Independence Contract Drilling Inc (ICD) 2018 Q4 法說會逐字稿

Good morning, and welcome to the Independence Contract Drilling Fourth Quarter and Year-end 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, sir.

Good morning, everyone, and thank you for joining us today to discuss ICDs fourth quarter and year-end 2018 results. With me today is Anthony Gallegos, our President and Chief Executive Officer. Before we begin, I would like to remind all participants that our comments today will include forward-looking statements, which are subject to certain risks and uncertainties. A number of factors and uncertainties could cause actual results in future periods to differ materially from what we talk about today. For a complete discussion of these risks, we encourage you to read the company's earnings release and our documents on file with the SEC. In addition, we refer to non-GAAP measures during the call. Please refer to the earnings release and our public filings for a full reconciliation of adjusted net loss, adjusted net income, EBITDA and adjusted EBITDA and for definitions of our non-GAAP measures. And with that, I'll turn it over to Anthony for opening remarks.

Thanks, Phil. Good morning, everyone. Our fourth quarter results are the first for us to report as a combined company, reflecting our recent strategic combination that closed on October 1, which more than doubled our rig fleet.

The combination helped drive ICD to report quarterly adjusted net income for the first time as a public company and set the stage for a meaningful free cash flow generation in 2019 and beyond. Phil will provide the detail in his prepared remarks, however, I'd like to say that I'm proud of these results, in particular, the combined company's intense focus on safe operations on our continued integration and on cost control and synergy realization, which drove better-than-expected financial performance in our cost lines during the quarter.

During the fourth quarter, we reactivated our 32nd operating rig, which mobilized and spud its first well under a 1-year contract in the Haynesville, resulting in us existing 2018 with 32 rigs operating, which is 100% of our marketed fleet. During the quarter, we also renewed or entered into new contracts for 5 rigs, including strategically transitioning rigs between customers in a few instances. Overall, our operating days fell right in line with our guidance. We also continued the hard work of integration during the period. I'm happy to report we're on schedule with all integration activities and I'm confident regarding our ability to achieve our target for synergies of $10 million or more by the third quarter of 2019.

Meshing 2 similarly sized companies and 900 combined employees is no easy task. However, the ICD team has responded magnificently. Our team has achieved much over the past several months, but we have not lost focus on the day-to-day, which is seen in our better-than-expected cost per day metrics and more importantly, our continuous focus on providing the safest and most reliable daywork drilling operations in the industry as evidenced by our year-end safety record for the combined company, which is more than 20% lower than the U.S. land category as tracked and presented by the IDC. I'm proud of how everyone has come together working hard as one team throughout the integration. In the process of our integration, we have sown seeds in terms of our culture and the ICD way, which will continue to pay dividends for years come.

Now moving on to the market and what it means for ICD in 2019. I'm sure everyone on this call is aware of what happened to oil prices during November last year. The downdraft in WTI during November was unprecedented in my career where we saw WTI close down 12 consecutive days. As we were turning the page on 2018, the forecast at that time by most analysts were very negative for 2019 rig activity. However, as has been discussed on various other conference calls, year-to-date demand for pat optimal drilling rigs, those, which ICD owns and operates has been more resilient than most analysts' original 2019 forecast. There is no doubt, there've been some tweaks on the margin as evidenced by some customers that released some rigs. However, there has also been some high grading as well, which offset some of those releases. I've spoken with certain of our customers and heard others speak about their commitment to capital discipline to live within cash flow. If the street thinks oil prices will be lower, then cash flow will be expected to be less, thereby requiring E&P Operators to recalibrate their expected drilling and completion spending. That is the message they have delivered. However, I'm not sure that lower oil price is really what the E&P Operators are expecting. Even during November and December, we were not hearing from our customers that they were planning mass releases of rigs. What we were hearing really was uncertainty. This uncertainty manifested itself in later CapEx budget announcements than we typically see. Rather than reducing their contracted rig count, several operators have rolled their current levels of contracted rig count by extending contracts on shorter durations, thereby giving them the opportunity to hold on to their rigs and their hard-earned efficiencies if prices remain stable at current levels and eventually rise.

I do think there's been some high grading, releasing some lower specification rigs and picking up pad-optimal rigs, but in spite of this, ICD was able to recontract our 3 operating SCR rigs over the past couple of months at incrementally higher dayrate than their expiring contracts. So what we're seeing once again is the continued manifestation of the ongoing rig replacement cycle, the pad-optimal fleet does not necessarily respond the way U.S. land rig count may have responded pre-2015 and it continues to enjoy very high levels of utilization.

What does all of this mean for ICD and how we are planning our operations for 2019? Overall, my outlook for this year remains very positive. Undisputedly, ICD's contracted rig count and operating free cash flow and EBITDA will be higher than ever before as a consequence of the larger fleet, which we operate today, both on an absolute and per share basis. While we may not be signing as many 1- or 2-year contracts in the first half of this year as we thought 3 months ago, I do expect demand for our pad-optimal rigs to remain high. We could see a little more down transitory downtime between contracts than normal principally in the first and second quarters, but this will not be unique to ICD. But as oil prices continue to stabilize, and improve over the course of this year, our customers will adjust their drilling plans accordingly and the transitory issues will resolve themselves. Against this backdrop, our Board of Directors has approved a net $29 million capital budget for 2019. This includes $9 million related to the delivery of long-lead time items for our planned SCR to AC conversions and $5 million reserved for additional equipment packages including third pumps, fourth engines, setback and hook load upgrades, much of which will depend upon market conditions, customer demand, contract tender and pricing that meets or exceeds our internal return hurdles.

As I close my prepared remarks, I want to make a few final observations about the rig market and were I see ICD. It feels like we are seeing the new norm in the post 2016 North American land rig market. Oil prices appear to be banded generally in the $50 to $70 range, shorter, less severe cycles, continued manifestation of the rig replacement cycle as customers continually high grade to a manufacturing model focused on full development characterized by increased pad size and lateral length and an intense focus on returns and free cash flow.

If that is the world we will live in, then I'm confident that ICD is exceptionally well positioned vis-à-vis our operations, our pad-optimal rig fleet and our strong balance sheet to respond to market dynamics, meanwhile generating meaningful free cash flow at whatever point in the cycle we find ourselves. Except for doing everything possible to keep our team members safe, that is our #1 focus here at ICD.

With that, I'll turn the call over to Philip who will provide more detail on our financial results.

Thanks, Anthony. As Anthony mentioned, our fourth quarter results and balance sheet fully reflects Sidewinder operations, which significantly benefited the company results during the quarter. There are a couple of discrete items affecting our reported results. We recorded noncash revenues of $2 million associated with the amortization of intangibles in accordance with purchase price accounting for the Sidewinder merger. We exclude these benefits when calculating our adjusted net income, adjusted EBITDA and revenue per day statistics. We incurred $11.3 million of merger-related expenses that we excluded in calculating adjusted net income and adjusted EBITDA. And we incurred noncash write-offs of deferred financing costs of approximately $900,000 associated with the termination of our prior credit facility in connection with the Sidewinder merger. This increased reported net interest expense during the quarter and has been excluded in calculating adjusted net income.

Now moving on to our results of operations for the quarter. We reported just -- adjusted net income of $0.01 per share and adjusted EBITDA of $16 million, both ahead of our guidance. Revenue per day of $20,433 and rig utilization came in consistent with our guidance with a small amount of idle time associated with transitioning a rig between customers. We also reactivated a rig acquired in the Sidewinder combination that began operations in late December and we exited 2018 with all 32 of our marketed rigs operating.

Cost per day of $12,932 came in below our guidance, benefiting from increased economies of scale and acceleration of certain operating synergies. SG&A also came in better than guidance, also associated with the acceleration of certain synergies. Depreciation expense reflects the result of our purchase price allocation with final depreciation expense coming in lower than guidance and benefiting our reported adjusted net income during the quarter. Moving on to our balance sheet. We ended 2018 in a very strong position. We had net debt excluding capitalized leases of a $117.1 million and a net debt-to-EBITDA ratio based upon our four quarter -- fourth quarter results of less than 2x. And we had total liquidity comprised of cash on hand and availability under our revolver in term-loan accordion of $54 million. Our backlog at December 31 stood at $121 million, representing 15.6 rig years of work.

Moving on to guidance for 2019. As Anthony mentioned, our capital budget net of disposals for 2019 is $29 million and this includes $9 million relating to the purchase of long lead-time items on our planned SCR conversions and $5 million reserve for other equipment package investments.

The timing of these completions will be based upon customer demand and received by us of an acceptable return on our investment and, of course, market conditions and contract tenders. We have been successful during the past couple of months extending contracts in all 3 operating SCR rigs at attractive day rates, and the first rig does not come off contract until later in the year, mid-year. With respect to our planned reactivation of our final lateral rig and its conversion to pad-optimal AC status, we can begin completing this conversion as soon as midyear with actual timing based upon market conditions.

We are budgeting cash SG&A for the full year to be approximately $14.9 million with noncash stock-based compensation expense on top of that of approximately $2.7 million. For the back half of the year after we believe we have full realization of synergies from the Sidewinder combination, our quarterly run rate should be approximately $3.6 million per quarter of cash SG&A plus $900,000 per quarter of noncash stock-based compensation expense on top of that. Full year depreciation expense is budgeted to be approximately $47 million.

Now moving on to the first quarter guidance, we expect to see the following: 2,730 operating days representing 95% utilization of our 32 rig marketed fleet. Revenue per day between $20,500 and $20,700 per day, higher than the fourth quarter, associated with higher contract pricing as contracts roll, but offset by 1 rig on standby for approximately 1 month during the quarter. Even with recent oil price declines, current dayrates are still substantially higher than dayrates on contracts signed in the first half of last year that were rolled later in the first quarter and during the second quarter of this year. Cost per day during the first quarter is expected to range between $13,300 and $13,600 per day, sequentially higher than the fourth quarter. The increase does not represent a true cost increase, but rather relates to seasonal payroll tax items and a shorter calendar quarter and thus fewer operating days to spread fixed operating costs over. Cash SG&A expense is expected to be approximately $4.4 million during the quarter with seasonal increases associated with year-end audit and related matters being more than offset by continued realization of operating synergies from the Sidewinder combination. Noncash stock-based compensation expense for the quarter will be approximately $400,000 and will be on top of the $4.4 million of cash expense. Depreciation expense is expected to be $11,000 -- excuse me $11,000,500 during the quarter, which is slightly up from the fourth quarter, reflecting the addition of the idle rig reactivated at the end of the fourth quarter to the operating fleet. And interest expense is expected to be approximately $3.9 million of which $200,000 will be noncash.

And finally, as Anthony mentioned in his prepared remarks, we expect to generate meaningful free cash flow during 2019, even after considering growth CapEx and working capital investments we make. In that regard, I want to mention that this free cash flow generation will be skewed towards the back half of the year as there is approximately $8 million of accrued transaction expenses that will represent cash outlays during the first half of the year as well as seasonal matters associated with the payment of year-end Ad Valorem taxes and incentive compensation expense during the first quarter.

And in addition, payments on the SCI conversion long-lead items are skewed more towards the first half of the year. And with that, I will turn the call back over to Anthony.

Thanks, Phil. I have no further comments at this time. Operator, let's go ahead and open it up for questions.

(Operator Instructions) And today's first question comes from Kurt Hallead of RBC.

Congratulation guys to very solid integration so far and a good start to 2019. So Anthony, maybe I can start the dynamic by saying, we've seen a number of different EB companies provide their drilling budget and program expectations for 2019. I noticed that one of your largest customers indicated that they would cut their rig count by something like 10 rigs or so. What -- you mentioned in your prepared commentary that you really haven't picked up on that dynamic -- or seems like you haven't picked up on a dynamic where your customers are necessarily looking to cut back on a significant basis. So I'm just trying to do some calibration here and really kind of get the read from your standpoint, the read from the field?

Yes. No problem. Kurt, thank you for your compliments there. It was a great quarter and really proud to have the opportunity today to talk through that. It's a great question you've asked. When I sit back and look at the overall rig count, that's really what I'm referring to when I say on the whole. We certainly haven't seen anywhere near the declines that people were projecting and expecting as we rolled into this year. Certainly, you can take a particular customer who may have particular drivers, and look at them in isolation and what they do with their contracted rig count, may be different than what the overall market is doing. What I would point out about Concho, that obviously is a key customer for ICD, someone that we had several rigs with. We enjoy a great relationship with them. Like other operators out there, they've taken a very conservative approach toward outlining their CapEx plans for 2019. I would say that the decision to release rigs, that was up-in-the-air for several weeks, if not months. Ultimately, they did decide to release them, but the point I want to make is that wasn't something they took lightly. They understand that they're probably going to need more rigs down the road and the last thing they want to do is release the rig or rigs that have been under contract for quite some time where they are enjoying the efficiencies from that long-term relationship, only to find themselves 6 months later having to pick rigs back up. So look, we still have several rigs with that operator. Certainly, expect to continue working for them. Certainly, expect to be part of what they do going forward when they pick rigs back up, but that's how I would respond to that, Kurt.

Okay, great. And secondarily, as you go kind of through, as you mentioned, going through this kind of transitory period of some choppiness on activity in your confidence level that you're going to be able to keep your rigs mostly active, what's the dynamic in play with respect to pricing and are you able to kind of hold firm on your price dynamic or are you finding you're -- you have to give up a little bit on pricing to kind of keep these assets fairly active?

Yes. So I guess, what's different for us sitting here today compared to 3 months ago, is 3 months ago, we were expecting to roll contracts at the $23,000 to $24,000 a day range. Given what's happened in the market over the last few months, we're not going to roll at that. It's certainly not a disaster. Dayrates will be a little less than what we were expecting 3 months ago. But what's interesting, Kurt, is given that a lot of these contracts were negotiated a year ago, we're still going to see increases as we roll contracts from where they were, which were negotiated 12 months ago, to where they are going to be now.

Next question today comes from Ryan Pfingst of B. Riley FBR.

Philip, just a follow up on pricing. You mentioned that the rigs extended in the fourth quarter are going to be contracted at higher dayrates than their previous contracts. And Anthony, just saying that though dayrates are not where you expected them to be a few months ago, do you still expect dayrates for the super set-back class to remain in a steady uptrend throughout 2019.

Well, certainly the contracts we've signed today have all been at higher dayrates than what the expiring contracts were. I think as Anthony said, I think dayrate momentum has paused a little bit. But -- as we go through this transitory period -- but by mid-year or so, we think a lot of that's going to be gone and so I think we're back in a position where we can achieve some momentum.

Ryan, I would add also that you've got to look at rigs, their capabilities, how they're outfitted, things like that. So when we talk about dayrates for rigs, maybe not being exactly what we thought -- we thought -- where we thought they would be 3 months ago. When you look at that sub-sector of the market, that's at the highest end, 3 pump, 4-gen and extended walking capability, stuff like that, I do think you're going to continue to see nice dayrate improvement on that subset of the pad-optimal fleet. So obviously, ICD today participates in that market as well. We're looking at some really interesting opportunities involving that class of rig, but with the 32-rig fleet, obviously, they don't all have that capability. So that's why we're saying the average may not be what we thought it would be, but that's not to say we're not going to have some really nice data points to talk about as this year plays out.

Got you. And then can you guys just give your thoughts on further M&A as we're now 5 months past the close of the acquisition?

Yes. Great question. So as I said on the third quarter call, the most important thing for ICD was to get the sideline of integration right. And with a lot of work that was put into that over the summer planning it, I'm happy to say since the merger launch, the integration has gone extremely well, not only from a cost synergy standpoint, but in my mind, more importantly from a cultural standpoint. We are one company today. We fly one flag. We -- I've been involved in 4, 5 integration efforts in my career, certainly never had to lead one as a CEO, but from my perspective, this has gone extremely well. The point I'm trying to make is over the last 3, 4 months, that's what we've been focused on. As the integration has moved along, we have started to pick up the pen, started to look around. We've been careful to make clear that this isn't a roll-up of just land rigs, but where there are opportunities to acquire additional rigs, additional companies where the asset quality, asset -- the fleet of rigs has industrial fit with ICD that being pad optimal, where we can purchase rigs in a way that it's accretive, those are opportunities we're going to look at. The challenge we have is, that there's a limited pool of opportunities out there, most of those opportunities are not straightforward. There's hair on all of them. So as you work down the list and you kind of tick off the ones that you think are actionable, you reach out and you try to do what you can. But it takes 2. And another challenge also is most of these companies when you talk to them, you're not just dealing with one guy or girl. So it's complicated. Look, the key that I -- the point that I would make is ICD given our scale, obviously, more scale would be better, but having combined with Sidewinder back in October, we don't have quite the pressure we had pre-merger to need immediate growth. So we're really in a great position here with a company that's really running well. I believe we're going to have nice wind in our sails in the back part of this year and I think we can sit down and make the really good and the right decisions for our shareholders as it relates to growth going forward.

And our next question today comes from Taylor Zurcher of Tudor, Pickering, and Holt.

Anthony, even for a fleet of your size, you've got pretty broad exposure to a wide array of different E&P Operators from majors to large independents to private. So my question is just given the private side is a pretty meaningful piece of the business for you at least today, to the extent you're seeing any differences in customer demand or contracting behavior between those 3 groups, again particularly on the private side, I was hoping you could shed some light on what you're seeing to the extent there are differences between those 3 groups?

Yes, Taylor. I would -- there's -- I think a big difference -- and that's the pressure that our public customers are feeling primarily from Wall Street, the investment banking community and certainly from shareholders -- and that's on returns. The privates that we're working for -- and there are some big privates in that mix, as you probably know -- tend to be a little less reactive to what happened late last year. And certainly, as they think about this year, how they're going to adjust budgets if they're going to adjust it all. So I'm happy to say that, that group of privates that we're working for have reacted very favorably in the midst of a lot of uncertainty in the market over the last couple of months. The SCRs that we have are working for privates, 3 of the 4. The 3 that have been working now for a year continue to work. We've got a couple that are rolling over in the second quarter. We're already in negotiations on extensions there. So I think that's held up quite well. Hopefully, I'm answering your question. The other point I would make -- and we don't talk about it as much as what's going over -- on in the Haynesville. We've got 8 rigs over there working right now. It's a really good niche market for ICD. We've seen -- gas prices ran up last year. They kind of backed off since then but certainly, as we think about the contract roll-overs that we have in that basin coming up here over the next couple of quarters, we're pretty optimistic about what we're going to be able to do there and possibly even add some incremental rigs into the market.

Okay, very helpful. And you answered my follow-up on the Haynesville. So one last question for me is just given all this market churn over the past several months and you've covered most of it in your script, but as of rig transition between customers or perhaps go idle for periods of time, are you seeing additional opportunities or incremental opportunities, I guess is the right way to say it to put rigs to work in basins in plays outside of the Haynesville Permian? And is that something that you might be interested in doing moving forward?

Yes. So an obvious target there would be the Eagle Ford. The Eagle Ford in our view is just an extension of the Permian. The Eagle Ford is a market where both legacy companies has -- have had presence over the last few years. So I wouldn't be surprised to see ICD end up with some rigs in Eagle Ford market. And remember, when we talk about our target market, is Texas and the contiguous states. Of course, we have one rig working in New Mexico now and I expect it's going to remain over there, but Oklahoma would be somewhere that we could easily move in and out of very efficiently. And of course, we've got a nice presence over in North Louisiana as well. So -- but we want to keep the target market narrow. We want to keep it in the South and that being in Texas and the contiguous states, but within that broader market, I wouldn't be surprised to see us move some rigs around just based on opportunities that are presented to us.

And ladies and gentlemen, this concludes our question-and-answer session. I'd like to turn the conference back over to the management team for any final remarks.

Thank you so much. Look, as we bring the call to a close, I'd like to confirm that ICD is in a great place. We're cash flowing at a level not previously achieved. We're executing on our integration plan successfully and we're on track to achieve more synergies than we originally projected. In terms of our customers, we can provide them with more rigs than ever before and have a wider array of drilling rig options to make available in addition to an enhanced ability to enter into larger, strategic relationships with our premium customer base. As an investor, we have better financial security, vis-à-vis our stronger balance sheet and low-risk line of sight to substantial growth and free cash flow generation over the next couple of years. Guys, as you've heard me say before, nothing has changed, but everything is different here at ICD. We appreciate everyone dialing in and spending a few minutes with us today. We look forward to seeing you all on the road at upcoming Investor Relations conferences and updating you on our results and progress during the second quarter when we discuss our first quarter results. We wish everyone a safe and productive Friday, and a very nice weekend. With that, we'll sign off.

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.