Independence Contract Drilling Inc (ICD) 2017 Q3 法說會逐字稿

Good day, and welcome to the Independence Contact Drilling Incorporated Third Quarter 2017 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 of Independence Contact Drilling Incorporated. Please go ahead.

Good morning, everyone, and thank you for joining us today to discuss ICD's third quarter 2017 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 a full reconciliation of net loss to adjusted net loss, EBITDA and adjusted EBITDA and for our definitions of our non-GAAP measures.

And with that, I'll turn it over to Byron for opening remarks.

Thank you, Phil. Good morning, everyone, and thank you for joining us today. This morning, I will review ICD's third quarter 2017 operations and update our outlook for the remainder of the year. Phil will provide details on our third quarter financials, and then we will take questions from call participants.

In the third quarter, ICD generated record operating and revenue days. We completed our final ShaleDriller conversion, and our fleet reached 100% utilization with every available rig contracted. We signed early renewal of 4 term contracts with term extensions between 6 and 12 months and with day rate increases in excess of $2,000 per day. We began our first contract with an international major operating in the Delaware Basin. In today's environment, delivering high-producing, cost-effective wellbores is absolutely critical. Working with our customers, we continue to help them exceed their own operational and economic expectations while collectively leading the industry in creating value for clients. For example, last quarter, we drilled the second longest well in the Austin Chalk. We set new field records for both lateral length and drilling rate in the Delaware Basin, which is undoubtedly the most challenging in the Permian. And we implemented technologies that will reduce our environmental footprint and lower fuel consumption, including the use of high-line power, which will materially decrease operating costs for those rigs.

As we predicted on our last conference call, the overall rig count has begun to fall. However, with ICD's pad optimal fleet at full utilization, we continue to see robust demand for our pad-optimal ShaleDrillers and currently have the highest volume of forward rig availability inquiry that we have enjoyed in years.

Substantial demand for pad optimal equipment combined with little availability drove the early renewal of the 4 existing contracts I previously highlighted, which added 3 full rig years of backlog. Although day rate momentum has slowed recently, base day rates for pad optimal rigs have reached a new level in the high-teen to low $20,000 per day range.

With regard to the 4 contract extensions I mentioned, let me note we will see some day rate benefit from these new contracts in the fourth quarter, with the most of the incremental revenue per day manifesting itself in the first quarter of 2018 and beyond.

Although we set new operating records during the quarter, revenue days came in on the low side of our guidance due to Hurricane Harvey dislocations. Operating costs per day were higher than in the second quarter due to Harvey and weather-related issues as well as safety field incentive bonuses, hiring and training entry-level employees and unscheduled repair and maintenance during the quarter. On a forward run-rate basis, as our rigs operated full effective utilization and as entry-level recruiting and staffing stabilizes, fully burdened OpEx at the rig level should be in the $12,500 to $13,000 range with rig level cash cost settling in the $10,700 to $11,000 per day range. As we discussed on last quarter's conference call, we expected a decline in gross rig count during the back half of 2017, and that decline continues to occur. We expect the gross rig count to continue a shallow decline into 2018 as technologically and economically obsolete rigs drop at the margin.

We believe that E&P operators have promise growth and profitability at commodity price thresholds that can only be provided through complex pad drilling programs utilizing the fastest and most efficient pad-optimal rigs such as ICD ShaleDrillers.

Large E&P players are shifting to development drilling using larger pads, batch billing and much more efficient pad-optimal drilling equipment. As these operators continue the process of high grading their rig fleets in 2018, dropping sub optimal rigs that are technologically obsolete, in that environment, pad-optimal equipment will be well-positioned to realize day rate and margin expansion based on the high economic value add these pad optimal rigs provide. With our fleet fully committed, ICD remains well positioned to capture improving day rates in 2018. We have strategically implemented a staggered term contract exploration matrix throughout 2018, supporting a process that allows ICD to capture day rate improvement as contracts roll and re-rate. At third quarter end, backlog stood at $75 million with all revenue days contracted through the first quarter of 2018 and 84% in the second quarter of 2018. ICD's balance sheet is in great shape. Until we elect to complete our next 2 new build rigs, our capital spend will be associated only with maintenance capital expenditures in a few discrete purchases to build out our inventory of critical spares. As a result, we plan to begin steadily paying down debt until such time as we elect to restart our rig build program.

Our operations are easily supported by our ABL against a commitment of $85 million and a borrowing base of almost $108 million. At September 30, we had net debt of $44.3 million.

As I mentioned previously, we have already invested approximately half of the construction cost to build 2 new ShaleDrillers. I noted the strong demand for our rigs with active inquiries and discussions from mobilizations well into 2018. I am hopeful that improving market conditions will drive day rates and tenures which meet the financial benchmarks we require to complete those rigs and continue to grow our fleet.

Concluding, I am quite pleased with ICD's current position. Our rigs have reached full effective utilization and are contracted customers with long-term drilling programs requiring pad optimal equipment for their proper execution. Our recent term contracts have provided additional forward-looking visibility, and our ABL availability and borrowing base remains strong. This provides ICD with the liquidity to strategically complete the 2 half build 200 series rigs as market conditions improve. We continue to see sustained steady demand growth for pad-optimal class rigs by operators with industry-leading cost structures, the type of operator represented in ICD's client list. And with that, I'll turn the call over to Phil.

Thank you, Byron. In the third quarter, ICD reported a net loss of $6 million or $0.16 per share. Excluding noncash charges summarized in our press release, our adjusted net loss was $5.1 million or $0.13 per share. Based on 1,235 revenue days in the third quarter an 11% sequential increase from the second quarter, total revenue was $23.4 million, including pass-through revenues of $1.2 million. Average revenue per day of $18,034 came in line with our guidance. Approximately 5% of third quarter revenue days were in under our higher day rate legacy contract that expired during the quarter. This contract rerated to the current day rate environment during the quarter.

Hurricane Harvey impacts during the quarter included a slight reduction in revenue days compared to our original guidance as well as modest increases in operating cost per day. In addition, our corporate office building experienced water-related damage that is a subject of an insurance claim. Cost per day of $13,513 came in higher than our guidance. Some was due to Hurricane Harvey and related weather events, but we also experienced higher unscheduled repair and maintenance expenses as well as increased costs associated with new hire retention initiatives and increased performance-based safety compensation at the rig level.

Gross margin per operating day excluding reconstruction expenses was below our guidance as a result of the cost items discussed. SG&A expenses were $2.9 million, including $900,000 of noncash compensation expense. Cash SG&A expenses of $2 million declined 9% sequentially as a result of lower professional fees and incentive compensation expense.

Noncash compensation expense declined 25% sequentially due to the completed vesting of equity awards originally granted at the time of the company's initial public offering.

Depreciation expense, interest expense and tax expense all came in line with our prior guidance. At September 30, we had net debt excluding capitalized leases of $44.3 million. Our borrowing base under our credit facility was $107.5 million, exceeding the $85 million of commitments under the facility. Cash outlays for capital expenditures in the quarter net of disposals were $9.6 million of which $4.7 million related to deliveries occurring during the second quarter of 2017.

Moving forward, until we begin completion of our next 2 rigs, where we have already made significant investments, our capital program will be comprised only of maintenance CapEx as well as a few discrete capital items to complete our capital spare inventory. For the fourth quarter, we expect cash outlays for CapEx of approximately $1 million plus an additional $2.5 million that will flow through our cash flow statement relating to prior period purchases that are accrued as accounts payable at quarter end.

We have $5.7 million of assets held for sale that will offset capital expenditures as proceeds from sale are realized. At September 30, 2017, our contract backlog was approximately $75 million, representing 10.8 rig years of activity. Of this backlog, 32% is expected to be realized during 2017, 63% in 2018 and 5% in 2019.

Byron mentioned that we recently signed expansions on 4 term contracts that added 3 rig years of backlog and rerated to current market rates. These increased day rates begin when the multiwell pads that these rigs are currently drilling are completed. We expect 2 of these contracts to switch to new rates later this quarter with the other 2 switching at year-end or early Q1 2018. With that backdrop, our average day rate and backlog for the remainder of 2017 is approximately $18,500 per day and increases to approximately $19,100 per day in Q1 2018 and $19,600 per day for the remainder of 2018 as our remaining lower day rate contracts roll during the first half of 2018.

As a result, we expect to realize some sequential top line revenue per day improvement beginning in the fourth quarter with our fleet at 100% utilization and more meaningful sequential revenue per day and margin improvement beginning in Q1 and Q2 of 2018 when lower day rate contracts continue to re-rate higher.

Fourth quarter guidance. In the fourth quarter, we expect our rigs will generate between 1,278 and 1,288 revenue days with revenue per day increasing slightly and ranging between $18,000 to $18,400 per day as we begin to realize some benefits from our new contract extensions. We expect fully burdened operating cost per day to fall to a range of $12,800 and $13,000 as repair and maintenance expenses move back to normalized levels compared to cost experienced during the third quarter. These per day expectations exclude pass-through revenues and expenses, and our cost per day also exclude rig construction expenses.

We expect fully burdened margin per day to be up sequentially with a range between $5,000 and $5,500 per day.

Rig construction expenses are expected to be approximately $450,000 during the third quarter -- fourth quarter. SG&A should approximate $3.1 million, of which $600,000 will be noncash. Depreciation expense should approximate $6.7 million, interest expense should approximate $840,000 and tax expense should be flat with the third quarter. And with that, I will turn the call back over to Byron.

Well, thank you, Phil. I guess in closing, I'd like to, as always, express my regards and support for the fine work that ICD's employees do. They truly make the company. And with that, operator, let's open the line for questions.

(Operator Instructions) The first question will come from James West of Evercore ISI.

Byron, so you've got the 2 new builds that are half -- you've paid for about half of those. You talk about market conditions improving before you go forward with the finalization of those rigs. Can you remind us again -- I know it's been a conversation about rate plus term, but it seems like we're getting there on almost both of those. I mean, could we see you guys go forward with those new builds in the next quarter or 2?

I think so. I think the -- I think day rates are where they need to be and we, if we get a 2-year term relative to the ABL, we're good to go. And we've got 2-year terms in the past, in the last couple of quarters, so I don't think that's out of the -- I think that's part of the conversation right now. We just have to link that up with a delivery date and we'd like to get those out as fast as we can.

And what's the time line from when you sign a contract to when those rigs would be in the field?

From when we -- from when I approve the AFE, it's about 4 months for those.

Four months, okay, great. And then we talked previously about additional new builds on top of that, but those would be more -- you talked, there could be a possibility of a partnership with a like-minded, say, E&P. Are those conversations still ongoing?

They are. The type of rig we're talking about is substantially different than the 200 series. So we're talking about 1 million pound mast, 2,000-horsepower rigs, extended walking capabilities, vastly expanded mud handling capabilities. These are associated with mega pad drilling at the very lowest levels of the Wolfcamp, and that's probably a $28 million to $30 million proposition. So that type of rig is in demand. There's nothing like it available right now. There's a handful of heavy rigs that are out there doing some of that work, but they're suboptimal. So those conversations, the conversations we're having surround the demand for this equipment, it's on availability and around financial terms that would make sense for everybody involved to begin construction of the type of equipment.

The next question will come from Kurt Hallead with RBC.

Hey so, Byron, just maybe for a little clarification, you referenced that there are some opportunities to get 2-year term, and then you kind of referenced relative to ABL. Can you just clarify what that means, exactly?

Phil, why don't you take that? Because we're balancing the -- our ABL draw against our contract backlog in order to mitigate market risk. Phil, do you want to...

Yes, so when we think about our forward-looking cash flows and what our lenders want to see, obviously we have plenty of borrowing base. They'd want to see if we need to tweak any covenants or something like that. If we were to build both of those rigs today, then we'd have to go back and tweak our cash flow covenants for a quarter or 2. If those -- if they're associated with 2-year contracts, that's a very easy conversation for us to have with our lenders. It's really just us looking at forward-looking cash flows and getting them comfortable with our -- with any kind of incremental debt we've got to put on the company.

Okay, I appreciate that clarity. Now in the context of these 2-year deals, what kind of pricing would be associated with a 2-year contract?

The conversations we're having range from the high-teens to the low-20s. So it's, there's multiple conversations and there's multiple price points. There's also adders for oil-based mud. There's a lot of bits and pieces in there, but it's right in line with the guidance we've given. I think the market is there, and what we're doing is pushing tenure.

Our next question will be from Daniel Burke with Johnson Rice.

Hey, Byron, could you elaborate on what you guys are doing with regard to electrified power or using grid power, it sounded like? Maybe I misunderstood your earlier.

Yes, what we're doing is, we're setting up rigs so they can run on high-line power. And the issue there is high-line power is typically dirty. There's harmonics, so we have to rectify, take it back to AC. And when you do that, you don't run your gensets, so it's good for the operator, and it's good for us. And then on an operating cost basis, because we're not running the gensets.

Okay, and how many -- can you talk about the magnitude of that opportunity across the fleet?

Two right now. So early stages but 2, and we'll see where that takes us.

Okay, great. And then, I think just a couple on the CapEx side. First, can you maybe just update us on where you are in terms of that forward maintenance level CapEx, if we think about that as a base run rate in 2018 before attempting or thinking about the potential overlay of the recompletion product -- projects? And then the second one, practically looking at CapEx this year. Are you guys experiencing a little bit of creep? Or am I just getting a little crossed over with the accrued CapEx versus the current quarter CapEx figures?

We brought in, in the third quarter a couple of pieces of equipment that probably -- were probably about $1.5 million higher than what our guidance was for the year on CapEx. Moving forward, we do need -- we took some deliveries in the third quarter that we'll pay for in the fourth quarter, incremental CapEx, the fourth quarter above that will about $1 million. Maintenance CapEx next year with a 14-rig fleet would be between $3 million and $4 million. We've got a couple pieces of equipment we need to buy. There's a top drive, cattage, and there may be a pump or 2 that we would add on to next year from a CapEx perspective.

Okay. But, I mean, not to put words in your mouth, but, so comfortably sub-$10 million before contemplating the conversion, then? Is that still the right ballpark?

Yes, yes. Our fleet is still relatively new. You can use $100,000 per rig per year for kind of maintenance CapEx. And so, and then, on top of that, we've got some facility cost, et cetera, et cetera, so our cash requirements in a non-build environment are quite low.

The next question will be from Rob MacKenzie of Iberia Capital.

Byron, I wanted to dig a little further into the prospects and how you feel about the likelihood of signing up something here for a 300 series rig. Do you think you've gotten closer in terms of those conversations, over the past month, 2 months, 3 months?

Yes. So I have to be careful because I thought at one point we had a done deal and then some things occurred, we didn't. So we've been extraordinarily close, I think, in -- but I have nothing to report, multiple conversations and we're not the ones that are slowing it down. Not that anyone is purposely slowing anything down, but we continue to push as hard as we can, and to a great degree the market is coming to us, because this equipment doesn't exist, and it's going to be required, so at some point the dam breaks, I'm a little uncomfortable trying to predict it, because if I had done that in the past I would've been wrong.

Okay, fair enough. And then can you talk to us about data analytics, and how big a role that may play, both on the new rig design and also on your current fleet?

So there's 2 things to think about there. One is data capture, and we already do that. So we have an enormous amount of data that we capture through the computer systems on the rigs, that's available to clients and that's used, not used. It's very client specific, but I think we're gravitating toward an environment where the capture of that data and the integration of it into historical drilling curves and cost structures will become more and more prevalent. The second answer is that there are systems that go on to the rig, particularly because we have OMRON systems that eliminate directional drillers, and they do a lot of things in terms of speeding up drilling, risk reduction and cost reduction, and we're in active conversation with 2 providers of that type of equipment, and we'll make a decision in the next quarter or so about which way we're going to go. That is a cost adder, so it -- that wouldn't be included in the base day rate. If a client wanted us to switch a system that like that, there would be an additional per day cost associated with it.

(Operator Instructions) The next question will be from Thomas Curran with FBR Capital Markets.

Byron, when it comes to the next 2 new build conversations you're having, on your side, strategically, could you rank order for us in descending order which basins ideally you would deploy each or both of those 2 new builds into? And then also, on the customer side, do you have a preference for favoring a new customer over an existing one? Or are you just agnostic on that?

We have no particular favoring of new customers, existing customers. I can tell you that the demand for additional equipment that we're seeing is concentrated in the Haynesville and the Permian. Every once in a while we'll get inquiries for the Eagle Ford. We've operated in the mid-Con, and we get inquiries there, but the vast majority's going to be Permian and Haynesville. And to the extent one of these new builds are built, I would expect that they would be, based on everything I know right now, I'd expect that those would be the basins that this new equipment would show up in.

And then, across all the new technologies we've been discussing, using the power lines for power, big data analytics, the directional drilling add-on, for any of that, is there a certain critical mass level in a given basin, where if and once you hit a certain number of rigs running there, it will make an aspect of one or more of these technologies easier technically or more affordable? Is there any kind of critical mass considerations by basin for you?

I don't think so. I think it's a rig-by-rig decision and we can switch it on or off. And so, it's up to the clients what they want to use. And again, we already provide data capture. And once we decide on a particular vendor for some additional software associated with the variable frequency drive and the drilling program, that's again something that's rig-specific that can be turned on or off, so I don't think there's any critical mass aspect to that decision.

Okay. And then last one for me. Philip, assuming you don't move forward with either of the new builds and you steadily pay down all of your debt, can you give us an idea of what that sequence would look like on a quarterly basis, in terms of the amount of debt you'd expect to be paying down until you've taken it to 0?

Taking it to 0, when you think about our free cash flow next year, our CapEx is going to be low. Our cash flows, operating income is all increasing. We're not a taxpayer, so pretty steady next year drawdown in debt. I don't have a specific number for you where we go to 0. I don't think it would be next year. It has to be some time, later 2019. But if we're getting improving day rates, above what we've got now, then that's going to accelerate. So I don't have a specific time line, but we're going to pay down a substantial amount of debt next year, assuming that we don't build those next 2 rigs.

I think that's accurate, in that sometime in 2019, if we didn't build the rigs, we would extinguish our debt.

We would pay -- we'd pay down to 0 by the end of 2019.

Okay, and that's what I was trying to get at, even if it's just a hypothetical scenario, and when would you expect to get there based on the pace of paydown.

Yes.

(Operator Instructions) The next question will be from Taylor Zurcher with Tudor, Pickering & Holt.

Just a housekeeping one for me. So pro forma for these 4 contract renewals. Could you just share what the contract rollover schedule looks like, let's say, over the next 6 months, couple of quarters?

Yes, so we've got, we're pretty much booked up through the first quarter. I think we have 13.5 rigs in backlog in the first quarter, 8.2 in the second quarter next year and then 3.4 in the third quarter of next year.

Okay, got it. And then, appreciate the color on day rates. I'm just curious, it seems like the average spot rate or at least the breadth from high teens to low 20s at least on the margins seems to be getting wider, and so I guess my question is, is that more of a geographic issue, a customer issue, a term issue or is that sort of a mix of all 3? Probably a bit of an unfair question, but just curious, the different puts and takes as to how, maybe a rig rolls of this quarter, and you sign one at 18k a day versus something more in the low 20s.

So the market has reestablished itself. During the downturn, there really wasn't a market. There were ad hoc conversations, and I think we discussed that over the last, I don't know, 6, 7 quarters or so. So what's happened in the last 2, 2.5 quarters is, a pretty efficient market has reestablished itself, and there are people out there who prefer to use us, and we'll get a negotiated structure with them. There's people that bid these things out, but everybody's aware of what the current market is for this type of rig. What's working in our favor right now is, and what people are finding who are talking to us, is they'll go out, and they'll look to get a quote on a rig that has pad-optimal capabilities for some time next year, and there aren't necessarily any. There is contracted rigs, and the, of course, you go back to your existing client and work with them as we go through this process, but there isn't a lot of availability, and that dynamic is typically what sets up an improving day rate market. So I think the market's pretty efficient. I think it's reformed. And I think the momentum has slowed a little bit, but I'd expect that in a pre-budget time period, and I think once budgets are done and people go out and look for equipment, it's going to be very positive for the forward day rate environment in 2018.

Got it, helpful. Last one for me, if I can. You noted that the 4 renewals were sort of early renewals, are we to assume those were earlier than is typically the case? I.e., the customer might be afraid that the rig would go elsewhere unless they renewed today or was that sort of in due course?

So a couple of things. One is, that particular client is very pleased with us. We worked in partnership with them, to get a lot of things done so we have a very good relationship. The market is tight. And they came to us before contract expiration for renewals, and we worked with them and put a package together. So a number of things came together that produced that situation, but I think you're correct in that people are going out and testing the market and not finding the type of equipment they want to use readily available.

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

I want to thank all for being on the call, taking the time to hear our story this morning. Looking forward to visiting with you, some of you personally, over the next couple of weeks and speaking with you again in February and talking about our fourth quarter and how we see 2018 laying out. Thank you very much.

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