Independence Contract Drilling Inc (ICD) 2018 Q1 法說會逐字稿

Good afternoon, and welcome to the Independence Contract Drilling, Inc. First Quarter 2018 Financial Results Conference Call. (Operator Instructions) Please note this event is being recorded.

I would now like to turn the conference over to Philip Choyce, Executive Vice President and Chief Financial Officer. Please go ahead.

Good morning, everyone, and thank you for joining us today to discuss ICD's first quarter 2018 results. With me today is Byron Dunn, 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 our full reconciliation of net loss to adjusted net loss, 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 afternoon, and thank you for joining us today. I'll start by reviewing ICD's first quarter 2018 operations and update our outlook for the year. Phil will provide details on our first quarter financials. And then we'll take questions from call participants.

In the first quarter, ICD generated record revenue and continued full utilization of our pad-optimal ShaleDriller fleet. Sequential revenue per day improvement began, as several contracts rerated from cyclical lows to the current robust and improving market dayrates. This is a trend we fully expect to continue throughout 2018, as older contracts rerate and new contract extensions are negotiated.

I'd like to provide some additional color on this. Since the low point of the downturn, dayrates on contracts we have signed have increased over 43% and recontracted dayrates on rig rolls have increased over 26% year-to-date. It is not unreasonable to expect similar percentage improvement in dayrates for pad-optimal equipment over the next 12 to 18 months.

Today, we reported a backlog of $52.7 million with an average dayrate of $19,650 per day. However, we are at the signature stage on 4 contract extensions that will increase our March 31 backlog to $91 million with an average dayrate of $20,200 per day. These 4 contracts are each being extended for a year, months before their current contracts' respective expiration at dayrates up over 10%, and in one case, the dayrate increase itself begins months before that current contract expiration.

Over the remainder of 2018, with the contract expiration matrix we put in place and including the effect of the 4 to-be-executed contracts and newbuild pad-optimal ShaleDriller 214 scheduled to enter the fleet during the third quarter, we will have 2 rigs recontracting during the second quarter, 3 in the third quarter and 2 in the fourth quarter.

ICD is extremely well positioned to continue to realize revenue per day improvement and to continue to post backlog average dayrate increases.

In the first quarter, operating cost per day statistics were in line with our guidance. I expect field-level cost to decrease throughout the year. Some of this decrease will come from new contract terms, as contract renewals include more favorable cost-sharing allocations. Further improvement will be driven by initiatives put in place regarding crew utilization, staffing and field supervision. I am very pleased with the improvement in cash cost per day at the rig level already evident, especially when taken in the context of ICD's growth.

Unlike the rest of our industry, whose rig fleets and crew requirements had actually shrunk compared to pre-downturn levels, ICD's fleet and the number of operating personnel we have been required to recruit and train has grown substantially. We have met this unique challenge, while continuing to satisfy the increasingly complex demands of our customers.

In fact, during the year-to-date period, as ICD has ramped to meet fast-growing customer pad-optimal rig demand, our unscheduled downtime has run at 2%, an exceptional level in the industry and a testament to the men and women working at the rig face as well as our operations and field maintenance teams.

As I mentioned on our previous call, demand for pad-optimal land drilling rigs is greater than the U.S. fleet can deliver. And this trend is growing as our clients, the top-tier players in the shales, expand wellbore manufacturing principles and design successively more complex pad drilling programs.

In this microenvironment, ICD continues to deliver exceptional results to our customers. A good example of the value-add of ShaleDriller's advanced omnidirectional moving system was on display during the first quarter, where we completed a 215-foot completely diagonal walk for a customer on a single pad in only 4 hours.

A rig equipped with an X-Y walking system would have had to have moved 200 feet in the X direction, then 60 feet in the Y direction, taking much longer period of time. And the skidding system would not be capable of meeting this customer requirement. Additional value is delivered to our customer on this pad, as our rigs aren't operating on highline power. And our moving system allows the customer to plan simultaneous operations, which they expect to implement in the near future.

ICD pad-optimal ShaleDriller rigs on complex pads deliver extraordinary financial results to our customers, as they move further to full wellbore manufacturing operations. It is not economically feasible to execute these extremely complex well designs by skidding, upgraded, X-Y walking or other legacy moving systems.

So wrapping up, ICD's fleet is at full utilization. The economic manifestation of the shortage of pad-optimal rigs has begun. Dayrates and contract tenures are improving. We continue to build a strategically staggered contract backlog at higher dayrates with customers who have long-term complex wellbore manufacturing programs requiring pad-optimal equipment. And we are in growth mode with our 15th ShaleDriller on schedule to enter our fleet early the mid-third quarter. Our leadership team is reducing field cost across the board, while meeting the increasing demands of our customers.

With that, I'll turn the call back over to Phil.

Thank you, Byron. In the first quarter, ICD reported an adjusted net loss of $4.3 million or $0.11 per share. Based on 1,259 revenue days in the first quarter, a small decrease from the fourth quarter of 2017, ICD reported record revenue of $25.6 million, including pass-through revenue of $1.6 million.

Average revenue per day of $19,055 came in line with the higher end of our guidance and represented a 4% sequential increase compared to the prior quarter. Cost per day of $13,414 came in line with our guidance and was impacted by the shorter quarter and seasonal payroll taxes. Overall gross margin per operating day came in line with our prior guidance.

SG&A expenses during the quarter were $3.5 million, including $650,000 of noncash compensation expense. Cash SG&A expenses of $2.9 million increased sequentially as a result of higher incentive compensation expense compared to the prior quarter as well as typical year-end legal and accounting professional fees.

Depreciation expense and interest expense came in line with our prior guidance. Tax expense was de minimis, included a deferred tax benefit associated with the Louisiana state taxes.

At the end of the quarter, we had net debt, excluding capitalized leases, of $50.7 million. Our borrowing base on our credit facility was $103 million, exceeding the $85 million of commitments under the facility.

Our capital budget for 2018 has increased slightly to $22 million. We ordered an additional drill pipe string ahead of the recent steel tariff announcements and will be adding a third pump to a rig.

Cash outlays for capital expenditures in the first quarter, net of disposals, were $6.1 million, of which $5.3 million related to deliveries occurring during the fourth quarter of 2017.

Accounts payable at quarter end included approximately $4.6 million relating to first quarter deliveries. At March 31, 2018, our backlog was $52.7 million. Byron mentioned 4 contract extensions that are at the signature stage, which will significantly increase backlog in aggregate dollars and average dayrate in backlog.

Second quarter guidance. We expect our rigs will again achieve full effective utilization, with small number of idle days for rigs transitioning between customers. Revenue days should range between 1,260 and 1,265 days during the quarter. Revenue per day should range between $19,300 and $19,500 per day as we continue to realize benefits from improving dayrates under contract extensions.

We do not expect dayrate improvements for the 4 pending contract extensions that Byron mentioned to kick in until the third quarter of 2018. We expect fully burdened operating cost per day to range between $13,100 and $13,300 per day. These per day expectations exclude pass-through revenues and expenses.

We expect to fully absorb all rig construction expenses into our newbuild during the second quarter, which is on schedule for delivery beginning in the third quarter. SG&A expenses should approximate $3.4 million, of which $700,000 will be noncash. Depreciation expense should approximate $6.7 million. Interest expense should come in around $1 million. And tax expense should be about $50,000 during the quarter.

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

Thanks, Phil. I have no other comments. So operator, if you would open the line for questions, please?

(Operator Instructions) And our first question comes from Taylor Zurcher with TPH.

First question is just on the 16th newbuild. Could you just remind us -- I know you talked about it in the past, how much CapEx will be required to get that rig out in the field? And it sounds like #15 will be out there early to mid-Q3. In terms of timing for the 16th, if you made a decision, would it be similarly a quarter or 2 before you could get it out there? And then finally, what's preventing you today from making that decision? Is it a balance sheet decision or really just a mix of term and price that you're looking for that you're not quite getting today?

The rig under construction will be ready to go out at the end of June. The next rig, it's still unclear what we're going to build. And there is still some -- ambiguity is wrong word. There's some differences in what the industry thinks it needs in the next cycle of newbuilds. And until that becomes clearer, we're going to -- we'll hold off. The -- from a cost standpoint, if we were to build a traditional ShaleDriller 200, it'd be another $14 million. If we were to build a what we call the 250 series, which would have 3 mud pumps, 4 engines, additional racking capacity, it will be a couple of million dollars in addition to that. And as you pointed out, what we're doing is we're trying to match dayrate, rate of return, what the industry really needs. And we want to make sure what we put out is going to satisfy those needs for a long period of time. So we haven't made a decision yet, and those are the variables.

Got it, makes sense. Second question is just on cost. I if I heard you correctly, I think the Q2 cost number is going to come down slightly. I realize there are some transitory, I think, payroll impact in Q1. But as we think about the cost level moving forward, you've got a lot of rigs in the Permian, the labor market is tight. Is there any wage inflation, realizing it's a pass-through cost to you, embedded in that cost guidance and consequently in the dayrate guidance you provided in Q2? And how should we think about that over the back half of the year?

Our dayrate is separate from cost. The -- there is no cost inflation in terms of our employees at the rig level. Bear in mind that most of our -- a vast majority of our employees don't come from the Permian area. We work 2 weeks on and 2 weeks off. And to the extent there was any inter-period, inter-contract wage cost increase, that's a pass-through to our customers. So our margins would not be impacted.

Our next question comes from Daniel Burke with Johnson Rice.

One more on cost just to stay there, I guess. Byron, you alluded to potentially see some field-level cost decreases due to more favorable contracting arrangements with customers. Can you quantify maybe what that means? Is -- I would imagine the dayrate escalation is more material, but figured out I'd push there for a second.

Yes. The dayrate escalation is vastly more material. When you talk about contract rolls, and I'll turn this over to Phil when I get done, he can quantify for you. But one of the things that happens during various contract negotiations during the cycle is it may be that we take a dayrate and embedded in the contract is forklift rental, something like that. So what we've been successful in doing is taking those things out of the system, so that part of our cost structure is decreased. Another thing to remember is sometimes when people report dayrates, they include pass-throughs. And so you'll see a high 20s dayrate that may include $4,000 a day in pass-throughs. It's not really a dayrate. So we avoid that. When we report that to The Street, our number is a pure number. The other thing about cost structure currently is we're looking hard at how we allocate and work with our field supervisory team, and I think there is a way we can continue to do what we're doing, and in fact, improve our supervisory structure at the same time taking a couple of hundred dollars a day out of average costs. So Phil, do you want to see if you can quantify?

Yes, I guess, the only thing I'd add on top of that, Daniel, is in addition to the rentals, we do have some contracts where we will have a sixth man on the rig that we're not -- we know that our older contracts, where we weren't getting compensated for that. Our contract renewals now are getting compensated for those things. And it's probably overall across our fleet. When we get back to what I consider more of a normalized cost-sharing arrangements, it's probably several hundred dollars a day across our fleet.

Great. That's helpful. Another one for you, Byron. I just wanted to reconcile a couple of comments you had on dayrates. I thought I heard you say your recontracted rates are up 26% year-to-date. And then you referred to a couple -- or excuse me, 4 contracts where dayrates will be up over 10% versus prior. Just will you help me maybe reconcile those 2 comments. What was the 26% referring to?

Okay, I'll help you as much as I can without disclosing anything that I think we don't want to disclose on our conference call. So the 26% related to the marginal rate we're signing new contracts right now versus the low we came into this year at. So that's a year-to-date improvement. The 43% number is the same calculation, but the starting point was the low point of the downturn. The 10% related to those specific contracts and the improvement in dayrates, just associated with them, from where they were initially signed to where they're rolling too.

Okay, got it. And then maybe a last one. Maybe this one is for Philip. But in the past, Philip, whether for just the second quarter or few quarters out, you've been able to share some of the contracted dayrate backlog. Maybe you could do that now. Maybe it's tough, because you've got those 4 sort of pending contracts. But at a minimum, could you give it to us for Q2 if it's available?

Well, yes, let me kind of give you -- this will be -- I'm going to give you the guidance based on the -- of those 4 contracts that we expect to be signed this week -- later this week. So the backlog -- that adjusted backlog will be $91 million. The 2 -- the 4 contracts really don't affect the second quarter. You're going to have an average day rate in contract there about $19,600. Third quarter, $2,200 -- $20,200. About the same in the fourth quarter. And then it starts going up to $20,400 in the first quarter next year and over $20,000.

That also depends on -- we've got some rolls coming up. And so what Philip gave you is status quo in the backlog. The numbers should be materially higher than that, because we've got 4 or 5 rigs that will recontract during that period that will pull that number up.

Right. Got that. Maybe the last simple piece of that is, what we are the uncommitted rig days in the $91 million backlog for Q2? I think you've got 2 rolls, right, you said later this quarter?

Yes, uncommitted. Let me -- I have to do some math here. It's probably a rig, and it's probably about one rig's worth.

And our next question comes from Tom Curran with B. Riley FBR.

Byron, when it's comes to the specific technical aspects of what would be the 16th rig that you're discussing with potential customers, could you expound upon what is the nature or the range of capabilities for the decisive specs that will determine which model you go with? What exactly is it that you're trying to clarify with customers that they're going to want that rig to be able to do? And what aspects of the wellbore would those specs apply to?

Okay. There's 2, I guess, major areas that are in discussion. One is the drill pipe setback capability of the rig. So to the extent you're doing Wolfcamp B wells, you're targeting deeper, longer laterals -- and we're talking to people about laterals that are extremely long. It want the ability to rack back additional pipe. And then the question is, is it 5 inches? Is it 5.5 inch? And the -- and that crosses over into how many mud pumps do you need? And the issue there is, when you've got long laterals, you want to keep -- you want to be able to maintain turbulent flow in your returns. So if you think about the energy in the mud system, you've got to get it down to the bit, you've got to have right hydraulic horsepower at the bit face, you're going to be turning a mud motor, which requires additional hydraulic horsepower. You've got to keep the bit cool. Then you have to return the cuttings to the surface, so you don't get stuck. And that requires, after all those pressure drops, the maintenance of turbulent flow characteristics throughout the annulus all the way up the hole. And that then is a 2-pump, 3-pump question. Okay, well, when you do that, the question is, what size VFD do you need, that varies too. So every time you move one thing, several other items change. And so it's not an Erector set. You can't just bolt something on and say, okay, you got it. There is engineering changes that occur throughout the system. This is why upgrades are so difficult. So people talk about upgrading rigs and we're going to make this rig walk and so on. It isn't that easy. And what you wind up with in some cases isn't really fit for purpose. So this is why -- this is where newbuilds come in. And so these discussions vary between operator, how much pipe do they need, what kind of setback do they need, what's the diameter of the pipe, what's the pump capacity requirement, which then relates to power requirements. So that's the mix of issues.

Very helpful. Thank you for elucidating there. And then as part of this ongoing discussion with customers about what they're going to be looking for in the next wave of innovation and enhancements, do you find that some customers are starting to evaluate you or asking what you can do for them not only on ROP and days per well, but other wellbore-related performance metrics such as wellbore placement or tortuosity? Are they starting to expand the envelope of performance metrics?

Okay. Well, so let's take that in a different step. Tortuosity is a reservoir engineering issue that relates to permeability, but then the degree to which the interconnected pores aren't straight. So that's not something we have anything to do with. That's something that reservoir engineers would take a look at. What I can deliver, what the drilling industry can deliver to our customer base is superb safety statistics and low unscheduled downtime, which is why I talked about that in my prepared remarks. Rate of penetration depends heavily on mud chemistry, mud maintenance, bit selection, bottom hole assembly design. And that is the purview of the E&P customer. So what we can provide for them is a safe piece of equipment that operates with the highest possible uptime and moves the quickest possible between wellbores, which is why I talked about that diagonal move, which save them days. And then the rate of penetration is really up to them. So what you're alluding to is more of a partnership agreement where you take on a 50- or 100-well program and those attributes, those issues would be part of that conversation. We don't have the balance sheet for that. But I think that's an -- I think the industry is probably moving that way. That's not something that we would do, because you need a petroleum engineering team and so on to be able to make those decisions.

Your next question is from Kurt Hallead with RBC.

So Byron, I was curious, given the challenges that are facing -- positive challenges, that is, that are facing the market right now, notably tight labor markets and so on. What do you -- is this going to be a major limiting factor, you think, for ICD and its potential growth plan as you get out into 2019? And maybe a better way of asking it is, how are you planning in advance, right? And our oil company is saying, well, look, we like what you do, we like what you've already done, but we're not quite sure if you can kind of man these rigs. I mean, are you facing any, getting any pushback whatsoever? And if so, how are you counteracting that?

Yes. Short answer is no. Longer answer is, we've got competitors that are for sale. We have competitors that have financial issues. And so we have no shortage of incoming relative to our needs. Where it's been difficult, and I've talked about this in the past, is pure entry level people. And there, we're having some issues with the lack of knowledge of hydraulics, electronics, mechanics, which in the past we've typically had in the entry-level folk. So it's been a longer training period. But even that is abating now because of some of the industry dynamics of companies for sale and companies that have financial issues. So I don't see that as an issue anywhere on the horizon, Kurt.

Okay, great. That's great. That's good. That's good color. And I'm going to apologize, I might ask you a question that might have been answered, but I've been bogged down with a lot of things this morning, as you probably know. So when you look at the prospects for your new rig and then you look for rigs that might be coming off contract and then kind of rebooking, I know that there have been a lot of conversation in the industry that the requirement is now like 2 years for recontracting and upgrading assets and 3 years for newbuilds. So can you give us some insight as to how the terms are evolving for the contract extensions and new contracts?

Well, we're pushing back on 2 year right now. We'll see how successful it'd be, because I think we're in a very substantial dayrate improving market. This looks like a lot like the market looked when we IPO-ed the company and dayrates were 28, on the way to 30. And I'm not saying that's where they are today, but the dynamic of the market is quite similar. So we're very happy to work with 1-year terms. I did extend some contracts that still had 3 to 6 months on them for a year. So arguably, we went past our year. That's sort of -- that 1-year target of ours, but this was for a very important client we've really partnered with. And as I mentioned, the dayrate increases begin before those contract terminations. So there's a little bit of give and take on that. But in general, we've looked for 1-year term and expect dayrates to continue to substantially improve through this year and next year.

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

Nothing really. I want to thank all of our -- all the folk on the call. I know we've got some investors, along with the analyst community. We thank you for their support, and we look forward to speaking with you on our next conference call.

The conference has now concluded. Thank you for attending today's presentation, and you may now disconnect.