Independence Contract Drilling Inc (ICD) 2016 Q3 法說會逐字稿

Good morning and welcome to the Independence Contract Drilling third quarter 2016 financial results conference call. All participants will be in listen-only mode. (Operator Instructions). Please note today's event is being recorded.

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

Good morning, everyone, and thank you for joining us today to discuss ICD's third quarter 2016 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 documents our documents on file with the SEC. In addition, we refer to non-GAAP measures during the call. Please refer to the earnings release and our public filings for a full reconciliation of EBITDA and adjusted EBITDA and for the definitions of our non-GAAP measures.

And with that I will turn it over to Byron for opening remarks.

Good morning, everyone, and thank you for joining us today. Following our usual format I will review third quarter results and provide observations on current and expected market conditions. Philip will detail our third quarter financials and then we will take questions from call participants.

The third quarter was transitional for ICD. We booked 774 revenue days in the quarter and on a very compressed five-week time scale we reactivated five rigs, more than doubling the operating fleet while deploying $5.2 million in reactivation and capital costs.

Two of the rig reactivations included fluid system upgrades to 7,500 PSI and one included the addition of a third mud pump. Two of the rigs reactivated during the quarter were deployed to the Louisiana Haynesville, a new region for ICD where, as in the Permian, operators are demanding high impact pad optimal equipment. This is a basin we foresee as another key focus area for us complimenting our Permian operations base.

ICD is recognized as a premiere employer and we had no problem attracting the required talent during rig reactivation. By virtue of being some of the first rigs back to work we were able to utilize first mover advantage to attract the best talent available in the market through an active and successful talent acquisition effort. Additionally, and subsequent to the end of the quarter, we signed two additional new contracts for rigs deploying to the Haynesville and they'll be deploying in the late fourth quarter bringing the number of ICD rigs contracted in the Haynesville to four.

Importantly these are one-year term contracts. Pro-forma for these new contracts, 92% of ICD's available rigs are now contracted. Having said that it is important to note that several of our rigs are on short-term or well to well contracts. Rig pricing is very aggressive and forward utilization during market stabilization may be choppy.

I would like to point out that ICD is working for, partnering, and contracting with mid to large CAP publicly traded ENP operators and large well capitalized private operators who embrace pad drilling and high impact long laterals using the full capabilities of omni directional walking, 7,500 PSI, dual fuel, pad optimal equipment. The operators using ICD pad optimal rigs are now drilling low calorie wells.

They are planning long laterals and higher number of wells per pad. They represent the rise of a new progressive group of ENP operators that recognize that adopting technically advanced pad-optimal rigs in a well bore manufacturing model, utilizing multi-well complex pads and long laterals, reduces the full cycle fuel cost base, provides permanent efficiency gains, and delivers higher return wells at a lower cost. This represents a significant competitive advantage relative to their competitors that use legacy lower tech rigs.

I would like to talk, for a minute, about day rates now. Day rates for pad-optimal rigs are not where we would like them to be, still in the mid to high teen range. Currently we are seeing aggressive public and private contractor pricing and do not expect any day rate improvement in the near term. It is important to note that I'm specifically referring to true day rate and not a revenue per rig number, which may include trucking, directional drilling, casing running, and other services and not a net net blend and extend outcome.

As we have noticed on previous calls, the first sign of a healing market is contract tenure extension, which we are starting to see, then followed by day rate improvement. In the current market recovery aggressive pricing by many public and private competitors may push out the timing of day rate improvement and, in any case, we see no current or nearterm day rate improvement.

I will talk for a second about cost structure, reflecting the aggressive redeployment of rigs, third quarter operating cost was higher than normal. The transition costs in the quarter included staffing in advance of rig mobilization, increased overtime and on the capital side, working capital build. Also a reported incremental margin on revenue generated by rigs reactivated from standby was near zero as we captured the entire operating margin on those rigs through our standby rate.

During the quarter we rationalized our executive leadership team, SG&A, and as a modular manufacturer our rig manufacturing cost base, taking an aggregate of $1.5 million out of our forward run rate cost structure. We expect this forward run rate structure to be stable and scalable throughout 2017.

In the third quarter cash operating cost at the rig level, for operating rigs, ran at approximately $10,600 per day and we expect those costs to remain flat for rigs operating through a quarter. More importantly is our rigs on standby go back to work and our fleet begins to approach full effective utilization. We expect fully burdened operating costs to trend to about $12,500 per day.

Along with the rationalization of our rig construction, overhead, and field operations, we also completed a review of our equipment inventory and opportunities to standardize items across our rig fleet with minimal out of pocket cash cost to ICD. As a result of this review we identified equipment based on early 200 series specs and out of spec equipment relative to the current 200 series design as well as equipment we have standardized on a different vendor. We believe there are opportunities to dispose of this equipment for cash or to exchange it for equipment that we have standardized on.

During the fourth quarter we intend to monetize or exchange these assets. We will likely book a fourth quarter noncash charge of about $4 million, depending on the realized sales price or the structure of equipment disposition. These are noncash charges and we will use the cash generated through sales or equipment gained through exchange to further upgrade and standardize our fleet. Philip will provide additional detail about this process later in the call.

Our capital budget for the remainder of 2016 has increased from $1.3 million to $7 million as we pay for additional upgrades completed during the third quarter and continue upgrading rigs to service.

As I conclude my prepared remarks, it appears that the North American land drilling cycle has bottomed. But it is important to note that many rigs are on short-term well to well contracts and industry pricing is aggressive. This may result in choppy rig utilization going forward. If commodity prices remain in the $50 per barrel and $3.00 per MCF range 2017 should be a solid recovery year, where utilization firms within the confines of the current day rate range.

At this point I will turn the call over to Philip who will run over through third quarter financials with you.

Thank you, Byron.

During the third quarter we reported a net loss of $7.2 million or $0.19 cents per share. Adjusted for noncash charges associated with rig upgrades our net loss was $6.5 million or $0.17 cents per share. Included in this net loss were approximately $2.6 million or $0.07 per share of reactivation costs for five rigs, as well as severance costs associated with the consolidation of portions of our rig construction and field operations.

Adjusted EBITDA, including the reactivation and severance costs, for the quarter came in at $1 million or approximately $1 million. And was $3.6 million excluding those costs. Fleet generated 774 revenue days, representing a 6% sequential increase from the prior quarter, slightly ahead of guidance as we reactivated one additional rig during the quarter. This included 222 days earned on a standby without crew basis.

Our marketed rigs achieved 64.7% utilization during the quarter. Overall we recognize revenue of $14.5 million and pass through revenues were approximately $1 million during the quarter. Gross margin per operating day, excluding reactivation and rig construction expenses, was $7,806 in line with our expectations and guidance.

Reactivation costs for the five rigs, totaling $2.5 million, exceeded our guidance principally due to the reactivation of an additional rig, as well as additional costs associated with inventory items purchased across all reactivated rigs that we expensed when purchased. Rig construction costs that were expensed during the quarter were $300,000 and pass through costs were $1 million during the quarter.

Selling, general, and administrative expenses were $3.2 million including severance payments of approximately $100,000, associated with the consolidation of our rig construction and field operations. SG&A expense included $1 million related to noncash stock based compensation and that included a $100,000 benefit associated with stock award forfeitures. SG&A expense, adjusted to remove severance expenses and noncash compensation, represented a 28% decline from the prior year quarter and a 6% sequential decline from the second quarter of 2016.

During the quarter depreciation expense was $6 million and tax expense was de minimis. At September 30th we had net debt, excluding capitalized leases, of $15.1 million. A $5.8 million increase in net debt, compared to the prior quarter, was split relatively evenly between capital expenditures associated with rig upgrades and working capital investments associated with the reactivation of five rigs. Our borrowing base under our credit facility was approximately $78 million at quarter end.

Pro forma for adding the idle rigs, associated with our two new contracts, the borrowing base at quarter end would have exceeded our $85 million commitment level. Cash outlays for capital expenditures net of disposal and insurance proceeds was $6.7 million. Our backlog of (inaudible) contracts at September 30, 2016 was approximately $40 million, which excludes the two 12-month term contracts that were signed following the end of the quarter.

Byron mentioned that we made improvements in our cost structure by consolidating portions of our manufacturing overhead and field operations. We expect that this will manifest itself most noticeably in a reduction of our rig construction overhead costs. We previously had discussed that these costs, assuming no rig construction activities during any particular quarter, could be approximately $750,000 per quarter. Going forward we expect these costs to be approximately $450,000 per quarter under the same assumptions.

Benefits to our SG&A cost structure will mainly be through a reduction in stock-based compensation expense. Looking at the fourth quarter we have approximately 800 revenue days under contract, an additional potential 120 revenue days tied to renewing stock market contracts expiring later during the quarter. Rigs four our two newly signed contracts are not scheduled to commence operations till January first of next year.

Assuming no rigs are returned to us or there is no idle time (inaudible) market rigs between customers, our best estimate is that our revenue days will range between 910 and 920 days during the fourth quarter of which we estimate approximately 10% will be earned on a standby basis.

Approximately 40% of these revenue days will be from term contracts signed in 2014. We estimate our margin per day during the fourth quarter to range between $6,100 and $6,600 per day. The sequential decline compared to the third quarter relates to a reduction of rigs operating under legacy term contract and an increased number of rigs operating at current market rates.

This margin guidance excludes reactivation costs associated with putting non-operating rigs back to work, as well as costs associated with rehiring, training, and staging crews. Today we know of two rigs we expect to return to operations at the end of the fourth quarter and there is one rig still on stand by and one idle 200 series rig for which we are in discussions regarding reactivation.

For the fourth quarter we expect reactivation costs to be similar on a per rig basis to what we experienced in the third quarter. With the aggregate amount based upon the level of reactivation activity in the quarter. We estimate rig construction costs that we'll expense in the fourth quarter to be approximately $300,000 and this is not included in the margin per day guidance.

We expect SG&A for the fourth quarter approximate $3.1 million, of which approximately $950,000 will be noncash stock based compensation. Depreciation expense should approximate $6.2 million and interest expense should approximate $500,000.

Similar to the third quarter we expect to recognize noncash disposal charges in connection with decommissioned equipment related to 7500 PSI upgrades on the two idle rigs that we'll mobilize at the end of the fourth quarter. We also expect to recognize the noncash charge Byron discussed relating to the sale or exchange of drilling equipment. Tax expense should be flat with the third quarter. On the capital sign Byron discussed the increase in our capital budget for the fourth quarter.

The $7 million cash outlays, estimated for the fourth quarter, include $3 million of cash payments for rig upgrades that occurred during the third quarter, as well as additional 7500 PSI and related upgrades occurring during the fourth quarter and of course maintenance and inventory purchases.

As rigs go back to work we also will be investigating in working capital, which we estimate to be approximately $600,000 per activated rig. Thus we do expect to incur some incremental barrings under our revolving credit facility as we upgrade and put rigs back to work. However we do not see any capital restraints under our current credit facility that would limit our ability in anyway to respond to this increased demand and activity.

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

Well, thanks, Philip. Operator, at this point let's open the lines for Q&A.

Absolutely, thank you, sir. We will now begin the question-and-answer session. (Operator Instructions). Today's first question comes from Rob MacKenzie of Iberia Capital. Please go ahead.

Good morning, guys.

Hey, Rob.

Rob.

Question for you, I guess, Byron, can you give us a handle, obviously you said the day rates remain weak in the mid to upper teens, where does that stand or what can you tell me, in terms of the two new contracts in the Haynesville and I presume those rigs are getting an upgrade before they go up to 7500 PSI mud systems and what impact if any would that have had on the rate?

Sure, Rob, the 7500 PSI fluid systems are pretty much a requirement for the work that we're doing. The people we're working with are drilling long to super laterals and so that's a cost of doing business for the type of work we're doing. The day rate for that equipment is in the upper teens.

So that would mean upper teens would mean over 17 a day?

It just means upper teens, Rob. I don't want to get into details. You never know who is on these calls.

Got it. Okay. And, again, these are obviously here the first one-year contracts we have seen signed in the latest up cycle.

Can you comment for us on the prospects for locking up more of your rigs on term and what your appetite is and how you would like to see that staggered throughout your fleet?

Sure. The -- I think we've talked about this a little bit on the two or three previous conference calls. The way as this market improves, stabilizes and improves the first thing you will see is contract extensions, you know, one year term contracts. And the driver for that is the client base seeing the equipment demand -- this type of equipment demand increasing and they want to make sure that, based on their drilling programs, they have locked in the type of equipment they need.

So that is the stage we are at now. We favor term contracts and particularly based on our view that you are not going to get any type of day rate improvement in the near term, we would -- to the extent we can and it fits us and the parameters are right we would favor term.

Okay, great. Next question would be along the lines of incremental CapEx. Right, you are now starting to see this term take hold. I think that has been one of your hurdles that you wanted to see before you committed to upgrading rig 101. where does your thought process stand on that rig at this point? And then, second, what is your updated thinking, if any, on building out the next 200 series rigs where you've already, kind of, spent half the money, if you will.

When one-year term becomes industry standard we'll look at that. And we're at a nascent stage of that right now, so we're not in the mode, we're not in a new build mode and we will see how the next couple quarters will flesh out in terms of term becoming pretty standard with pad-optimal equipment.

Okay. Thanks. I will turn it back for now.

And our next question comes from James West of Evercore ISI. Please go ahead.

Good morning, guys. This is Alex on for James. How are you?

Hi, Alex.

Alex.

So you have one competitor building new build rigs. Could you speak as to what you think that means for the rest of their legacy fleet and whether it is able to compete in the new market that's quickly becoming standard?

I don't know who that is, Alex, so I really can't comment.

Okay. Fair enough. And then second question, as the market kind of looks to go to one-year terms, do you guys feel you're giving up some potential day rate traction by being the first ones to sign one-year terms?

We don't know. I think that we see substantial aggressive bidding in the market including the market for walking 1500 horsepower equipment. So what we are seeing is that equipment coming into short supply, but juxtaposed against that when you see public and private competitors bidding very, very aggressively it makes sense to term out.

Understood. Thank you.

And our next question today comes from Tom Curran from FBR Capital. Pleas go ahead.

Good morning, guys.

Hi, Tom.

Are you already having discussions yet at least around the conversion of rig 101? And in those conversations how far apart are you on day rate?

We're having no discussions in that regard right now, Tom and until, again, we get to an industry wide one-type term we are too far apart with regard to our rate of return requirements and current market conditions.

And then turning to the Haynesville, you know, you are quickly ramping from no presence to what will be a four-rig presence as Haynesville's current rig count that would make you one if not the biggest land driller there. Do you foresee the need for any incremental infrastructure support costs there, Byron or Philip?

A couple of thoughts. We have substantial inquiry -- I'm sure the industry -- it is not just us. There is substantial inquiry coming out of the Haynesville, and it is interestingly large with regard to the Permian. So gas prices, you know, if you have a hedgeable gas price environment of $3.00 or higher I would expect to see activity in the Haynesville ramp for the industry.

It takes more than one basin to drive market improvement and this could very well be a second major basin for us. So we are cautiously optimistic about activity levels and rig utilization drilling for gas in the Haynesville. And with regard to additional infrastructure, the answer is no.

Okay. That was some helpful, interesting color. Thanks, Byron.

(Operator Instructions). Our next question comes from Daniel Burke of Johnson Rice. Please go ahead.

Good morning, guys.

Hi, Daniel.

This just a recap then, second half of the year CapEx spendings going up $10 million versus plans earlier in the year, I mean, how many 7500 PSI upgrades are captured in that figure? Is that basically working its way through the whole fleet or are there still -- or are there some other upgrades in there?

We have three rigs at the end of the year that will not have been upgraded to 7500 PSI so there is five -- and for this year we would have done five, 7500 PSI upgrades and several third mud pump upgrades and then we completed the rig 217 conversion -- the 103 conversion to rig 217. Material components of the second half CapEx.

But I think it is fair to say that as we get -- if we get any downtime between rig commitments we'll make those upgrades.

That's helpful. And then, Byron, you've expressed caution over the -- I guess the time line over which we would see improvement in the day rate and high spec rig class. What needs to happen to get to that point? I mean, as you eluded to earlier we are starting to see the ability or term creep back into the market, very nascent. How many rigs do we need to see go back to work? What happens next here?

The rule of thumb is you get to 80% utilization and that provides underling support for day rate improvement. Having said that the first thing you do see a contract extension, which we're seeing, and then the day rate improvement follows on the heels of that.

So that's where we are right now. But in -- the other thing to put into that mix is there are public and private competitors that, for whatever reason, are bidding substantially below the mid to high teens range and there are head winds there that are caused by that type of bidding.

That's helpful and succinct. And then, maybe, last one, maybe back to Philip, can you remind me what is the next couple term rolls, legacy term rolls to look for?

Yes, we've had no changes to any of our term contracts since our last conference call so I will just update. We have one that the next one expires at the end of the first quarter. We have expire in the middle of the second quarter of next year and one at the end of the third quarter and then one that it goes through the middle of 2018.

Okay, guys. Thanks very much.

Our next question is a follow-up from Tom Curran of FBR Capital. Please go ahead.

Thanks for letting me back in, guys. I was curious when it comes to the rig components that you are standardizing for, what are those and how competitive were the vendors as you went out to them and evaluated which models to go with?

Right. So as we go to super lateral-type drilling and completions, you really need to go to 500 ton top drives. And we've got some 350 ton that we used on the 100 series and the early 200 series and that's probably about half of what we're rationalizing right now. And it is -- so that's the driver and then there's some iron rough necks that aren't in spec with what we are doing, there's some catwalks that aren't in spec with what we are doing and it just relates to longer and longer and longer laterals.

And from a supplier standpoint there is a very large amount of suitable equipment at substantially discounted rates and pricing from what you saw as list in the last up cycle. So there is no shortage of equipment. Pricing is -- on that side is very aggressive as well. And there is no -- we may be able to do a one for one swap.

I don't know how it's going to work out, but as we raise cash we are deploying it to go to the type of specs, of equipment specs that are going to be supportive of super laterals.

And That's all consistent with what I would have expected, Byron. As a result are you, yourselves, trying to take advantage of the position your suppliers are in with perhaps longer term agreements or bulk purchase contracts? Anything like that where you can maybe lock in as you standardize?

No, we are not pursuing that. We don't want to get ahead of our skis so we are being quite disciplined in our capital deployment. We have taken a lot of costs out of our SG&A and operating run rates. And so until we get better clarity we will be very capital disciplined and won't do anything like that.

Okay. Thank you.

And our next question comes from Matt Johnston of Nomura. Please go ahead.

Hi, good morning, guys.

Hi, Matt.

Morning.

Congrats on the two new contracts in the Haynesville. Just wondering, as we think of the Permian and the Haynesville, outside of those two basins wondering if you can give us your thoughts on how the rest of the lower 48 might evolve over the next year and from a geographic perspective where might be the best opportunity to win some new work?

Sure. Of course our target market is Texas in the continuous states so our client conversations and our marketing and business development efforts are really focused there. When you step back and look at that you have the Permian, Stack Scoop, Eagle Ford and the various gas plays including the Haynesville.

Where we are seeing a lot of traction right now is the Permian, in a big way, and Haynesville in a growing way. We get inquiries from other areas, but it is not in the volume of the two basins right now. So, I think, it has a lot to do with the underling basin economics and those two they are in the sweet spot.

I expect to see the bulk of it, right now, come from those basins and certainly we have the ability to work anywhere in the five-state area and we would respond quickly to inquiry or rig requirements from those basins as well.

Got it. Okay. That's very helpful. And just a follow-up in connection with that, how does day rate, kind of, factor into the decision making process if you were to go outside of the Permian and the Haynesville, staying within that five-state area. Would you need a higher rate or are you close enough to your core logistics network where you are incentivized to go out at what current rates?

Current rates in the mid to high teens are where we play. We are not going to participate in knockdown day rate work. And from a logistics and a cost standpoint anywhere in that five state area has pretty much the same cost structure for us, a little bit higher in New Mexico. Some of the states have different permitting and operating requirements, but they are not really germane in terms of driving a requirement for a higher day rate.

Great. Thanks for that.

And our next question is a follow-up from Alex George from Evercore ISI.

Hi, guys, sorry one more and slightly, I guess, more academic, but as the days require to drill a well decreases, land rigs are capturing a smaller percentage of the DNC CapEx pie, do you see a need for the business model to shift away from a revenue per day model in order to, I guess, incentivize further technology adoption and, I guess, continue to invest in higher quart land rigs?

We talk about that and, I think, there's -- we are looking out over a five, ten-year time frame and it's pretty difficult to do that. But you can make a case for that, but that would have to be something that was driven and adopted by the ENP community. So, right now we don't see any -- in the next several years we see nothing that's going to take us from a traditional day rate environment.

Could that potentially stymie new builds, not necessarily by you guys given where you play, but by the (inaudible) land rig community and essentially drive higher utilization as a result?

Well, I think, what you'll see is over the course of this cycle, you will see pad-optimal equipment go to full effective utilization. You will see the increased use of longer term contracts.

You will see day rate improvement and then, you remember the main driver for what we do is pads and as pads become broadly accepted by the entire ENP community as the most effective way to -- the most effective from both an engineering and a cost standpoint from addressing their drilling programs, that's going to create unfilled demand for pad optimal rigs and if you're going to go the trouble of building a big pad there is no particular reason to use anything other than a walking rig. And so you will get into a new build cycle that'll top that off. But, again, I think that's probably a 2018 discussion.

Understood and well done on essentially full utilization at year-end.

Thanks.

Ladies and gentlemen, this concludes the question-and-answer session. I would like to turn the call back over to management for any closing remarks.

As always we thank you for your participation on the call for the questions, from your support as shareholders. And we always want to thank the employees of ICD for their exemplary safety record and exemplary up time record and all of the things that make us a preferred provider to the ENP community. We look forward to talking to you all next quarter.

And thank you, sir. This concludes today's conference call. We thank you all for attending today's presentation. You may now disconnect your lines and have a wonderful day.