and manufacturing headcount naturally tracks activity and we closely monitor and evaluate our cost structure weekly.

As we mentioned on the first quarter call, we have deferred four new construction ShaleDrillers into 2016 and 2017 and rig 212, our last new build of 2015, has been completed and has moved to its first location.

We will complete the upgrade of rig 103 and begin the upgrade of rig 101, to full 200-series Omni directional walking substructures with 7,500 PSI mud pump capability during the remainder of the calendar year. And at that time, no 100-series rigs will remain in the ICD fleet. We'll be 100% comprised of 200-series Omni directional walking ShaleDrillers.

Third quarter guidance; although no developed spot or term market for rigs has developed, we have seen tenders for pad optimal equipment with one-year term and some coalescing of short-term day rates for pad optimal equipment, in line with our first quarter guidance.

As a result of the effort to lower overall wellbore costs, we are seeing customers, who never before contemplated pad development, changing drilling programs and currently building multi-well pads using our pad optimal ShaleDrillers in their forward drilling programs.

Customers who had previously adopted small pads, are currently expanding the scale of future pads, providing additional demand for pad optimal rigs. We see all the signs in the field that the use of pads to optimize operators' field development economics will continue to grow, as will the wellbore intensity and size of newer pads.

The compelling economics of pad development, should drive the forward demand and utilization of pad optimal rigs that will manifest early, even in a modest recovery.

With that, I'll hand the call over to Phil, who will discuss second quarter financial results and provide some forward guidance.

Thank you, Byron and thanks, everyone for joining us today.

During the second quarter, we reported net loss of $652,000 or $0.03 per share, and adjusted EBITDA of $6.1 million. We ended the second quarter with 939 revenue days, representing a slight sequential decline compared to the first quarter of 2015.

During the quarter, our rigs achieved 79% utilization compared to 92% during the first quarter. On a sequential basis, we recognized revenue of $21.1 million compared to $22.3 million in the first quarter of 2015.

We had approximately 2.6 rigs earning revenue on a standby basis during the quarter, including approximately 1.6 rigs earning revenue on a standby without crew basis. Standby rates preserve margin, but reduce our top line in revenue per day operating statistics.

All of our rigs on standby have returned to normal operations and we expect to have approximately 1 rig month of standby revenue in the third quarter.

Total operating costs were $12.1 million during the second quarter. On a per day basis, our reported operating costs during the quarter were $11,855 per day. Our cost per day statistics benefited from rigs that earned revenue on a standby without crew basis. Excluding those revenue days, our fully burdened operating costs were approximately $13,783 per day.

Included in these adjusted operating costs during the second quarter, were approximately $213 per day of cost directly associated with crew transition costs related to idle rigs.

During the quarter, SG&A expenses were $3.8 million, flat with the first quarter. Included in SG&A expense was $800,000 related to non-cash stock-based compensation expense.

Depreciation expense was $5.2 million during the quarter. The approximate $900,000 sequential increase was due to the activation during the quarter at one of our new builds that had been on standby without crew status in the prior quarter.

We also reassessed the useful life of certain components of our drilling rigs and related equipment, which increased depreciation expense during the quarter and will accelerate depreciation expense going forward.

Adjusting the remainder of the year for these new depreciation assumptions and activation of new rigs, we expect depreciation expense to be approximately $5.7 million in the third quarter and $6 million in the fourth quarter.

We are currently forecasting a negative tax rate for the year of 9%, which resulted in our recording a small tax expense during the quarter. Tax expense for the remainder of the year is expected to be in the range of $400,000 in the aggregate.

At June 30, we had net debt of $49 million, comprised of cash on hand of approximately $12 million and $61 million drawn on our $155 million revolving credit facility. Our borrowing base under the credit facility was approximately $125 million at quarter end.

During the quarter, our capital expenditures were $14 million, primarily related to the construction of our 14th ShaleDriller rig, which was substantially completed ahead of schedule. During the remainder of 2015, we expect our capital expenditures to range between $13 million and $18 million.

This would bring our total CapEx for 2015 in line with our prior guidance of $54 million net of insurance recoveries. We continue to expect to end the year with net debt slightly below $60 million, consistent with our prior guidance. This CapEx guidance includes costs to finish our 14th rig, complete the upgrades of rigs 101 and 103 to 200-series ShaleDriller status, including 7,500 PSI mud pump capacity, as well as the purchase of previously ordered long lead time items that can be utilized in the construction of a 15th ShaleDriller rig.

Now I want to turn to our outlook for the third quarter. In the current operating environment, we would expect that our revenue days in the third quarter will range between 835 and 885 days, with the variance depending on contracting of our rigs being marketed in the spot market.

We expect our reported fully burdened margin per day to be in line with the second quarter and be in the range of $9,600 to $10,000 per day. Other operating costs we expect to incur that are not included in the margin guidance, should be in the range of approximately $300,000.

SG&A should remain in line with the second quarter. We expect third quarter interest expense to be in the range of $800,000 to $850,000.

With respect to our announced rig upgrade, we expect to incur a noncash disposal charge for each rig in the $2 million to $2.5 million range, relating to the replacement of the rigs existing substructure and related equipment. Right now, we would expect these charges to occur in each of the third and fourth quarters of 2015.

Finally, with respect to our shares outstanding, for the second quarter, we used 23.9 million shares outstanding to calculate our net loss per share. We would expect a similar number of outstanding shares to be utilized in the third and fourth quarters of 2015.

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

Thank you, Phil. And thanks to all call participants. I also want to say a special thank you to ICD employees in the field, the yard and the office, for their outstanding work supporting our company and our shareholders.

Operator, we're ready for Q&A.

(Operator Instructions) James West, Evercore ISI.

This is Dallas, in for James. I was curious to know, given that pricing is stable and demand for high spec rigs is improving, what do you guys think about your new build program and during 2016 if there are any plans to restart it, now that you've ordered some of those long lead time items?

The answer is, we haven't made that determination. We have the capability to either speed our new build up or slow it down, depending on market conditions and we'll react to market conditions. You mentioned the long lead time items, and yes, in fact, there are a number of those we've got in stock. We'll be receiving more.

So I guess the good news is, we can react on a dime, but we'll be very cognizant of current market conditions. As we said previously, when we see one-year term contracts coming into the market and available, that's the type of market we'll build into and obviously we're seeing that type of term right now. So I guess it's a qualified -- our expectation is, we will be building but we haven't made that determination to date.

I jumped on late, so I didn't hear if Ed was on, but if he is, I would love to hear his take on why SCR rigs and mechanicals do not serve as a price cap for the high spec AC rigs.

I'm right here. I really think that the market and the operators are really dictating the rigs of choice or the rigs that they're wanting to go further. I think the mechanical rigs, particularly in the horizontal market, are heavily challenged with the ability to efficiently drill the well, both in the vertical and horizontal section.

There are some SCR rigs that are capability of drilling the horizontal section. However, they become challenged in the move times. The industry is moving to an environment where we're producing wellbores. We're manufacturing wellbores and with that, the operator that has the ability to increase the number of wells per cycle, is at an advantage over that operator who chooses to go with legacy SCR rigs and thus, those rigs take longer to move. So you're at a disadvantage of drilling more wells per cycle.

That's the reason we believe that there is a structural change, as Byron stated in his opening remarks, in the industry and really a challenge, going forward, for the mechanicals and the SCRs. As opposed to the pad-optimal AC rigs that we're talking about.

Connor Lynagh, Morgan Stanley.

I was wondering if, granted there basically is no spot market right now, but I think previously you said the spot market was somewhere in the 17 to 20 range. Could you give us just a feel of where it's shaping up in that range? Is it towards the high end, the low end or is it just totally random, depending on who you're talking to?

It depends who we're talking to, it depends on what exactly they need, it depends on where they are. So I think the number moves around within that range. Ed?

I would add one other thing. I know there's a lot of discussion, particularly this past earnings release couple of weeks, regarding the spot market. There's one particular aspect of that, that I think is different from previous cycles in that it's hard to determine what the spot market is, because there have been so many rigs that have been farmed out.

And when you have a farm out situation, the operator that holds the contract has the incentive to reduce his financial exposure to another operator, who is trying to get that same piece of equipment at the cheapest price that he can.

So with that, it's hard to make a determination of what that spot market is. As a contractor, I really don't want to use that farm out rate that the new operator has contracted as a basis for what I want to bid against. I'm then bidding against myself. And so therefore, until we see this farm out market decrease, which is a positive from what we're seeing now.

We do believe the farm outs and the rate of farm outs are decreasing and the rigs that have been on standby without crews have essentially gone back to work, and thus, the increase in rig count over the last few weeks. I think in the near future, we'll start seeing a clearer -- have a clearer picture of the horizon of what the spot market will be.

Just so we can think about how you guys are going to operate here, would you say that you're generally going to, if you're bidding against a larger competitor, try to price at a discount to keep the crews working and be positioned for the next cycle here, or is your goal to sort of hit the highest rate in the market?

Connor, we get the highest rate and the longest tenor available in any market we choose to operate in, because of our size, we're not the setter of that day rate or that tenor. The larger competitors are. But we will not be disadvantaged in either day rate or tenor in any market we choose to participate in. Is that fair, Ed?

That's fair. I would add one other thing, Connor. I think historically over these cycles, as long as I've been in this business, it's hard to lead the market up, but I think the industry has shown much better financial discipline this time than what we've seen in previous cycles. So we'll let our bigger brethren establish what that market is going up, but we're going to hitch the wagon to the horse and ride with them.

Sounds like that plan hasn't changed, despite the challenging times here.

Jeff Tillery, Tudor, Pickering, Holt.

As I think about it, I'm curious to hear color on your customer base. You mentioned two new customers. I'm curious of your conversations and what's driving that? Is it just more established nature of the company? And then furthermore, around the new builds, how much of the incremental new builds has CapEx that's already been incurred? So I guess I'm curious what you're incremental cost is to get the next handful of rigs out?

I'll talk about the customer base. We made a decision several years ago, to have a customer base that has the ability to drill through the cycles. I think if you look at our customer base, we've achieved that. Those are the same customers that we're focused on now and those are the same customers we've had and are having discussions with going forward.

I think the key now is going to be timing on their part; depending on the price of crude, commodity pricing as to how they're going to firm up their drilling plans going forward. But we're going to focus on the high end operators that have the ability to drill through the cycles.

On your other question, at the end of the year, for the 15th ShaleDriller rig, we'll be into that rig, with the deposits and deliveries of equipment that we'll take delivery of, about $6 million to $7 million. On the three other rigs, we've made deposits on those rigs between $2.5 million and $3 million per rig.

Rob MacKenzie, Iberia Capital.

Phil, I wanted to follow-up on that last question little bit. When you're looking forward and thinking about building the 15th ShaleDriller or the 16th, 17th and 18th, will you guys consider the amount already spent, a sub-cost, in terms of your investment decisions?

We can argue about this a number of different ways. If we are talking about return on invested capital or DCF models or incremental analysis, what it boils down to is we need to have equipment fielding, crewed with safety records, with uptime records out and in the market, before the day rates begin to improve.

We firmly believe that the market for pad-optimal equipment is going to improve in 2016 and 2017 and our fleet size is the most important thing that will determine the return to our shareholders. So yes, we do look at it. We run DCF models.

We go through it with our Board. We look at incremental analysis and when we're looking at the material we've already bought, we don't treat it as sunk in any DCF analysis. We treat it as opportunity cost. So we run the models, but there's nothing that we're looking at, except for contract term, that would prevent us from beginning our build program again right now.

So we're waiting for term and the models all work, even in the current price environment, Rob.

Follow-up question on another topic, if I may. I think maybe it was Phil who said, the fully-loaded cost per day in the quarter, netting out the impact of the idled rigs getting paid, with $13,783 a day. What would Q3 be, rolling into the fact that I think you said you had one month of paid standby and one rig still; where should we think about that number coming out this quarter?

If you look at our operating cost, the standby without crew factor kind of makes the statistic a little bit hard to tell, and that will be less. If you take out standby without crew, our rig level operating costs are in the $11,000, $11,300 type range. Then you've got other costs that are added on top. And kind of on a normal basis, we run $12,800 to $13,000.

In this environment, we are going to have some inefficiencies, because the rigs aren't effectively 100% utilized. So I'd say, and I think $13,500 is the right number for us, plus or minus, depending on the quarter.

And then going forward, you guys mentioned a couple of times, I think Ed as well, there is talk about term work out there for pad-optimal rigs. Can you give us a feel for how those conversations are developing? When you think you might see some of that turn into actual contracts?

I think, several months ago there was a lot of momentum. And it appeared that there was going to be some significant activity that would begin in the second half of 2015 and move into the budget years in 2016 for our customers. So there was a lot of discussion and energy that was being built up about picking up the preferred rig of choice by these operators. And being prepared to move in, go to work in 2015 and then enter their new budget season of 2016.

However, with the recent collapse in the price of oil, that has really been now deferred and tabled, until they can see some consistency in where the price of oil is going to settle down. If it goes to 40, 35, I think all bets are off. However, we're still positive about what we're seeing, and we're all positioned and our customers are positioned to increase activity just as quickly going forward, as it was decreased, coming down, beginning in November, December of last year.

Let me add a little bit of color to that. So this demand has been postponed, not eliminated. And as I said in my prepared remarks, people who have never drilled with pads are building pads. People that have used pads are building bigger pads. And that's going to drive the demand for the entire asset class that includes omni-directional walking systems and so on and so forth.

So when we get to the point where we've got some stability in oil prices and activity ticks up, you're going to see this asset class move past the -- I think we're already past 80% utilization. But certainly, we'll begin to then chip away at the lower capability AC fleet that's stacked, and that's going to provide, first of all, utilization support, and then secondarily, pricing power to the smaller pad-optimal fleet. And so, I think it's just a matter of time. We thought we were there. It's been pushed a little bit to the right, but it's right on the horizon.

Kurt Hallead, RBC Capital Markets.

So you mentioned some interesting things on the farm-outs. I may have missed it, if you guys gave the number. What percent of the rigs right now do you think are kind of being farmed-out? Do you have any market intelligence on that?

Not specific, Kurt. No. There have been a lot of rigs that have been released. A lot of rigs have went to contract that were stacked or put on standby without crews, and those have been -- any activity or any opportunities that came up from another operator to upgrade their rigs, those were kind of put into the system and farmed-out.

I mean, so the contractor doesn't have -- they don't have a discussion in that, other than to approve the operator that's taking the farm-out. That's the only contractual discussion they have. It's really a financial discussion between the two operators.

So no, Kurt, we don't see. We can't really gauge. We see it out there generally. You see it, because bid requests disappear. First of all, you got the farm-outs, where either the operator gets its full day rate and it goes to some discount to someone else. So you work through that, then you see the standby rigs go back to work at full day rate, well we've seen that.

So, I think we've worked through whatever that portfolio of stacked or semi-used equipment is, and we've cleared that out to the way. And that provides the space for real increases in utilization of the existing fleet. I think that's where we are.

Now, I'm kind of curious too, because you guys mentioned, the fact that you're getting enquiries about one-year contracts for pad-optimal rigs. Are these in your existing fleet or are these for newbuild rigs?

Both.

Given the number of rigs that are available in the marketplace, why would anybody be thinking about building a new rig right now?

I think, the prudent operator right now, with the price to where it is, if they have ability to drill through the cycles, I think the prudent operators want to test the market to see what's that contractor's appetite, at what rate to take a one-year term? I mean it makes sense for them to sign up a rig for as long a term as possible, at the lowest rate.

We're trying to shoot for the opposite. We're trying to get the longest term at the highest rate. So, I think it's encouraging to see operators that several months ago wouldn't even consider a term, are now trying to determine what's the appetite out there for one-year term, what's the rate.

So Kurt, if there is only a 150 pad optimal rigs in the entire North American fleet across all of us, and that rig in a pad application, particularly a large pad application, significantly out drills any other piece of the equipment that's out there, and this is not just the equipment, it's the crew, it's the safety, it's the entire package, and you're looking at your drilling program and across the board, you've got to take your cost structure down.

And the most efficient way to do it on the drilling side is pads, and particularly larger pads. You've got a very limited amount of equipment to choose from, which to a great degree right now is already dedicated to operators. And if you're putting a drilling program together and you're faced with that choice, what you do is you try to go to term. I think, again, that's what we're seeing.

And then maybe just one last one to follow-up on. You guys are at the tail end of the earnings reporting period, so we heard a number of different data points out there on pricing and so on. What kind of pressures are you getting from E&P companies? And maybe in recent weeks, given now that oil is in the mid-40s versus what it might have been in a couple, has there been a renewed sense of urgency by E&Ps that that's going to get more price relief?

Kurt, I think first off, we're always getting pressure on pricing, regardless of the cycles. I mean, that's the one driver that operators are always trying to drive the price down. We're not seeing the pressure we did in the beginning of the cycle. Again, like I said earlier, I think we're seeing some really good financial discipline right now in the industry among our competitors, all of us.

I will say that in our conversations, one of the comments that the operators are making that has been consistent across the board, is that the drilling cost have already pretty much come down, and they are focusing most of their attention on the completion costs and the frac cost. What we've heard, that's where they need to get more savings on that cost.

Now, whether it's there for them to achieve, I don't know, I'm not in the pressure pumping business. But, we're not seeing as much pressure as we did in the first part of the cycle today, on day rates, as we were in the beginning of the cycle.

Again Kurt, I think that's equipment specific. I'm not sure that's a comment that cuts across the industry.

Kurt, we don't have any mechanicals or SCRs, so I can't really respond to you on how that market's being treated.

Thomas Curran, FBR.

Byron or Ed, when it comes to these one-year term tenders that have started to emerge for pad-optimal rigs, would the 100-series rigs, the last rig that you're operating, would they qualify for those tenders? And if so, have you bid them on those tenders or are you having other similar conversations around them?

No. That's the reason we've made the decision, along with an approval by our Board of Directors, to go ahead and modify those to the 200-series.

But as modified, we're bidding them.

That was my question. Post modification, are those being bid on and do they qualify for the type of opportunities that are emerging?

Yes.

And when it comes to the reference you made Byron, to certain operators that are actually deciding to change their pad structures and move towards bigger pads, is that being done with the expectation that once completed, they'll be looking to deploy one or more of your rigs on to those pads? So even if they haven't necessarily issued a tender yet or awarded a contract, is your expectation that once they are done with that construction, you'll be the beneficiary of the rig contract?

So in terms of the comment I made, that comment was specific to people we are working for now. But that comment is also general. We're seeing that across the industry, and it makes sense. In any oil price environment, the operators group needs to lower its cost of wellbore construction. And if it's a $100 oil or $40 oil, that's the case. Lower price obviously accelerates and focuses people on that process.

And on the drilling side, what's been proven over the last five years or so, is it's the most efficient way to manufacture wellbore in the unconventional resource base, which has stacked pays, homogeneous reservoirs to a larger degree over a large acreage position. You're taking an offshore technology, mainly platform drilling, and you're moving it on land in the form of pads.

And the economics have been proven and the industry is moving toward that as a drilling solution. And in the context of that being a drilling solution, the most efficient way to drill that process, unequivocally, is pad-optimal equipment. And so, this is exactly what you're seeing unfold in the market.

And then, one more for me. Phil, could you update us on where the contract revenue backlog stood as of the end of the quarter? And the percentage you have covered by early termination fee protection?

Well, all the backlog will be covered by early termination protection. At the end of the quarter, second quarter, our backlog was $112 million.

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

Well, thank you. I have no closing remarks, except to reiterate my thanks to our investors, the analysts and our employees. And we look forward to continuing to update you, meeting with you all, and then joining again on our next conference call. Thank you very much.

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.