Q3 2023 Independence Contract Drilling Inc Earnings Call

Good morning, and welcome to the independence contract Drilling's third quarter 2023 financial results Conference call.

All participants will be in a listen only mode.

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After todays presentation, there will be an opportunity to ask questions.

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Please note this event is being recorded.

I'd now like to turn the conference over to Philip Choyce, 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 as you can see Guy I guess.

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 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 starting to 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.

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.

I want to talk about the progress we made on some important strategic initiatives during the third quarter.

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.

Third quarter also represented the end up the transition of Briggs from our Haynesville 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 reactivation during the fourth quarter and a line of sight for more reactivation in 2024.

All of this manifested itself in our third quarter results Philip 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 cost as we staffed up for known fourth quarter reactivation.

We also had slightly lower operating days compared to expectations driven by rig churn as we prioritize repositioning greg's with customers with longer term drilling programs.

During the third quarter, we continue 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 with <unk>.

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 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.

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 in Icd's priorities as we navigate what we expect to see over the next several quarters.

As expected we saw the U S 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 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 haynesville to remain relatively muted until at least later in 2024.

In the near term I think the impending winter withdrawal season will determine.

While activity levels in the first half of 2024, we also believe rig adds in the near term are going to be weighted more towards private 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 adds and for renewals with existing customers and as you might expect theres more day rate pressure in the Haynesville then in the Permian.

Day rates for our 300 series rigs have generally stabilized in the low 30000 dollar range for our 200 series rigs the high 20000 dollar 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 or more fully utilized and competition for incremental rig adds concentrates within pure 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 maximizes 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. They are 200 to 300 series conversions, 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 'twenty 'twenty four 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 won't full payback on the initial contract or any reactivation that involves capex expenditures associated with our 200 to 300 series conversion.

So 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 they're placed with customers long term drilling programs.

One more 300 series rigs in the Haynesville that we expect to contract here in the fourth quarter for an early 2020 for reactivation.

With a lot of rig churn over the last few quarters to achieve is set up well, we believe that is behind us.

Overall in an environment, which we returned 21 operating rigs mid summer 2024, I'd like to have five operating in the Haynesville, which would 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 in early 2020 for reactivation.

In this regard we've already signed two contracts or mid fourth quarter reactivation.

In advanced discussions for additional reactivation is here in the fourth quarter.

We also have begun dialogue or additional reactivation as 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 and decisiveness and lack of formal guidance from E&ps regarding their 2020 for 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 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 <unk>.

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 moved through 2024. This is big for US as these conversions have important strategic applications for ICD.

As they provide howard margin potential in 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 where 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 high torque drill pipe systems.

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 to provision of these offerings will continue to enhance our financial performance as I indicated to you during our last earnings call.

So rolling all of 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 more detail.

Thanks Anthony.

During the quarter, we reported an adjusted net loss of $5 $2 million or 30, 37 per share and adjusted EBITDA of $12 $9 million.

Calculating adjusted EBITDA and a loss per share excludes $1 $1 million associated with noncash SG&A charges during the quarter associated with the contract modification and extension.

We operated 13 four average rigs during the quarter slightly below guidance provided on our prior conference call because by greater than expected idle days between contracts as we repositioned rigs with customers with longer term drilling programs.

During the quarter, we recognized $800000 of transition costs associated with rate transitions.

Early termination revenues during the quarter of $700000 recognized as an offset.

Partially these costs.

Moving onto our per day statistics, the statistics exclude both the early termination revenues transition expenses I just mentioned.

Revenue per day during the quarter was $32925, representing a four 5% sequential decrease from the second quarter.

Cost per day during the quarter.

$18920 essentially flat with the second quarter.

And overall margin per day was $14005 on the low end of guidance and representing a nine 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, but also included the $1 $1 million charge I previously mentioned.

Breaking out the components of cash SG&A expenses of $3 $8 million were essentially flat compared to the second quarter and noncash based SG&A compensation expense $2 million increase 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 noncash amortization deferred issuance cost and debt discounts, which were excluded when presenting adjusted net income.

Tax benefits for the quarter were de Minimis 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. So I mean, we move towards 2017 rigs reactivated by year end.

Capital expenditures during the fourth quarter aggregate $5 $5 million.

This includes cost to complete two additional 200 300 series reactivation and purchases of additional streams of drill pipe.

Moving onto our balance sheet, we continue to make progress towards debt reduction goals.

We repaid $5 million of our convertible notes at par at quarter end and reduced revolver borrowings by $85 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 onto fourth quarter guidance.

We expect operating days to approximate 1355 days, representing 14, seven average rigs, earning revenue during the quarter.

With reactivation to only partially benefiting the fourth quarter.

We expect margin per day to come in between 11700 $12300.

Sequential decline related to lower day rates on contract renewals slightly higher cost per day levels. This contract mix becomes more heavily weighted towards the Permian basin.

Breaking out the components, we expect revenue per day to range between 31030 $1500. We also expect sequential cost efficiencies during the quarter associated with contract reactivation cost per day expected to range between 19200 $19600 per day.

I think it's important to point out that only four 5% of our expected fourth quarter revenue will be generated from legacy contracts executed in 2022.

Thus, we believe the fourth quarter provides a reasonable estimation of the current spot day rates environment. During the initial stages of the expected recovery in U S 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 are positioned to participate in any day rate recovery driven by expected growth in the U S rig count off the third quarter bottoms.

Unabsorbed overhead expenses are expected to be about $600000. We've excluded those expenses from our cost per day guidance.

We do expect to incur a rig reactivation expenses during the fourth quarter associated with the re hiring crews and replenishment of operating supplies for the rig additions to our operated 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.

Stock based compensation extension, approximately $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 or relate to noncash amortization of deferred financing cost of debt discounts.

Depreciation expense for the fourth quarter is expected to be flat with the third quarter.

And we expect tax benefit to be de Minimis during the fourth quarter.

And with that I'll turn the call back over to Anthony.

Thanks Philip.

So wrapping all of this we believe ICD is very well positioned as we exit. This most recent slowdown in fact I feel this is the strongest ICD 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 spent a year end 2023, primarily in all directed markets based on recently increased commodity prices current customer inquiries and discussions we're having in our expectation of WTS wtf pricing will remain higher than the levels. We saw during the second third quarters of 2023.

I also think the effects of depleted DUC inventories and more cash flow for our customers, who 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 'twenty, one operating rigs over to come.

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 one on your Touchtone phone.

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At this time, we will pause momentarily to assemble our roster.

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

Good morning, guys.

Anthony obviously, you walked through the demand picture out there.

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. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero.

Can we get a little bit more color on particularly in the Haynesville.

You know, obviously you had a bunch of rigs running their early part of last year and it fell off.

Fairly significantly.

Operator: 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 think if I heard you correctly, then you are expected 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.

Philip Choyce: I would now like to turn the conference over to Philip Choyce, Executive Vice President and Chief Financial Officer. Please go ahead. Good morning, everyone. And thank you for joining us today to discuss ICD's third quarter, 2023 Results.

You're right, there's 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 10 rigs working in the Haynesville half of that Tim was with one customer who went from five rigs to zero.

Anthony Gallagos: With me today, I think I and you guys are President and Chief Executive Officer. Before we begin, I would like to remind all participants that 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.

That played out for us over the second and the third quarter.

We bought them down at two rigs operating over their three rigs contracted.

Sure.

As prices commodity prices Henry hub has improved as some of the takeaway local takeaway issues have been addressed there's been a small amount.

Philip Choyce: For complete discussion of these risks, we encourage you to read the company's earnings release and our documents on by the SEC. In addition, we refer to non-gap measures during the call. Please refer to the earnings release and our public filings for a forward reconciliation of net loss to adjusted net loss, EBITDA and adjusted EBITDA and for definitions of our non-gap measures.

Demand appear some of it's been in the western part of the Haynesville the stuff over in Leon and Robertson County, I think we heard an operator talk about that earlier. This week fantastic results that we're reporting for their sixth and seventh wells that's good for our industry.

Uh huh.

For us.

A prior customer of ours has started back up.

Anthony Gallagos: 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.

We were their first call that rig is back up and running now.

Is exciting for us as a company because we have started talking a lot about technology. So they.

Anthony Gallagos: During my prepare remarks today, I want to talk about three things. First, we'll talk about the SuperSpec Rig Market. Second, I want to talk about the progress we made on some important strategic initiatives during the third quarter. Lastly, I want to close out talking about our plans as we exit 2023. The first, just a few comments looking back on the third quarter, which was a meaningful quarter for ICD on several fronts.

Picked up a rig of sister rig to rig they had before this time, we have our technology. The technology, that's coming from third party partners that we have employed and Theyre seeing amazing results better RFP.

The same or better hole quality stuff like that.

In addition.

To that.

As we're approaching fourth quarter.

Anthony Gallagos: 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 and 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 than 2024.

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 the base in 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.

The conditions around the contract or better than what we think we can do in the Permian.

But.

Anthony Gallagos: All of this manifested itself in our third quarter results. Philip 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. Costs 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.

As we think about that market longer term.

From an ICD status quo perspective, five would be the top out of the <unk> 'twenty or 'twenty, one that we would expect to be running in the back part of next year.

You know rates are softer I mentioned that in the comments when you think about the two markets.

Anthony Gallagos: During the third quarter, we continued the pursuit of our most important strategic initiative which is de-leveraging our balance sheet by paying down a second, $5 million tranche of convertible notes at part. We looked 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 continue and to take advantage of pay-down opportunities is positioning the IECD bleed in a manner that optimizes refinancing opportunities for the convertible debt when the debt refinancing window begins to open approximately 12 months from now.

Haynesville rates are a bit softer and thats just a function of having gone from 80 rigs in the basin working to 38 39 today.

It hasn't been a lot of capacity move out we probably moved more out that anymore.

Still a lot of capacity on the sidelines.

So we would expect pricing in the haynesville to to remain more challenging than the Permian even against the backdrop of.

Recharged budgets capital budgets for 2024.

But that 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.

Anthony Gallagos: 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.

There's a lot of bullishness around the back part of 2020 for especially 2025 and beyond.

And that's being driven by the expectations around the LNG exports. So yes, it's a great market for us it's one of our two core markets with <unk>.

Anthony Gallagos: 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 in IECD's priorities as we navigate what we expect to see over the next several quarters. As expected, we saw the U.S.-Land Rick County crease over the third quarter. That was driven by the continued decline of drilling activity in the Hainesville impermeant, softer commodity prices during the summer, and strong capital discipline on the part of the NP companies.

<unk> brand and reputation over there.

Don't want to abandon that market I think it's a place where we can really bring our talents to bear and.

And not just compete with everybody but.

Perform them as well.

That's what I would say about the haynesville market.

I appreciate that color and to talk a little bit on the <unk> to touch on the conversions.

I'm, assuming that it's contracts that are pulling forward. Those conversions that you are not just doing those on spec and can you remind us of the of the day rate uplift that you get when converting our series 200 to $300.

Anthony Gallagos: For IECD, 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 and our target markets will improve over the next several quarters. Some of these opportunities are high-grade efforts on the part of the NP's attracted to our 300 series rigs. We expect the Hainesville to remain relatively muted until at least later in 2024.

Yes, you are correct, we are doing those against the.

Against the 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.

Anthony Gallagos: In the near term, I think the impending winter withdrawal season will determine at Hainesville activity levels in the first half of 2024. We also believe rig ag ads in the near term are going to be weighted more toward privates and key customer base for us. From a day rate perspective, in light of the existing softness in the 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.

We get that cash back.

What we've said in the past and it is holding out to be true, it's kind of two to $3000. A day uplift is what we see.

It's 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 it back that rig started moving yesterday.

Uh huh.

Anthony Gallagos: This is more pronounced for incremental rig ads than for renewals with existing customers. As you might expect, there is 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.

Three of the four have been with customers that have.

Had the 200 series rig running first.

And a great rig.

I am always concerned when I talk about our three hundreds that I'm somehow casting the two hundreds in a bad light I'm not that 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.

Anthony Gallagos: As we get through this initial wave of reactivations, our expectation is that opportunities for day rate improvement will increase, as smaller contractors path often will fleece or more fully utilized, and competition for incremental rig ads concentrates within pure 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.

Three of the four 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.

Like I said, we've been able to sign contracts that meet.

Meet our requirements in terms of that.

Cash on cash payback.

Okay and just one final one for me can you remind us what the current conversion prices a couple of hundred thousand right.

Anthony Gallagos: 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.

No it's 650 to $800000.

But you're getting cash on cash payback over the contract term on those right.

Yes.

Okay I appreciate it I'll get back in queue. Thanks.

Alright, Thank you Donna.

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

Anthony Gallagos: We also want to maintain our handsable presence to maximize opportunities there later in 2024 and beyond when incremental LNG exploitation 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 won't pay back on the initial contract for any reactivation that involves CAPEX expenditures associated with our 200 to 300 series conversion.

Good afternoon, everyone I appreciate the detail on the call I just wanted to get a lot of numbers I just want to connect some of the docs.

Based on your guidance, how many rigs did you have drilling at the end of <unk> and how much do you have how many rigs are drilling right now.

We had 14 rigs drilling at.

At the end of the quarter, we will have 16 rigs drilling at the end of November.

And then obviously, we're looking to add.

The 17th ranked there in December.

Okay. So the guidance of the average 14, seven rigs and for Q is assuming.

Anthony Gallagos: So, 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, their place 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 is behind us.

Probably some yearend white space with some of the rigs they finished programs a little bit early is that sort of you're just.

Being a little bit conservative assuming.

Year end why no no no.

Theres, a rig or two.

There is a rig that we have moving between customers as we positioned rigs where there was a couple of weeks.

There's a little bit of white space, but theres not theres not any white space at the end of the at the end of the we would expect those all of those 16 rigs will continue into next year.

Anthony Gallagos: Overall, in an environment which we returned to 21 operating rigs in the 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.

But the rollout they're biased more toward the back little bit, thereby it yes.

Yes.

Okay.

As far as the day rate trends, obviously got it.

It held up for a while.

Q3 was down but not way off the guidance for <unk> was down pretty good.

Anthony Gallagos: In this regard, we've already signed two contracts for mid-fourth quarter reactivations 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 this time given the indecisiveness and lack of formal guidance from ENPs regarding their 2024 upstream capex plants.

Another step down so youre still seeing pricing pressure, you're agreeing to short term deals, but how differentiated is the pressure coming on pricing.

Rigs back to work how much concessions you're 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 it.

As Phil noted in his comments, we don't have a lot of backlog.

Anthony Gallagos: With respect to 200-300 series conversions, we completed two additional 200-300 series conversions during the third quarter, and last week, completed an additional conversion supported by a signed contract that more than guarantees whole 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 of this means that about three quarters of the 17-18 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.

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 wear skirt current spot market rates are.

Point out that the <unk>.

Most important metric when we talk about this as margin per day.

And the things that the team is doing around added services and stuff like that is going to be additive to our margin per day.

That's what we focus 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 isn't as you don't feel it as much as when that incremental demand begins to appear meaning you've bounced off bottom theres opportunities out there.

Anthony Gallagos: 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. Back in 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.

It always gets a little bit more competitive and that's where we are right now.

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.

Anthony Gallagos: 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 high torque-drought 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 that these offerings will continue to enhance our financial performance as I indicated to you during our last earnings call.

It's the smaller contractors that.

Tend to be a little bit more aggressive and kind of where we said it's kind of right there in the middle.

<unk>.

With a smaller fleet, we can be a little bit more patient you.

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 lot of focus around multi rig clients and making sure that we're.

Anthony Gallagos: 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.

Sure.

Got a lot of exposure on that Brian So when Philip talks about positioning with customers and stuff like that those are the drivers that he's referring to.

Okay, that's really helpful.

Philip Choyce: I'll make some additional concluding remarks before opening 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 with 5.2 million dollars for 37 cents per share and adjusted EBITDAW for $12.9 million.

As you try to crew up these rigs to go back to work.

Whats the labor, obviously, the rig count way down right now is it fairly easy to bring back crews and what type of cost is just because I know you're hitting 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.

Philip Choyce: In calculating adjusted EBITDAW and loss per share, we excluded $1.1 million associated with non-CATCHS-GNA charges during the quarter associated with the contract modification and extension. We operated 13.4 average rigs during the quarter, thought leading to low guidance provided on our prior conference call, because by greater than expected 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.

Our our people development group that team there 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 up cycle, where we see the added cost is we want to bring these people ask even industry experienced people and 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 theyre going to be new to our systems and processes. They are certainly going to be due to our culture and that's where we see the cost inefficiencies as we are beginning the expansion of our operating rig count.

Philip Choyce: 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 $14,500 on the low end of guidance representing a 9.4% sequential decline compared to the second quarter.

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

Thanks, Steve.

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

Hey, guys. Thanks for having me.

Morning, John just one question on the demand outlook when you.

I think you said, you're at 15 rigs today and I.

I guess I might characterize as hope at this point that you'll be at 21.

Philip Choyce: SGNA 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 up the components, cash SGNA expenses of $3.8 million were essentially flat compared to the second quarter. And non-cash based SGNA 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.

Middle of next year.

If.

And that that would be very impressive growth.

And I'm curious is this isolated to two or three of your maybe customers you've worked with in the past, they're just coming back like because I think you can just walk us through that percent increase relative to what the broader market might do again I know its total speculation right now.

No.

Fully anticipated that question, John I think the.

Consensus out there is we should see 40 to 70 rigs go.

Philip Choyce: Interest expense during the quarter aggregated $9.10 million, this included $2.4 million associated with non-cash amortization, deferred issuance costs and debt discount, which we excluded from presenting adjusted debt income. Tax benefits for the quarter were diminishing and in line with guidance. During the quarter, cash payments for capital expenditures and have disposals who are 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 complete to additional 200, 300 series reactivations and purchases of additional strings of trope pipe.

Go back to work over the course of 2024.

We're I'm very confident that we're going to end this year with 17 con.

Contracted.

Its probably 18.

So to get back to the 21 there is another three.

Our board 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.

Paul.

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 are they.

At the same group of customer that really started to pull back a year ago.

Philip Choyce: Moving on to our balance sheet, we continue to make progress towards debt reduction goals. We paid $5 million with convertible notes at par, a 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. $2 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.

You've seen the percent of rig count working for privates continued to decline I think that starts to go the other way.

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 is a lot of money being raised private equity money being raised to be deployed.

Philip Choyce: 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 related to lower day rates on contract renewals, slightly higher cost per day levels, 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.

Among E&P companies and that's very important because if you think about the business over the last 20 or 30 years Emma.

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 in the last three or 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.

Philip Choyce: We also expect sequential cost efficiency during the quarter, the CSA, with contract reactivations, with cost 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. Unless we believe the fourth quarter provides a regional estimation of the current spot day rate environment during the initial stages of the expected recovery in U.S, land rate count.

And I think that growth is going to happen primarily in the south also so think Permian, obviously think Eagle Ford.

And think Haynesville 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 its never a layout, but I feel pretty good about our chances there.

Okay, well, that's all I had I I am hoping that you are correct you my friend.

Philip Choyce: Given only three of our current rate contracts extend past the first quarter of next year, and then beyond the second quarter of next year, we believe we have positioned IT to participate in a day rate recovery driven by expected growth in U.S, rate count of the third quarter bottom. Unumsorbed overhead expenses are expected to be about $600,000. We've excluded those expenses from our cost per day guidance. We do expect incur a rig reactivation expenses during the fourth quarter associated with a re-higher increase in replenishment of operating supplies for the rig additions to our operating fleet during the fourth quarter, and early 2024.

Great. Thank you John.

The next question comes from Dave strong with Stonegate. Please go ahead.

Good morning.

Good morning.

Good morning, just wanted to start.

Got a lot of new contracts coming up you know that seems structural and strategic.

Wanted 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 going to be mostly a great pressure terms added services just would love to hear your thoughts around that.

How do you think the negotiating table is going to be.

Yes, I think it's going to start with.

Philip Choyce: 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 SGNA expense to be approximately $4 million. Stock-based compensation expenses 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, or relate to not cash armorization to deferred financing costs and debt discounts. Appreciation expense for the fourth quarter is expected to be flat with the third quarter, and we expect tax benefits to be diminished during the fourth quarter.

As 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 are 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 U S shale today in the maturation that's occurring so I think it starts with what what's your rigs capability, obviously, they want to understand your performance that start as always with Hs knee 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.

Anthony Gallagos: And with that, I will turn the call back over to Anthony. Thanks, Philip. So wrapping all of this up, we believe ICD is very well positioned as we exit this most recent slowdown.

Anthony Gallagos: In fact, I feel this is the strongest ICD's 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 all directed markets based on recently increased commodity prices, current customer victories 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 don't have to be converted to 300 series. There 200 series rigs today in fact, we're in some 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 at a reasonable day rate without having to invest the capital and kind of a punt that upgrade.

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.

The capability around your Reagan your rig specification and that's why you've heard us pounding the table.

Anthony Gallagos: 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 Recharge D&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 to coming course.

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 back in our investors should be pleased to know and we've got a very obvious and relatively easy and relatively cost.

Operator: With that, we'll open up the call for questions.

That gave way pathway toward gaining more of that exposure.

Operator: We will now begin the question and answer session. To ask a question, you may press star then one on your touchtone phone. If you are using a speaker phone, please pick up your handset before pressing the keys.

Understood that's very helpful.

If I could with all of the new tech initiatives that you've been rolling out is there any difference in capabilities between the 203 hundred series rig.

Operator: 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 the sample or roster.

Kind of tech that can operate there or is it.

Pretty homogenous.

Not on the software side things such as back to bottom sequencing, the oscillation and stick slip mitigation.

Donald Crist: The first question today comes from Don Christ with Johnson Rice. Please go ahead. Good morning, guys. Anthony, obviously you walked through the demand picture out there, but can we get a little bit more color on particularly in the Haynesville? You know, obviously you had a bunch of rigs run in 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?

That is deployed on both our 203 hundred series rig where you might see where you will see a difference is in the high torque capability. So think about the high torque drill strings.

The longer laterals, the higher torque top drives.

We need to be able to put all of that torque at at the end of the three mile lateral that's where you see the difference and that also is what drive that day rate differential that we talked about earlier in the call you know anywhere from 2000 and $3000 a day.

Donald Crist: Sure, Don. Thanks for the question. You're right. A lot of what happened to IECD 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, which was ten rigs working in the Haynesville. Half of that ten was with one customer who went from five rigs to zero. So, you know, that played out for us over the second and the third quarter.

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

Thank you Doug.

The next question comes from Jeff Robertson with Watertown 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 'twenty four.

How does that play into your thoughts around being able to re market 300 series rigs and contract duration for those.

Donald Crist: You know, we bought them now at two rigs operating over their three rigs contracted. As commodity prices in rehab has improved, as some of the takeaway 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 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.

Both in the Permian and in the Haynesville as you look to try to be in a position to maximize EBITDA looking into 2025. When you are trying to.

Consider doing something with the notes.

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 'twenty or 'twenty, one rigs running.

Donald Crist: Well, that's good for our industry. For us, you know, a prior customer virus has started back up. You know, 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 little about technology so 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.

Day rates are a bit softer than any of us would like we've 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 and the way that we did in the last up cycle so that.

We're in the best position possible and to be able to evaluated many alternatives as there are available to address.

Donald Crist: You know, better RP, the same or better whole quality stuff like that. In addition to that, you know, 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 into perspective, that means the four rigs that we still have in the base and all four will be contracted by the end of the year. But we don't have that fourth contract signed, but I'm pretty confident it's going to come.

The debt will come due in 2026 long way off but as you know it.

You've gotta be taken measures today to be able to make sure you put the company in the best position possible.

To address that.

That's how we think I mentioned.

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

Donald Crist: 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, you know, the conditions around the contract are better than what we think we can do in the Permian. But, you know, as we think about that market longer term. You know, 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.

Uh huh.

They used 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.

Donald Crist: You know, 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 base and work into 3839 today. Hasn't been a lot of capacity move out. We probably move more out 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.

It already has a high torque top drive on it so it has that and we can put the.

The iron Roughneck the tool on it we just need to make sure we understand the pathway.

Towards the mast and substructure upgrades and the way that we.

Completed that upgrade on the other two hundreds, but it's 90, it's upwards of 90% and yes. There is a path. There there is a scenario where theyre all at a 100%, but look if we can contract our 200 series rigs without having to make that investment and generate what we think are appropriate returns there.

Donald Crist: Even against the backdrop of, you know, recharge budgets, capital budgets for 2024. But that, 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 EMP customers in the hands bowl. 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.

Wouldn't be a need to do that so there's not a hard and fast rule nobody 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 in U S shale that that's where things are going.

Thanks for taking my questions.

Mr. Jeff Thank you.

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

Donald Crist: So, you know, 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.

Thanks for letting me back end guys. Anthony I wanted to kind of ask a more kind of macro question in a fully admit that this may not have a direct answer but.

As you look at the market today and.

And kind of survey the guys, who were kind of depressing prices on the private side.

Anthony Gallagos: But that's what I would say about the hands bowl market. I appreciate that color. And to talk a little bit on the 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 serious 200 to 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.

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 <unk> level.

Given that the larger companies have upheld pricing as well as they have.

Yeah, I don't think it's as much as people think Dan and the reason is think about how much.

The requirements from our customers had changed since Covid right. The laterals certainly are getting longer.

M&A.

That's happening around us is theres 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.

Anthony Gallagos: Obviously, we want to make the return on that too, but just given the volatility, the quality of the business, it's very, very important that in a minimum, we get that cash back. You know, what we've said in the past, and it's holding out to be true, it's kind of two 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, and we did two and the third quarter, and we just finished another one.

On and on and on and when you survey.

The smaller <unk>.

Contractors.

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.

Anthony Gallagos: In fact, that rig started moving yesterday. Three of the four have been with customers that had the 200 series rig running first. And, you know, 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 that they are super spec pat off the rigs. They go toe to toe with everything that's out there. But the reason I'm pointing this out is three of the four have gone to customers that used the 200 series rigs.

So you read into that what you've all but certainly the smaller con.

Contractors that are out there.

There's there's not as many of those types of Briggs and those fleets in fact for a couple of them. They are essentially 100% utilized today among what we would consider to be 300 like.

Type rigs so what you've just described is what we think are I think is going to happen that.

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.

Anthony Gallagos: They were very, very pleased with the 200 series rigs. And they'd 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? A couple hundred thousand, right?

He is going to set the fairway for the big three two to come in and.

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.

Anthony Gallagos: That was 650 to 800 thousand dollars. Okay. But you're getting cash on cash payback over the contract term on this, right? Yes. Okay. I appreciate it. I'll get back in key. Thanks. All right. Thank you, Doc.

I appreciate the color. Thanks, a lot guys.

Yes for now thanks.

The next question comes from <expletive> Ryan with Oak Ridge. Please go ahead.

Thank you say Anthony on your ICD impact.

How many of those systems are do you currently have deployed I know you had expectations that you could generate some incremental margins.

Stephen Ferazani: The next question comes from Steve Feranzi with Sedoli. Please go ahead. Afternoon, everyone. Appreciate the detail in the call. I just want to get a lot of numbers. I just want to connect some of the docs, based on your guidance. How many rigs did you have at the end of 3Q and how much do you have? How many rigs are drilling right now? We had 14 rigs drilling at the end of the quarter.

Are you seeing any of that yet or are these.

It kind of still on a trial basis.

Yes, it's really a mixture so we have it.

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.

Stephen Ferazani: 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 finished programs a little bit early. Is that sort of you just being a little bit conservative assuming year-end white space? 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 so there's a little bit of white space.

Certainly when we provided equipment.

Other it be the.

The biofuel dual fuel capability of the rig or the ability to plug in the utility grid or the.

Our high torque drill strings that we provided we are getting paid for all of those added at an appropriate rate that justifies the investment and.

And earns an incremental return.

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 for any of these kind of things that we're providing right now it is somewhat of a mixture. It is 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.

Stephen Ferazani: But there's not any white space at the end of the, we would expect those all those 16 rigs will continue into next year. But the rollout, they're biased, more sure the back ones. Yeah, they're biased in the back end. Yeah. Okay, okay.

Being able to demonstrate quantify where values being added to them.

Stephen Ferazani: As far as the day rate trends obviously got, it held up for a while. 2, 3 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 questions, Steve. I don't think that's isolated to ICD.

But our expectation would be like I said, we are not just earning incremental day rate, 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.

Overtime.

Okay is this a differentiator as you're talking to customers going into 'twenty for maybe some of the smaller competitors are cutting prices. That's a differentiator for you guys.

Yes. It is.

Stephen Ferazani: 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. It gives us added exposure to where current spot market rates are. Yeah, I'd point out that, you know, the most important metric when we talk about this is margin per day.

I appreciate you asking that debt because I should have pointed out earlier. It is it just one more way I think that we stand out.

What people would consider to be the smaller drilling contractors right.

The goal with ICD is look I think we've got the best rates 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.

Stephen Ferazani: And the things that the team's doing around added services and stuff like that is going to be added into margin per day. That's what we focus 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 isn't as, you don't feel it as much as when that incremental demand begins to appear meaning you bounced off bottom.

Is anyone else that's out there and that's the pathway that wrong, 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.

This stuff finally, getting deployed being be adoption with being able to walk into customers off some show where values being created.

Sure.

Great. Thank you Anthony.

Alright, Thank you <expletive>.

Stephen Ferazani: There's opportunities out there. It always gets a little bit more competitive and that's where we are right now. Yeah, 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 said is kind of right there in the middle, and, you know, with a smaller fleet, we can be a little bit more patient.

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 and I would like to say thank you very much to all the employees of ICD hard work their dedication their sacrifice, we really appreciate that but thank you everybody for dialing into today's call. We appreciate you making time.

Well in the call from here.

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

Stephen Ferazani: 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 counterpart who the ENP company is. A lot of focus around multi-reg clients and making sure that we've 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.

Yes.

[music].

Anthony Gallagos: Okay, that's really helpful. As you try to crew up these rigs, take a back to work. What's the labor? Obviously, the rig can't weigh down right now. Is it fairly easy to bring back crews and what type of costs? Is it because I know your cost-properating gate 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 and bringing some really good talent into the company.

Anthony Gallagos: 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 and even industry experience 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.

Anthony Gallagos: They're certainly going to be new to our culture. And that's where we see the cost and efficiencies as we're beginning the expansion of our operating rig count. Okay, that makes a lot of sense. Thanks, Anthony. Thanks, Philip.

Anthony Gallagos: Thanks, Dave.

John Daniel: 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 when you, I think you say you're 15 rigs today and the, I guess my care crisis is hope at this point that you'll be at 21 in the middle of next year. If 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 because I think he just walk us through that percent increase relative to what the broader market might do.

John Daniel: Again, I know it's total speculation right now because you're looking at that. I fully anticipated that question. John, I think the consensus out there is we should see 40 to 70 rigs. Yeah, go back to work over the course of 2024. We're, I'm very confident that we're going to end this year with 17 contract. I think it's probably 18. So to get back to the 21 there's another three or four that, you know, so, you know, you take the three or four and you compare that to the 40 to 70 that that would imply that we would be punching up of our weight.

John Daniel: We certainly did that in the last that 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 more biased toward privates. They, you know, they, that's the same group of customer that, you know, really started to pull back a year ago. You know, you've seen the percent of red count working for privates continue to decline.

John Daniel: 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 EMP side, not on the services side. And he shared something with me 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 EMP 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.

John Daniel: 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 NP companies. And I think that growth is going to happen primarily in the South also.

John Daniel: So think Permian, obviously, thank Eagleford, and think April. 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 our cancer there.

John Daniel: Okay. Well, that's all I had. I am hoping that you are correct, my friends. Great.

David Storms: Thank you, John. The next question comes from Dave Storms with Stonegate. Please go ahead.

Anthony Gallagos: Good morning. Good morning, Dave. Good morning. Just want to start. You got a lot of new contracts coming up. Yeah, that seems structural and strategic. Just want to get your sense on where you think the big sticking points are going to be on. And those contracts are with the finish line. It's going to be, you know, the payback provisions is going to be mostly great pressure terms added services. Just would love to hear your thoughts around where you think the negotiating table is going to be.

Anthony Gallagos: Yeah, I think it's going to start with, you know, your rig capable. And that, you know, 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. You know, 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, what's your rig capability?

Anthony Gallagos: Obviously, they want to understand your performance. That starts always with HS&E safety, but, but also just operational performance. You know, 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.

Anthony Gallagos: 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 based on 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 capability around your rig and your rig specification.

Anthony Gallagos: And that's why you've heard us pounding the table. You know, really over the last year, you're in half about the need to continue to have more exposure to the 300 series market because we think about where things are going in US shale. Well, it's going to be the 300 series back. And you know, our investors should be pleased to know. And we've got a very obvious and relatively easy and relatively cost effective way, halfway for gaining more of that exposure. Under so that's very helpful.

Anthony Gallagos: 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 only on the software side, things such as, you know, back to bottom sequencing the the oscillation is still slip mitigation that that is deployed on both our 200 and 300 series rig where you might see where you will see a difference is in the high torque capability.

Anthony Gallagos: So, think about the high torque drill strings certainly the longer laterals, the hard torque top drives that that we need to be able to put all that torque at, you know, 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, you know, anywhere from $2,000 to $3,000 a day. That's perfect.

Operator: Thank you for taking my questions and good luck on the fourth floor.

Operator: Thank you, Jack.

Jeffrey Robertson: 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 remark it 300 series rigs and contract duration for those. Both in the Permian and in the Haynesville as you look to try to be in a position to maximize EBITDAB looking into 2025 when you're trying to consider doing something with the notes.

Jeffrey Robertson: 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 that we want to go relatively short and keep them short so that as we approach what we think will be more demand for SuperSpec rigs in the back half of 2024 throughout 2025.

Jeffrey Robertson: 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, you know, 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.

Jeffrey Robertson: That's how we knew mentioned. Thanks. You mentioned, I believe that year end 2023 that 75% of the fleet working will be, we'll have 300 serious capability. If you skip forward to the fourth quarter of 24, is there a case where you 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.

Jeffrey Robertson: It already has a high torque top drive on it. So it has that. We can put the Iron Roughnack tool on it. We just need to make sure we understand the pathway toward the mass and substructure upgrades and in the way that we completed that upgrade on the other 200s. But it's 90, it's upwards of 90%. And yes, there is a path. There is a scenario where they're all at 100%. But look, if we can contract our 200 series rigs without having to make that investment and generate what we think are appropriate returns.

Jeffrey Robertson: There wouldn't be a need to do that. So there's not a hard and fast rule. Nobody, 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 in U.S. Shale, that's where things are.

Jeffrey Robertson: Thank you for taking my questions. Mr. Jeff, thank you.

Donald Crist: The next question comes from Don Chris with Johnson Rice. Please go ahead. Thanks for letting you back in guys.

Donald Crist: Anthony, I wanted to kind of ask a more kind of macro question and I'll 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 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 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?

Donald Crist: The 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 as 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 but certainly of the smaller contractors that are out there there's there's not as many of those types of rigs in those fleets in fact for a couple of them they're essentially a hundred percent 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 you know 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 to come in and and do what they do because they're going to have at that time what will be remaining big rig capacity so yes that that is part of the thesis and how we see this playing out over the next 12 to 18 months I appreciate the color thanks a lot guys if not thanks the next question comes from Decrine with Oak Ridge please go ahead thank you say Anthony on your ICD impact how many of those systems are do you currently have deployed I know you had expectations that you know 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 it's 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 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 the bifurcule capability of the rig or the ability to plug in the utility grid or the high 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 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 for any of these kind of things that we're providing right now it is 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 and most importantly being able to demonstrate quantify where values being added to them and but our expectation would be like said we're we're we're we're not just earning incremental day rate for it but actually earning incremental margin and and while we're doing that on some of them today the expectation would be able to do that on all of them over time Okay. Is this 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?

Donald Crist: Yes, it is. I appreciate you asking that, 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 goal with ICD 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.

Donald Crist: 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, being the adoption, but being able to walk into customers off some show where values being created. Great. Thank you. All right.

Dick: Thank you, Dick.

Anthony Gallagos: This concludes our question and answer session. I would like to turn the conference back over to Anthony Gallagos for any closing remarks. We share appreciate everyone dialing in. I would like to say thank you very much to all the employees of ICD, hard work, their dedication, their sacrifice. We really appreciate that, but thank you everybody for dialing in today's call. We appreciate you making time.

Operator: We'll end the call from here.

Operator: The conference is now concluded. Thank you for attending today's presentation.

Operator: You may now disconnect. Thank you very much.