Independence Contract Drilling, Inc. (NYSE:ICD) Q3 2023 Earnings Call Transcript

Independence Contract Drilling, Inc. (NYSE:ICD) Q3 2023 Earnings Call Transcript November 1, 2023

Independence Contract Drilling, Inc. beats earnings expectations. Reported EPS is $-0.37, expectations were $-0.51.

Operator: Good morning, and welcome to the Independence Contract Drilling third quarter 2023 financial results conference call. All participants will be in a listen-only mode. [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.

Philip Choyce: Good morning, everyone, thank you for joining us today to discuss ICD’s third-quarter 2023 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 much materially from what we talked about today. For complete discussions of these risks, we encourage you to read the company’s release and our documents on filed with the SEC. In addition, we refer to non-GAAP measures starting 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 definitions of our non-GAAP measures. With that, I’ll turn it over to Anthony for opening remarks.

Anthony Gallegos: Hello, everyone, thank you for joining us for our third-quarter 2023 earnings conference call. During my prepared remarks today, I want to talk about three topics: first, I’ll talk about the super-spec rig market; second, I want to talk about the progress we made on some important strategic initiatives during the third quarter; and lastly, I want to close out talking about our plans as we exit 2023. But first, just a few comments looking back on the third quarter, which was a meaningful quarter for ICD on several fronts. First and foremost, we believe the third quarter represents the low point for ICD operating utilization, as we expect our operating fleet utilization to increase over the next several quarters.

The third quarter also represented the end of the transition of rigs from our Haynesville market to the Permian, and the elevated churn associated with repositioning our work in fleet with customers with longer-term drilling programs. During the quarter, we also saw increased rig inquiries that are leading to rig reactivations during the fourth quarter, and a line of sight for more reactivations in 2024. All of this manifested itself in our third quarter results. Philip will provide more details during his prepared comments, but overall, I see these third quarter results came in at the low end of our prior guidance. Cost per day was impacted by higher labor costs, as we staffed up for known fourth quarter reactivations. We also had slightly lower operating days compared to expectations, driven by rig churn as we prioritized repositioning rigs with customers with longer-term development programs.

During the third quarter, we continued the pursuit of our most important strategic initiative, which is deleveraging our balance sheet by paying down a second $5 million tranche of convertible notes at par. We look forward to continuing to take advantage of these opportunities to pay down debt and we have one more at the end of the fourth quarter and four additional opportunities next year. Equally important to continuing to take advantage of paydown opportunities, is positioning the ICD fleet in a manner that optimizes refinancing opportunities for the convertible debt, when the debt refinancing, when that begins to open approximately 12 months from now. We believe that involves returning to approximately 21 rigs operating, with a higher concentration of 300 Series rigs, working for the right type of customer and stair-stepping our contractual day rates in a manner that maximizes day rate opportunities when we believe market conditions will be stronger.

With that background, I’d like to talk a minute about the market super-spec rigs in our target markets, what we’re seeing from a rig reactivation day rate perspective, and I assume these priorities as we navigate what we expect to see over the next several quarters. As expected, we saw the US land rig count decrease over the third quarter. That was driven by the continued decline of drilling activity in the Haynesville and Permian, softer commodity prices during the summer, and strong capital discipline on the part of E&P companies. For ICD, this resulted in an overall decline in average operating rate rigs during the quarter. But as I mentioned before, we believe the third quarter is the bottom for us. Based upon what we are seeing, our expectation is that overall rig counts in our target markets will improve over the next several quarters.

Some of these opportunities are high-grade efforts on the part of the E&P’s attracted to our 300 series rigs. We expect the Haynesville to remain relatively muted until at least later in 2024. In the near term, I think the impending winter withdrawal season will determine Haynesville activity levels in the first-half of 2024. We also believe rig adds in the near-term are going to be weighted more toward privates, a key customer base for us. From one day rate perspective, in light of the existing softness in US land rig count and the fact that new contracting opportunities have only just began to emerge, we have seen some pressure on day rates. This is more pronounced for incremental rig adds than for renewals with existing customers. And as you might expect, there’s more day rate pressure in the Haynesville that in the Permian.

Day rates for our 300 Series rigs have generally stabilized in the low $30,000 range. And for our 200 Series rigs, the high $20,000 range. But I’d be remiss if I did not mention there are instances where we have lost work to competitors who have gone below these levels. As we get through this initial wave of reactivations, our expectation is that opportunities for day rate improvement will increase, as smaller contractors’ pad optimal fleets are more fully utilized and competition for incremental rig [Technical Difficulty] concentrates within your drilling contractors. We’re also seeing increased demand for our 300 Series rigs, which are principally 100% utilized at this time, which is leading to increased opportunities for our 200 to 300 Series conversion solution.

So what are the near-term priorities that we believe maximize our strategic objectives as we move forward in this expected uptick in activity? We like our fleet to return to 21 operating rigs by the middle of 2024, and we would like to continue increasing the penetration of our 300 Series rigs via our 200 to 300 series conversion, so that at least 75% of our operating rigs earning 300 series day rates by mid-2024. We also want to maintain our Haynesville presence to maximize opportunities there later in 2024 and beyond, when incremental LNG exportation capacity is expected to come online. We believe this setup maximizes ICD’s opportunity to return to margin per day levels that existed prior to the 2023 slowdown. In the near term, as we reactivate rigs, there will be some day rate pressure, thus, we will be looking to sign most of our contracts on shorter-terms, which allow for contract renewals higher rates, when we believe the market will be stronger.

In addition, we want full payback on the initial contract or any reactivation that involves CapEx expenditures associated with our 200 to 300 Series conversion. But how are we doing pursuing these priorities? First, with respect to the Haynesville, I’m very pleased that we now have three of our four rigs there placed with customers’ long-term drilling programs. We have one more 300 Series rigs in the Haynesville that we expect to contract here in the fourth quarter for an early 2024 reactivation. There was a lot of rig churn over the last few quarters to achieve this setup, but we believe that it behind us. Overall, in an environment which we return to 21 operating rigs mid-summer 2024, I’d like to have five operating in the Haynesville, which will be an appropriate balance in terms of commodity and basin exposure for our company, and allows us to leverage our strong brand and reputation for tailoring technology and equipment solutions to exceed our customers’ expectations.

We expect to end 2023 with 17 rigs operating, with another rig likely contracted for an early 2024 reactivation. In this regard, we’ve already signed two contracts for mid-fourth quarter reactivations, entering in advanced discussions for additional reactivations here in the fourth quarter. We also have begun dialogue for additional reactivations mid to late first quarter 2024. But I would consider those more in the early stages of discussion, which makes their outcomes much harder to predict at this time, given the indecisiveness and lack of formal guidance from E&Ps regarding their 2024 upstream CapEx plans. With respect to 200 to 300 Series conversions, we completed two additional 200 to 300 Series conversions during the third quarter, and last week completed an additional conversion supported by a signed contract that more than guarantees full simple payback of the CapEx investments.

With the completion of the most recent conversion last week, we have now converted four of our 200 Series rigs to 300 Series specification. Bigger-picture, this means that about three-quarters of the 17 to 18 rigs we expect to be operating at year-end will be 300 Series rigs, with opportunities to increase that percentage as we move through 2024. This is big for us as these conversions have important strategic implications for ICD, as they provide higher margin potential and additional exposure to the rig market segment with the highest specification requirements for the most technologically demanding work in the industry. By comparison, if you look at the end of the first quarter of this year when we were generating record margins and operated approximately 20 rigs, only half of those rigs were 300 Series rigs.

In addition to the conversions, we are continuing to execute on our rollout of our ICD impact offerings, including technology. We deployed additional systems during the third quarter. And also here in the fourth quarter, including oscillation, stick-slip mitigation, and back to bottom software, EDR packages, and hydropipe systems, and we will have additional rigs operating using the utility grid here in the fourth quarter. We are excited about what ICD impact means for our customers, the environment, and other stakeholders of our company going forward. And I expect the provision of these offerings will continue to enhance our financial performance as I indicated to you during our last earnings call. So rolling all this up, I’m confident that ICD has experienced the worst of the 2023 slowdown.

And we have commenced adding working rigs and repositioning our fleet to maximize utilization and margin potential as market conditions improve. I’ll make some additional concluding remarks before opening the call for questions, but right now, one of the call over to Philip to discuss our financial results and outlook in a little more detail.

Philip Choyce: Thanks, Anthony. During the quarter, we reported an adjusted net loss of $5.2 million or $0.37 per share, and adjusted EBITDA of $12.9 million. In calculating adjusted EBITDA and loss per share, we exclude $1.1 million associated with non-cash SG&A charges during the quarter, associated within a contract modification and extension. We operated 13.4 average rigs during the quarter, slightly below guidance, private provided on our prior conference call, caused by greater than expected idle days between contracts, as we repositioned rigs with customers for longer term drilling programs. During the quarter, we recognized $800,000 of transition costs associated with rig transitions. Early termination revenues during the quarter of $700,000 were recognized and offset partially these costs.

Moving on to our per day statistics, these statistics exclude both the early termination revenues and transition expenses I just mentioned. Revenue per day during the quarter was $32,925, representing a 4.5% sequential decrease from the second quarter. Cost per day during the quarter was $18,900, essentially flat with the second quarter. And overall margin per day was $14,005, on the low end of guidance representing a 9.4% sequential decline compared to the second quarter. SG&A costs were $6.9 million during the quarter, which included approximately $2 million of stock-based and deferred compensation expenses. It also included the $1.1 million charge I previously mentioned. Breaking out the components, cash, SG&A, expenses of $3.8 million were essentially flat compared to the second quarter.

And non-cash base SG&A compensation expense $2 million increased sequentially, driven by variable accounting on awards by the changes in our stock price and full quarter amortization of awards granted during the prior quarter. Interest expense during the quarter aggregated $9.2 million, which included $2.4 million associated with non-cash amortization of deferred issuance costs and debt discounts, which we excluded when presenting adjusted net income. Tax benefits for the quarter were diminimus and in line with guidance. During the quarter, cash payments for capital expenditures, net of disposals were approximately $3.9 million. For the remainder of the year, assuming we move towards 17 rigs reactivated by year-end, we expect capital expenditures during the fourth quarter to aggregate $5.5 million.

This includes cost to complete two additional 200, 300 Series reactivations and purchases of additional strings of drill pipe. Moving on to our balance sheet. So we continue to make progress towards debt reduction goals. We’ve repaid $5 million of convertible notes at par at quarter end and reduce revolver borrowings by $8.5 million during the quarter. The overall reduction and adjusted net debt during the quarter was $8 million. Our financial liquidity at quarter end was $21.7 million, comprised of cash on hand of $6 million and $15.7 million of availability under our revolving credit facility. Now moving on to our fourth quarter guidance, we expect operating days to approximately 1,355 days, representing 14.7 average rigs going revenue during the quarter, with reactivations only partially benefiting the fourth quarter.

We expect margin per day to come in between $11,700 to $12,300, with sequential decline related to lower day rates on contract renewals, slightly higher cost per day level, this contract mix becomes more heavily weighted towards the Permian Basin. Breaking out the components, we expect revenue per day to range between $31,000 and $31,500. We also expect sequential cost efficiencies during the quarter associated with contract reactivations, with the cost per day expected to range between $19,200 to $19,600 per day. I think it’s important to point out that only 4.5% of our expected fourth quarter revenue will be generated from legacy contracts executed in 2022. Plus, we believe the fourth quarter provides a reasonable estimation of the current spot day rate environment during the initial stages for the expected recovery in US land rig count.

Given only three of our current rig contracts extend past the first quarter of next year and then beyond the second quarter of next year, we believe we have positioned ICD to participate in a day rate recovery, driven by expected growth in the US rig count of the third quarter bottoms. Unabsorbed overhead expenses are expected to be about $600,000. We’ve excluded those expenses from our cost per day guidance. We do expect to incur rig reactivation expenses during the fourth quarter associated with the rehiring crew and the replenishment of operating supplies for the rig additions to our operating fleet during the fourth quarter and early 2024. Overall, we expect these will aggregate approximately $1 million during the quarter and are excluded from a margin per day guidance.

We expect fourth quarter cash SG&A expense to be approximately $4 million. Stock based compensation expense should approximate $2 million, assuming no material changes to our stock price that would impact variable accounting on awards. We expect interest expense to be approximately $9.7 million. Of this amount, approximately $2.6 million will relate to non-cash amortization of the deferred financing costs and debt discounts. Depreciation expense for the fourth quarter is expected to be flat with the third quarter, and we expect tax benefits to be diminimus during the fourth quarter. And with that, I’ll turn the call back over to Anthony.

Anthony Gallegos: Thanks, Philip. So wrapping all of this up, we believe ICD is very well positioned as we exit this most recent slowdown. In fact, I feel this is the strongest ICD there have ever been when entering an expected upturn in drilling activity. We continue to make progress on the three most important strategic initiatives we had, which include paying down debt, increasing our exposure to the 300 series market, and leveraging our ICD impact offerings. We remain optimistic about market momentum strengthening as we spread to year end 2023, primarily in all directed markets based on recently increased commodity prices during customer inquiries and discussions we’re having, and our expectation that WTI pricing will remain higher than the levels we saw during the second, third quarters of 2023.

I also think the effects of depleted duck inventories and more cash flow for our customers will provide additional boost to demand for drilling rigs in our target markets during 2024 from recharged E&P capital budget next year. For these reasons, I’m optimistic about reactivating our remaining idle rigs, on our way back to 21 operating rigs over the coming quarters. With that, we’ll open up the call for questions.

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Q&A Session

Operator: [Operator Instructions]. We will now begin the question-and-answer session. First question today comes from Don Crist with Johnson Rice.

Don Crist: Morning guys. Anthony, obviously, you walk through the demand picture out there, but can we get a little bit more color on particularly in the Haynesville? Obviously, you had a bunch of rigs running their early part of last year and then it fell off fairly significantly. And I think, if I heard you correctly, that you’re expecting to be five rigs again back in that area. Can you just expand on that a little bit and just the overall demand picture color?

Anthony Gallegos: Sure, Dan. Thanks for the question. You’re right. A lot of what happened to ICD this year was a function of our market presence in the Haynesville at the beginning of the year. And to put it into perspective, we had half our fleet contracted, just 10 rigs, working in Haynesville. Half of that 10 was with one customer who went from five rigs to zero. So that played out for us over the second and the third quarter, we bottomed out at to two rigs operating in over there, three rigs contracted. As commodity prices and rehab has improved as some of the local takeaway issues have been addressed, there’s been a small amount of demand appear. Some of it’s been in the western part of the Haynesville, the stuff over and Leon and Robertson County.

I think we heard an operator talk about that earlier this week; fantastic results they were reporting for their sixth and seventh wells, that’s good for our industry. For us, a prior customer of ours has started back up. We were their first call, that rig is back up and running now. It’s exciting for us as a company because we have started talking a lot about technology, so they picked up a sister rig to a rig they had before. This time, we have our technology, the technology that’s coming from third party partners that we have deployed and they’re seeing amazing results: better ROP, the same or better whole quality stuff like that. In addition to that, as we’re approaching fourth quarter, we expect to have the fourth rig contracted and running as we round out next year.

So just to put it in perspective, that means that the four rigs that we still have in base and all four will be contracted by the end of the year. We don’t have that for contract signed, but I’m pretty confident is going to come. When I mentioned five, that’s looking out into next year. Obviously, it would require that we move a rig back. We’re only going to do that if the conditions around the contractor are better than what we think we can do in the Permian. But as we think about that market longer term, from an ICD status quo perspective, five would be the top out of the 2021 that we would expect to be running in the back part of next year. Rates are softer. I mentioned that in the comments, when you think about the two markets. Haynesville, rates are a bit softer and that’s just a function of having gone from 80 rigs in the basin work into 38, 39 today.

Hasn’t been a lot of capacity move out, we’d probably move more about than anyone, still a lot of capacity on the sidelines. So we would expect pricing in the Haynesville to remain more challenging than the Permian, even against the backdrop of recharge budgets, capital budgets for 2024. But we’re very bullish in the long-term. I think in the short term, winter is going to be very, very important to what happens to gas prices. But our conversation with E&P customers in the Haynesville, there’s a lot of bullishness around the back part of 2024, especially 2025 and beyond, and that’s being driven by the expectations around LNG exports. So it’s a great market for us. It’s one of our two core markets. Strong brand and reputation over there, certainly don’t want to abandon that market.

I think it’s a place where we can really bring our talents to bear. And not just compete with everybody but outperform them as welI. But that’s what I would say about the Haynesville market, Don.

Don Crist: All right, I appreciate that color. And to talk a little bit — or to touch on the conversions, I’m assuming that it’s contracts that are pulling forward those conversions that you’re not just doing those on spec. And can you remind us of the of the day rate uplift that you get when converting a Series 200 to a 300?

Anthony Gallegos: Yes, you’re correct. We are doing those against a contract that is going to guarantee us simple payback, cash-on-cash. Obviously, we want to make a return on that, too. But just given the volatility, cyclicality of the business, it’s very, very important that at a minimum, we get that cash back. What we’ve said in the past and it’s holding out to be true, is it’s $2,000 to $3,000 a day uplift is what we see. It is interesting to me also because of the four conversions that we’ve completed so far, and we did two in the third quarter and we just finished another one; in fact, that rig started moving yesterday. But three of the four have been with customers that had the 200 series rig running first. Great rig.

And I am always concerned when I talk about our 300 that are somehow casting the 200 in about a lot of knot. They are super-spec pad optimal rigs, they go toe-to-toe with everything that’s out there. But the reason I point this out is three of the four have gone to customers that used to 200 Series rigs. They were very, very pleased with the 200 Series rigs and they like the fact that we can give them a little bit more capability with the 300 Series conversion. And we’ve been able to sign contracts that meet our requirements in terms as of the cash-on-cash payback.

Don Crist: Okay. And just one final one for me. Can you remind us what the current conversion prices? It’s a couple hundred thousand, right?

Philip Choyce: So it’s $650,000 to $800,000.

Don Crist: Okay. But you’re getting cash-on-cash payback over the contract term on those, right?

Philip Choyce: Yes.

Anthony Gallegos: Yes.

Don Crist: Okay, I appreciate it. I’ll get back in queue. Thanks.

Anthony Gallegos: Great. Thank you, Don.

Operator: Next question today comes from Steve Ferazani with Sidoti

Steve Ferazani: Good afternoon, everyone. Appreciate the detail on the call. I just want to do a lot of numbers; I just want to connect some of the dots. Based on your guidance, how many rigs do you have drilling at the end of 3Q? And how much do you have how many rigs are drilling right now?

Anthony Gallegos: We had 14 rigs drilling at the end of the quarter, we’ll have 16 rigs drilling at the end of November. And then obviously, we’re looking to add a 17th rig there in December.

Steve Ferazani: Okay. So the guidance of the average 14.7 rigs in 4Q is assuming probably some year-end white space with some of the rigs they finished programs a little bit early. Is that being a little bit conservative, assuming your endpoint?

Anthony Gallegos: There’s are a rig — we have moving between customers as we position rigs where there’s a couple of weeks of — there’s a little bit of white space. But there’s not any white space at the end of that. We would expect all of the 16 rigs to continue into next year.

Philip Choyce: But the rollout, they’re biased more toward–. Yeah.

Steve Ferazani: Okay. As far as the day rate trends, obviously, it held up for a while, Q3 was down, but not way off. The guidance for 4Q is down pretty — another step down. So you’re still seeing pricing pressure, you’re agreeing to short-term deals, but how differentiated is the pressure coming on pricing and to get rigs back to work? How much concessions you’re making?

Anthony Gallegos: Yeah, great question, Steve. I don’t think that’s isolated to ICD. I think the reason is kind of stands out more when we talk as Phil noted in his comments, we don’t have a lot of backlog. So certainly, everything we’re bringing out now is exposed to the spot market. And then, the fact that we’re constantly negotiating renewals with existing customers gives us added exposure towards current spot market rates are. Yeah, I’d point out that the most important metric when we talk about this is margin per day. And the things that the team’s doing around added services and stuff like that is going to be additive to margin per day. That’s what we focused on here. It is a bit softer, obviously, you see this anytime you go through a cycle: the ratcheting down of day rates as you’re moving down in rig count — you don’t feel it as much as when that incremental demand begins to appear.

Meaning, you bounced off bottom, there’s opportunities out there, it always gets a little bit more competitive, and that’s where we are right now. I pointed out in my comments that we have had missed out on some work where we were undercut. But I would say that, especially, among the big three in the industry, we’re seeing a lot of price discipline. The smaller contractors that tend to be a little bit more aggressive and where we sit is right there in the middle. And with a smaller fleet, we can be a little bit more patient. We don’t have to just go after and swing at every pitch that comes across plate. But we’re thinking about, obviously, geographic positioning, we’re thinking about commodity exposure, and we’re thinking a lot about the counterparty: who the E&P company is.

A lot of focus around multi-rig clients and making sure that we’re got a lot of exposure on that front. So when Philip talks about positioning with customers and stuff like that, those are the drivers that he’s referring to.

Steve Ferazani: Yeah, that’s really helpful. As you tried to crew up these rigs back to work, what’s the labor? Obviously, the rate kind of weighed down right now. Is it fairly easy to bring back crews and what type of costs? Because I know you hit your cost per operating day guidance is up a little bit.

Anthony Gallegos: Yeah, it’s been relatively easy. Look, it’s never easy to Steve. I’ve been really pleased with our people development group, the team, their efforts, but more importantly, the results and bringing some really good talent into the company. Cost to bring that talent in isn’t any higher today than it was in the last upcycle where we see the added cost is — we want to bring these people as, even industry experienced people in, we want to bring them in a little bit early. So they have a hitch or two with the company. They know what to do at the rig side in terms of technical skills, but they’re going to be new to our systems and processes, they’re certainly going to be new to our culture, and that’s where we see the cost inefficiencies as we were beginning the expansion of our operating rig count.

Steve Ferazani: Okay. That makes a lot of sense. Thanks, Anthony. Thanks, Philip.

Anthony Gallegos: Thanks, Steve.

Operator: Next question today comes from John Daniel with Daniel Energy.

John Daniel: Hey, guys, thanks for having me. One question on the demand outlook, — I think you say you’re at 15 rigs today and I guess — I might characterize this — as hope at this point that you’ll be at 21 in the middle of next year, that would be very impressive growth, right? And I’m curious, is this isolated to two or three of your, maybe customers you work with in the past are just coming back? Could you just walk us through that percent increase, relative to what the broader market might do? Again, I know its total speculation right now because–

Anthony Gallegos: Yeah, no, fully anticipated that question, John. I think the consensus out there is we should see in 14 to 17 rigs, go back to work over the course of 2024. I’m very confident that we’re going to end this year with 17 contracted, I think it’s probably 18. So to get back to the 21, there’s another three or four. You take the three or four and you compare that to the 14 to 17, that would imply that we would be punching our weight. We certainly did that in the last up cycle, if you recall. You’ve got to think also where we think a lot of the incremental demand is going to come from, and I think it’s going to be made more biased toward privates. That’s the same group of customer that really started to pull back a year ago.

You’ve seen the percent of rig count working for privates continue to decline, I think that starts to go the other way. I was at an industry function last week and I was talking with an investment banker on the E&P side, not on the services side, and he shared something when they and I haven’t heard this and call it a decade. But apparently, there’s a lot of money being raised, private equity money being raised to be deployed among E&P companies. And that’s very important because, if you think about the business over the last 20 or 30 years, M&A continues to accelerate. But through your career and my career, those management teams would go and raise money and do something else. And that’s not been the case in the last three, four, eight years.

It feels like, with the backdrop that’s out there today, in terms of the commodity where people think things are going, even in the face of this energy transition stop, I just think there is going to be a lot of private opportunities in 2024. And as you know, we do a lot of work for private E&P companies. And I think that growth is going to happen primarily in the south also. So think Permian, obviously, think Eagleford, and think . I just think, against that backdrop, for us to expect to put three or four more rigs out in the first two quarters of 2024, it’s not a layup, it’s never a layup. But I feel pretty good about our chances there.

John Daniel: Well, that’s all I had. I am hoping that you are correct, my friend.

Anthony Gallegos: Great. Thank you, John.

Operator: Next question today comes from Dave Strohm with Stonegate Capital Partners.

Dave Strohm: Just want to start: you’ve got a lot of new contracts come up that seems structural and strategic. I just want to get your sense on where you think the big sticking points are going to be again on those contracts over the finish line. Is it going to be the payback provisions? Is it going to be mostly great pressure terms, added services? Just would love to hear your thoughts around how you think the negotiating table is going to be.

Anthony Gallegos: Yeah, I think it’s going to start with is your rig capable. And that it sounds obvious, but if you think about what’s happening in the industry, with M&A and stuff like that, you’re seeing and hearing more discussion around longer laterals, obviously, everybody wants to be more efficient. It’s just a function of where we are in US shale today and the maturation that’s occurring. So I think it starts with what your rigs capability. Obviously, they want to understand your performance. That starts always with HS&E safety, but also just operational performance. We only have one 300 Series rig left in our inventory. That said, that’s probably the next rig or the second rig that gets contracted by the end of the year.

So that when we look at the last couple to get us to 21, they don’t have to be converted to 300 Series. They’re 200 Series rigs today. In fact, we’re in pretty advanced discussions around an existing 200 Series rig, one-year type situation, Permian Basin opportunity. And obviously, if we can secure that contract at a reasonable day rate without having to invest the capital and punt that upgrade three or four quarters out, that’s what we were going to do. But I think, to answer your question, is going to start with your technical capability around your rig and your rig specification. And that’s why you’ve heard us to pounding the table, really over the last year, year-and-a-half about the need to continue to have more exposure to the 300 Series market.

Because as we think about where things are going on in US shale, it’s going to be the 300 Series spec. Our investors should be pleased to know we’ve got a very obvious and relatively easy and relatively cost-effective pathway for gaining more of that exposure.

Dave Strohm: Understood. That’s very helpful. One more if I could, with it’s all the new tech initiatives that you’ve been rolling out, is there any difference in capabilities between the 200 and 300 Series rigs on what kind of tech they can operate there, or is it pretty homogenous?

Anthony Gallegos: Not on the software side. Things such as back to bottom sequencing, the oscillation, stick-slip, mitigation that that is deployed on both our 200 and 300 Series rig. Where you will see a difference is in the high torque capability. So think about the high torque drill strings, certainly the longer laterals, the hard toward top drives that we need to be able to put all that torque at the end of the three-mile lateral. That’s where you see the difference. And that also is what drives that day rate differential that we talked about earlier in the call of anywhere from $2,000 to $3,000 a day.

Dave Strohm: That’s perfect. Thank you for taking my questions and good luck in the fourth quarter.

Anthony Gallegos: Thank you, Dave.

Operator: Next question today comes from Jeff Robertson with Water Tower Research.

Jeff Robertson: Thanks. Good morning. Anthony, you mentioned — the refinance window on the notes opening up late next or I guess fourth quarter of ’24. How does that play into your thoughts around being able to remarket 300 Series rigs and contract duration for those both in the Permian and in the Haynesville as you look to trying to be in a position to maximize EBITDA looking into 2025 when you’re trying to consider doing something with the notes?

Anthony Gallegos: Great. Thank you for that question, Jeff. When we think about it, we want to put ourselves in a position to be able to maximize the opportunities as we enter that window. And that starts with having the 20 or 21 rigs running. Day rates are a bit softer than any of us would like. We talked a lot about that on this call, that we want to go relatively short. Keep them short so that as we approach what we think will be more demand for super-spec rigs in the back half of 2024 throughout 2025, then we’ll have the opportunity to get back to ratcheting rates up in the way that we did in the last upcycle, so that we’re in the best position possible to be able to evaluated many alternatives as there are available, to address the debt that will come due in 2026. Long way off. But as you know, you’ve got to be taking measures today to be able to make sure you put the company in the best position possible to address that. That’s how we may–.

Jeff Robertson: Thanks. You mentioned I believe at year-end 2023, that 75% of the fleet working will be plus 300 Series capability. If you skip forward to the fourth quarter of ’24, is there a case where you’d expect 100% of the of fleet to be 300 Series?

Anthony Gallegos: It’s probably in the 90% — of the remaining 200 Series to come out, all but one are the same. And we’re working on some engineering around that one. It already has a high torque top drive on it, so it has that and we can put the iron roughneck, the tool, on it, we just need to make sure we understand the pathway toward the mast and substructure upgrades, in a way that we’ve completed that upgrade on the other 200. But it’s upwards of 90%. And yes, there is a path there, a scenario where they’re all at 100%. But look, if we can contract our 200 Series rigs without having to make that investment generate what we think are appropriate returns, there wouldn’t be a need to do that. So there’s not a hard-and-fast rule. We haven’t said to ourselves, it’s not about ego. We haven’t said 100% has to be 300 series. But we do feel that, as we continue in this cycle and US shale, that that’s where things are going.

Jeff Robertson: Thanks for taking my questions.

Anthony Gallegos: Mr. Jeff, thank you.

Operator: Next question today comes from Don Crist with Johnson Rice.

Don Crist: Thanks for letting me back in, guys. Anthony, I wanted to ask a more macro question, and I fully admit that this may not have a direct answer. But as you look at the market today and surveying the guys who are depressing prices on the private side, any sense as to how many rigs that may be? And once those rigs are soaked up with incremental demand, do you think that pricing just rebounds towards that mid-30s level, given that the larger companies have held pricing as well as they have?

Anthony Gallegos: Yeah, I don’t think it’s as much as people think, Don, and the reason is: think about how much the requirements from our customers have changed since COVID, right? The laterals certainly are getting longer. The M&A that’s happening around us is — there’s a lot of drivers to that. But certainly, the ability to put together more contiguous acreage on the part of our customers is a big driver, which again, is going to drive that need for the ability to drill the longer laterals, more setback capacity, on and on and on. And when you survey the smaller contractors and installers, it’s not just them. Like I said, I think the big three are really doing a great job at it being very disciplined in the market. And as you’ve read into that, what you all, but certainly of the smaller contractors that are out there, there’s not as many of those types of rigs in those fleets.

In fact, for a couple of them, they’re essentially 100% utilized today among what we would consider to be 300-like type rigs. So what you just described is what I think is going to happen that in the first couple of quarters of next year, what excess capacity there is in this 300 Series market held by the smaller guys that is going to get snapped up, which is going to set the fairway for the big three to come in and do what they do. Because they’re going to have, at that time, what will be remaining big rig capacity. So yes, that is part of the thesis and how we see this playing out over the next 12 to 18 months.

Don Crist: I appreciate the color. Thanks a lot, guys.

Anthony Gallegos: Thanks, Don.

Operator: Next question today comes from Dick Ryan with Oak Ridge.

Dick Ryan: Thank you. So Anthony, on your ICD impact, how many of those systems are you currently have deployed? I know you had expectations that you could generate some incremental margins. Are you seeing any of that yet? Or are these still on a trial basis?

Anthony Gallegos: Yeah, it’s really a mixture. So we have — depending on how you classify it, four to six out there right now. There are some that we are getting paid for on a per-day basis. There’s a couple where there may be certain aspects that we’ve offered on a trial basis. Certainly, when we provided equipment, whether it be the biofuel, dual fuel capability of the rig or the ability to plug in the utility grid or the high torque drill strings that we’ve provided, we are getting paid for all of those at an appropriate rate that justifies the investment and earns an incremental return. We look out longer term when we think that there’s going to be increasing demand for these services. And certainly, our expectation would be we would get paid for any of these kind of things that we’re providing.

Right now, it’s somewhat of a mixture. It’s not the driver for us today, as much as the driver is getting these things out, proving these things up with our customers. And most importantly, being able to demonstrate, quantify where values being added to them. But our expectation would be like said, we are not just starting incremental day rate for it, but actually earning incremental margin. And while we’re doing that on some of them today, the expectation would be able to do that on all levels of over time.

Dick Ryan: Is this a differentiator as you’re talking to customers going into ’24, maybe some of the smaller competitors that are cutting prices, is this a differentiator for you guys?

Anthony Gallegos: Yes, it is. I appreciate you asking that because I should have pointed out earlier, it is. It just one more way, I think, that we stand out among what people would consider to be the smaller drilling contractors, right? The goal with ICD is like: I think we’ve got the best rigs in the industry; I know we have the best people in the industry, but we want to be able to offer the same level of, not just service, but equipment and capabilities as anyone else that’s out there. And that’s the pathway that we’re on. We’ve been working on this for a while, but it’s really exciting right now, especially here in the back part of this year to see this stuff finally getting deployed, seeing the adoption, but being able to walk into our customers’ office and show where value is being created.

Dick Ryan: Great. Thank you, Anthony.

Anthony Gallegos: Great. Thank you, Dick.

Operator: This concludes our question-and-answer session. I would like to turn the conference back over to Anthony Gallegos for any closing remarks.

Anthony Gallegos: We sure appreciate everyone dialling, and I would like to say thank you very much to all the employees of ICD, the hard work, their dedication, their sacrifice, we really appreciate that. But thank you, everybody, for dialling into today’s call. We appreciate you making time. We’ll end the call from here.

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