Independence Contract Drilling, Inc.

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. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on a touch-tone phone. To withdraw your question, please press star then two. Please note, this event is being recorded. I would now like to turn the conference over to Philip Choice, Executive Vice President and Chief Financial Officer. Please go ahead.

Good morning, everyone. Thank you for joining us today to discuss ICD's third quarter 2023 results. With me today is Nancy 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 at the SEC. In addition, we refer to non-GAAP measures during the call. Please refer to the earnings release and our public filings for our full reconciliation of net loss to adjusted net loss, EBITDA and adjusted EBITDA, and for definitions of our non-GAAP measures. With that, I'll turn it over to Anthony for opening remarks.

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 things. First, I will 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 Hainesville market to the Permian and the elevated churn associated with repositioning our working 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. Phillip will provide more details during his prepared comments, but overall, ICD's 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 drilling 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 part. We look forward to continuing to take advantage of these opportunities to pay down debt. 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 pay down opportunities is positioning the ICD fleet in a manner that optimizes refinancing opportunities for the convertible debt when the debt refinancing window 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 for super spec rigs in our target markets, what we're seeing from a rig reactivation and day rate perspective, and ICD's 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 Hainesville 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 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 E&Ps attracted to our 300 series rigs. We expect the Hainesville to remain relatively muted until at least later in 2024. In the near term, I think the impending winter withdrawal season will determine Hainesville activity levels in the first half of 2024. We also believe rig ads in the near term are going to be weighted more toward privates, a key customer base for us. From a day rate perspective, in light of the existing softness in U.S. land rig count and the fact that new contracting opportunities have only just begun to emerge, we have seen some pressure on day rates. This is more pronounced for incremental rig ads than for renewals with existing customers. And as you might expect, there's more day rate pressure in the Hainesville than 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 reactivation, 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 ads concentrates within fewer 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 during this expected uptick in activity? We would 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 are earning 300 series day rates by mid 2024. We also want to maintain our Hainesville 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 will allow for contract renewals at higher rates when we believe the market will be stronger. In addition, we want full payback on the initial contract for any reactivation that involves CapEx expenditures associated with our 200 to 300 series conversions. How are we doing pursuing these priorities? First, with respect to the Hainesville, I'm very pleased that we now have three of our four rigs there placed with customers with long-term drilling programs. We have one more 300 series rigs in the Hainesville 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 is behind us. Overall, in an environment in which we return to 21 operating rigs mid-summer 2024, I'd like to have five operating in the Hainesville, 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 reactivation, and are 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 ENPs regarding their 2024 upstream CAPEX plants. 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 investment. 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 ICB 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're continuing to execute on a 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 high torque drill pipe 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 I want to turn the call over to Philip to discuss our financial results and outlook in a little more detail.

Thanks, Anthony. During the quarter, we reported an adjusted net loss of $5.2 million for 37 cents per share and adjusted EBITDA for $12.9 million. In calculating adjusted EBITDA and loss per share, we excluded $1.1 million associated with non-cash SG&A charges during the quarter associated with the contract modification and extension. We operated 13.4 average rigs during the quarter, which is not leaving below guidance provided on our prior conference call, caused by great unexpected idle days between contracts as we repositioned rigs with customers with longer-term drilling programs. During the quarter, we recognized $800,000 of transition costs associated with rate 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 $18,920, essentially flat with the second quarter. An overall margin per day was $14,005 on the low end of guidance and 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 in 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-based SG&A compensation expense, $2 million increased sequentially, driven by variable accounting on awards, tied to 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, This included $2.4 million associated with non-cash amortization, deferred issuance costs, and debt discounts, which we excluded when presenting adjusted net income. Tax benefits for the quarter were de minimis 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 costs to complete two additional 200-300 series reactivations and purchases of additional strings of drill pipe. Moving on to our balance sheet, we continue to make progress towards debt reduction goals. We repaid $5 million of convertible notes at part and quarter end and reduced revolver borrowings by $8.5 million during the quarter. The overall reduction in 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 fourth quarter guidance. We expect operating days to approximate 1,355 days, representing 14.7 average rates on revenue during the quarter, with reactivations only partially benefiting the fourth quarter. We expect margin per day to come in between $11,700 and $12,300, the sequential decline relating to lower day rates on contract renewals, slightly higher cost per day levels as 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 efficiency during the quarter associated with contract reactivations with costs per day expected to range between $19,200 and $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 of the expected recovery in U.S. land rate count. Given only three of our current rate contracts extend past the first quarter of next year and none beyond the second quarter of next year, we believe we have positioned IC to participate in any day rate recovery driven by expected growth in U.S. rate count of the third quarter bonds. 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 crews and 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 our 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. For this amount, approximately $2.6 million will relate to non-cash amortization with 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 de minimis during the fourth quarter. And with that, I'll turn the call back over to Anthony.

Thanks, Phillip. 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 has ever been when entering an expected upturn in drilling activity. We continue to make progress on the three most important strategic initiatives we have, 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 sprint to year end 2023. primarily in oil-directed markets based on recently increased commodity prices, current customer inquiries and discussions we're having, and our expectation that WTI pricing will remain higher than the levels we saw during the second and 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 budgets 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.

We will now begin the question and answer session. To ask a question, you may press star then 1 on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star, then two. At this time, we will pause momentarily to assemble our roster. The first question today comes from Dawn Christ with Johnson Rice. Please go ahead.

Morning, guys. Anthony, obviously you walked through the demand picture out there, but could we get a little bit more color on, particularly in the Haynesville? Obviously, you had a bunch of rigs running there early part of last year, and 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 kind of the overall demand picture color?

Sure, Don. 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 Hainesville at the beginning of the year. And to put it into perspective, we had half our fleet contracted ten rigs working in the Hainesville. Half of that ten was with one customer who went from five rigs to zero. That played out for us over the second and third quarter. We bottomed out at two rigs operating over there, three rigs contracted. As commodity prices Henry Hub 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 Hainesville. The stuff over in Leon and Robertson County, I think we heard an operator talk about that earlier this week. Fantastic results. They're 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, you know, we have started talking a little bit about technology. So they, you know, they picked up, you know, a rig, a sister rig to a rig they had before. This time we have our technology, the technology that's coming from the third-party partners that we have employed, and they're seeing amazing results, you know, better ROP, the same or better hole 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. Just to put it in perspective, that means the four rigs that we still have in the basin, all four will be contracted by the end of the year. We don't have that fourth contract signed, but I'm pretty confident it's 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 contract 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 20 or 21 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, Hainesville rates are a bit softer, and that's just a function of having gone from 80 rigs in the base and working to 38, 39 today. Hasn't been a lot of capacity move out. We've probably moved more out than anyone. Still a lot of capacity on the sidelines. So we would expect pricing in Hainesville to remain more challenging than the Permian, even against the backdrop of you know, recharge budgets, capital budgets for 2024. But we're very bullish in the long term. I think in the short term, you know, winter is going to be very, very important to what happens to gas prices. But our conversation with E&P customers in Hainesville, 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 well. But that's what I would say about the Hainesville market.

Don? I appreciate that, Culler. And to talk a little bit on the, 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 day rate uplift that you get when converting a Series 200 to a 300?

Yes, you're correct. We are doing those against the 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, it's kind of $2,000 to $3,000 a day uplift is what we see. It's interesting to me also because of the four conversions that we've completed so far. We did two in the third quarter and we just finished another one. In fact, that rig started moving yesterday. Three of the four have been with customers that had the 200 series rig running first. Great rig. I'm always concerned when I talk about our 300s that I'm somehow casting the 200s in a bad light. I'm not. They are super spec pad optimal rigs. They go toe-to-toe with you know, everything that's out there. But the reason I'm pointing this out is three of the four have gone to customers that use the 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 like I said, we've been able to sign contracts that, you know, meet our requirements in terms of the cash-on-cash payback.

Okay. And just one final one for me. Can you remind us what the conversion price is? It's a couple hundred thousand, right?

No, it's $650,000 to $800,000. Okay.

But you're getting cash on cash payback over the contract term on those, right? Yes. Yes. Okay. I appreciate it. I'll get back in queue. Thanks. All right. Thank you, Don.

The next question comes from Steve Feranzi with Sidoti. Please go ahead.

Good afternoon, everyone. Appreciate the detail on the call. I just want to get a lot of numbers. I just want to connect some of the dots. Based on your guidance, how many rigs did you have drilling at the end of 3Q, and how many rigs are drilling right now?

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.

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 finish programs a little bit early. Is that sort of you just being a little bit conservative, assuming...

No, there's a rig or two. There's a rig that we have moving between customers as we position rigs where there's a couple weeks of – there's a little bit of white space. But there's not any white space at the end of the – we would expect all those 16 rigs will continue into next year. But the rollout, they're biased more toward the back. Yes, they're biased to the back.

Okay, 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 was 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 are you making?

Yeah, great question, Steve. I don't think that's isolated to ICD. I think the reason it kind of stands out more when we talk is, as Philip 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 to where 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 focus on here. It is a bit softer, obviously. You see this any time you go through a cycle. The ratcheting down of day rates as you're moving down in rig count isn't as you don't feel it as much as when that incremental demand begins to appear, meaning you've bounced off bottom, there's opportunities out there. It always gets a little bit more competitive. And that's where we are right now. You know, I pointed out in my comments that we have 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. It's, the smaller contractors that tend to be a little bit more aggressive and kind of where we sit is kind of right there in the middle. And, you know, 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 the 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, you know, we've got a lot of exposure on that front. So when Phillip talks about positioning with customers and stuff like that, those are the drivers that he's referring to.

Yeah, that's really helpful. As you try to crew up these rigs to go back to work, what's the labor? Obviously the rig count way down right now. Is it fairly easy to bring back crews and what type of costs is it? Because I know you're, your cost per operating day guidance is up a little bit.

Yeah, it's been relatively easy. Look, it's never easy. Steve, I've been really pleased with our people development group, that team, their efforts, but more importantly, the results in bringing some really good talent into the company. You know, 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 in, even industry experienced people in, we want to bring them in a little bit early so that they have a hitch or two with the company. They may 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're beginning the expansion of our operating rig count.

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

Yes, sir. Thanks, Dave.

The next question comes from John Daniel with Daniel Energy. Please go ahead.

Hey, guys. Thanks for having me. Just one question on the demand outlook. I think you say you're at 15 rigs today, and I guess I'm going to 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've worked with in the past that are just coming back? Because I think if you could just walk us through that percent increase relative to what the broader market might do. Again, I know it's total speculation right now because you're looking at-

fully anticipated that question, John. I think the consensus out there is we should see 40 to 70 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 that So you take the three or four and you compare that to the 40 to 70, that would imply that we would be punching above our weight. We certainly did that in the last up cycle, if you'll 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 more biased toward privates. That's the same group of customer that really started to pull back a year ago You know, you've seen the percent of rig count working for privates continue to decline. I think that starts to go the other way. You know, I was at an industry function last week and was talking with an investment banker on the E&P side, not on the services side, and he shared something with me, and I haven't heard this in, 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, you know, if you think about the business over the last 20 or 30 years, you know, M&A continues to accelerate, but throughout your career and my career, those management teams would go and raise money and do something else. And that's not been the case, you know, 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 stuff, I just think there's 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 Hainesville. And 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 Arkansas there. Well, that's all I had.

I am hoping that you are correct, my friend. Great. Thank you, John.

The next question comes from Dave Strom with StoneGate. Please go ahead.

Good morning.

Good morning, Dave.

Good morning. Just want to start up. You've got a lot of new contracts coming up that seems structural and strategic. Just want to get your sense on where you think the big sticking points are going to be on getting those contracts over the finish line. Is it going to be the payback provisions? Is it going to be mostly rate pressure terms, added services? Just would love to hear your thoughts around how you think the negotiating table is going to be.

I think it's going to start with is your rig capable? That 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. You know, it's just a function of where we are in U.S. shale today and the maturation that's occurring. So I think it starts with what's your rig's capability. Obviously, they want to understand your performance. That starts always with HSE safety. but also just operational performance. We only have one 300 series rig left in our inventory. Like I 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. There are 200 series rigs today, In fact, we're in some pretty advanced discussions around an existing 200 series rig, one year type situation, you know, Permian Basin opportunity. And obviously, if we can secure that contract at a reasonable day rate without having to invest the capital and kind of punt that upgrade, you know, three or four quarters out, that's what we're going to do. But I think to answer your question, it's going to start with your technical background. capability around your rig and your rig specification. And that's why you've heard us pounding the table, you know, 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 in U.S. shale, it's going to be the 300 series spec. And, you know, our investors should be pleased to know we've got a very obvious and relatively easy and relatively cost effective way, pathway, toward gaining more of that exposure.

Understood. That's very helpful. One more, if I could. With all the new tech initiatives that you've been rolling out, is there any difference in capabilities between the 200 and 300 series rigs? So, you know, what kind of tech they can operate there? Or is it, you know, pretty homogenous?

Not on the software side. Things such as back-to-bottom sequencing, the oscillation and stick-slip mitigation, that is deployed on both our 200 and 300 series rigs. 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 higher-torque top drives. that we need to be able to put all that torque at the end of a 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.

That's perfect. Thank you for taking my questions, and good luck in the fourth quarter.

Thank you, Dave.

The next question comes from Jeff Robertson with Water Tower Research. Please go ahead.

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 Hainesville as you look to try to be in a position to maximize EBITDA looking into 2025 when you're trying to consider doing something with the notes.

Yep, great. Thank you for that question, Jeff. When we think about it, we want to put ourselves in the position to be able to maximize the opportunities as we enter that window. And that starts with having the 20 or 21 rigs running. You know, day rates are a bit softer than any of us would like. We talk a lot about that on this call. So 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 up cycle so that we're in the best position possible and to be able to evaluate as 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 do it.

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

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. 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 and the way that we've completed that upgrade on the other 200s. But it's upwards of 90%. And yes, there is a scenario where they're all at 100%. Look, if we can contract our 200-series rigs without having to make that investment and 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, you know, 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 in U.S. shale, that's where things are going.

Thank you for taking my questions.

Mr. Jeff, thank you.

The next question comes from Don Crist with Johnson Rice. Please go ahead.

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

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, you know, 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 it's not just them. Like I said, I think the big three are really doing a great job at being very disciplined in the market. So you read into that what you want. 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 we think or 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 sapped 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.

I appreciate the call. Thanks a lot, guys.

The next question comes from Dick Ryan with Oak Ridge. Please go ahead.

Thank you. So, Anthony, on your ICD impact, how many of those systems do 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 kind of still on a trial basis? Yeah, it's really a mixture.

So we have, depending on how you classify it, kind of 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've provided equipment, whether it be the bi-fuel, 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. You know, as we look out longer term, 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 is 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 and quantify where value is being added to them. But our expectation would be, like I said, we are not just earning 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 to be able to do that on all of them over time.

Okay. Is this a differentiator as you're talking to customers going into 24, maybe some of the smaller competitors that are cutting price? Is this a differentiator for you guys?

Yes, it is. I appreciate you asking that, Dick, because I should have pointed that earlier. It is. It's just one more way, I think, that we stand out among what people would consider to be the smaller drilling contractors, right? The You know, the goal with IECD is, look, 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 is 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, see this stuff finally getting deployed, seeing the adoption, but being able to walk into a customer's office and show where value is being created. Sure.

Great. Thank you, Anthony.

Great. Thank you, Dick.

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

We sure appreciate everyone dialing in. 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 dialing in to today's call. We appreciate you making time. We'll end the call from here.

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