Independence Contract Drilling, Inc. (NYSE:ICD) Q4 2022 Earnings Call Transcript

Independence Contract Drilling, Inc. (NYSE:ICD) Q4 2022 Earnings Call Transcript March 2, 2023

Operator: Hello and welcome to the Independence Contract Drilling Inc. Fourth Quarter and Year End 2022 Financial Results Conference Call. Please note this event is being recorded. I would now like to turn the conference over to Philip Choyce, Executive Vice President and Chief Financial Officer. Please go ahead.

Philip Choyce: Good morning, everyone and thank you for joining us today to discuss ICD’s fourth quarter 2022 results. With me today is Anthony Gallegos, our President and Chief Executive Officer. Before we begin, I would like to remind all participants that our comments today will include forward-looking statements, which are subject to certain risks and uncertainties. A number of factors and uncertainties could cause actual results in future periods to differ materially from what we talk about today. For a complete discussion of these risks, we encourage you to read the company’s earnings release and our documents on file with the SEC. In addition, we refer to non-GAAP measures during the call. Please refer to the earnings release and our public filings for a full reconciliation of net income and loss to adjusted net income and loss, EBITDA and adjusted EBITDA and for definitions of our non-GAAP measures.

And with that, I will turn it over to Anthony for opening remarks.

Anthony Gallegos: Hello, everyone. Thank you for joining us for our fourth quarter earnings conference call. And during my prepared remarks today, I want to talk about three things. First, I want to highlight our 2022 accomplishments. Second, I want to describe the current market for super-spec, pad-optimal rigs and how that will impact ICD. And third, I want to close out with what we are focused on as we navigate 2023 and beyond. But first just a few comments on the quarter. Overall, ICD’s fourth quarter results came in well ahead of expectations in terms of revenues, margins and adjusted EBITDA. Phillip will go through the detail, but I want to point out that our reported revenue per day, margin per day and quarterly adjusted EBITDA were all again records for ICD.

This is the second quarter in a row we have produced record results. In addition, as the full year 2022 played out, we saw adjusted EBITDA increase by more than 5x measuring fourth quarter to the fourth quarter of last year. And we are well positioned so that 2023 will be the best year by wide margin in ICD’s history, whether it’s revenue per day, margin per day or overall free cash flow. As we closed out last year, we achieved additional strategic goals. In addition to generating rig margin per day exceeding most of our industry peers, we ended the year with 20 rigs operating, activated 2 additional rigs during the fourth quarter. Both of those rigs went to work in the Haynesville on very good contracts. In addition, we successfully completed our first 200 to 300 series conversion, involving a rig working for a customer in West Texas, proving that our 200 to 300 series conversions are technically and commercially viable, it was very important for us as we can now market 100% of our marketed fleet with 300 series specification if the market pulls us that way.

On the operational safety front, our safety performance based upon reported TRIR was over 20% better than the U.S. land average as reported by the International Association of Drilling Contractors. We accomplished so much in 2022 and I am very proud of how our operations and support teams continue to deliver high levels of customer service, performance and professionalism, which our customers expect from ICD. This is especially noteworthy given the unprecedented challenges involving the labor market and supply chain challenges, which continue to plague the global business community and more recently, the softness in natural gas prices. Looking ahead, we are finalizing the reactivation of our 21st rig in our Odessa, Texas yard, which is another 300 series rig.

This reactivation project was started back in October of last year and will be our last reactivation for a while. Like our other 300 series rigs, this rig possesses the technical capabilities that our target customers prefer today. We are in final contract negotiations for this rig and expect the rig will be mobilized into its maiden contract involving work in West Texas during the second quarter. All-in-all, ICD entered 2023 in a very strong position, whether from a margin per day and cash flow generation perspective or a fleet composition perspective where we have materially increased the percentage of rigs marketed with our 300 series specification. ICD has never been stronger. All of the hard work we have put into positioning ICD while bouncing off the pandemic bottom will be on full display as we navigate the New Year.

And with that, I want to shift to our current market perspective. And in particular, what’s on everyone’s mind, what the softness in natural gas prices means for ICD strategically in 2023. First, let me address the overall market and outlook for rig activity for pad-optimal super-spec rigs in our target markets of Texas in the contiguous states. Overall, demand for pad-optimal super-spec rigs remains strong. Today, overall utilization remains above 90% in the industry and we expect continued improvement in our rig margin per day in the first quarter driven by contract rollovers as we reprice rigs contracted early last year. Phillip will provide more detailed guidance, but I wanted to highlight that we currently expect our margin per day to increase to between $15,000 and $15,500 per day in the first quarter ahead of our prior guidance for that quarter.

However, the sharp decline in natural gas prices during the past 4 months has created a disparity between our two primary operating basins. In the Permian, which is all directed activity, demand remains robust and we are expecting an overall uptick in the super-spec rig count in that basin in 2023. In terms of our Haynesville market, which is tied to natural gas commodity prices, we are seeing softness in the Haynesville rig market driven by the E&P’s response to Henry Hub natural gas prices, which have declined from $9.68 on August 22 to $2.12 per million Btu last week. As we are nearing the end of winter and gas inventory levels remain high on a historical basis, combined with takeaway constraints in the Haynesville, the outlook for natural gas prices to remain softer, longer.

With that market backdrop, we see two primary impacts on ICD. First, the overall Haynesville directed rig counts going to decline. We have one customer in particular who has informed us that they will be moving to zero operating rigs. Several current prior and prospective customers in the Haynesville are also terming their active rig plates. The impact to ICD’s Haynesville fleet will include some rig relocations to West Texas, which have already commenced. Right now, we are confident that we will need to relocate 5 to 6 rigs, which will take place primarily during the second and third quarters of this year. The process has already started with 1 rig relocating without any operational whitespace. And I would be remiss if I didn’t point out that we received a day rate increase in the process.

We are in the final contract negotiations for our second relocation, which will also occur with minimal whitespace and a day rate increase. We believe market demand and strength in the Permian for pad-optimal super-spec rigs as well as our customer base is strong enough to absorb rig additions to the basin. We are already seeing some lower spec rigs gets displaced as a result of the churn underway. Also rigs brought from the Haynesville into the Permian will actually absorb rig count growth opportunities previously reserved for rig reactivations. In this environment, we expect overall rig reactivations to slow considerably or even stop until this overall rebalancing process is complete and the market is settled. Thus, we have elected to defer the reactivation of what would be our 22nd rig.

Overall, during this process, we expect the overall super-spec rig market to remain robust and maintain current utilization levels, which are above 90% utilization. As we have mentioned on prior calls, 80% utilization or above is typically where drilling contractors were able to maintain and increase pricing. But over the next two quarters or so, there is going to be some choppiness as we reshuffle the deck as a result of what’s happening in the Haynesville, I expect there will be more rig on rig competition where rig additions are occurring or a rig replacement opportunity exists. This will have some impact on pricing. Principally, we would expect the pace of day rate margin acceleration to moderate. So as we move past the first quarter and all of the rigs have repriced to current market day rates, I expect day rate and margin improvement to flatten out for ICD after the first quarter.

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Phillip will provide more financial details on our outlook, but overall, it means we will likely move sideways after the first quarter for a quarter or two until the market is rebalanced following rigs transitioning between basins. We remain optimistic about market momentum beginning to accelerate again towards the back part of this year, primarily in the Permian based upon our expectation that WTI will be higher in the back half of 2023. From a rig utilization perspective, while we relocate rigs to the Permian, we are not expecting a major reduction in our overall utilization rate. We will have some rigs in transit, but we do expect to reach full effective utilization of our 21 rigs operating in the fourth quarter or by year end. Overall, we would expect to operate in the neighborhood of 19 to 20 average rigs during this year, taking into account the transition time that might occur on rig relocations during the second and third quarter.

Phillip will go through more of the details, but financially our backlog of contracts in the Haynesville will mute much of the potential financial impacts, while rigs are transitioning. So how will all this impact ICD this year and strategically? Overall, we do not expect it will have a material overall impact other than to postpone rig reactivations. All of ICD’s strategic and financial goals regarding generating significant free cash flow and reducing overall leverage remain intact. As Phillip will discuss, we still expect 2023 to be a record year for ICD from a revenue per day, margin per day, EBITDA and free cash flow perspective. In fact, in the near-term as we slow our capital investments and additional rig reactivations, our free cash flow and net debt reduction plans will accelerate as we improve our working capital position by putting some cash on the balance sheet.

Strategically, we remain very focused on creating a pathway towards steadily decreasing our net debt position as we move towards the refinancing window for our convertible notes. One of our long-term goals is to reduce our net debt to adjusted EBITDA ratio meaningfully towards the range of less than 1x to 1.5x during the refinancing window involving our convertible notes. For reference, we are currently at 2.5x levered on an annualized basis using our fourth quarter results. And based upon the market expectation I just described, we expect to exit 2023 around 2x or below utilizing the same metric. So, while we have some work to do in this regard, everything is in place for ICD to achieve its short and long-term financial and strategic goals.

I will make some additional concluding remarks. But right now, I want to turn the call over to Phillip to discuss our financial results and outlook in a little more detail.

Philip Choyce: Thanks, Anthony. We were essentially breakeven from a profitability standpoint in the fourth quarter. During the quarter, we reported an adjusted net loss of $87,000 or $0.01 per share and adjusted EBITDA of $18.5 million. Reported adjusted EBITDA increased sequentially 48% compared to the third quarter of €˜23. Adjusted net loss and income excludes the impact of a tax benefit recognized during the fourth quarter following completion of our analysis regarding the deductibility of interest expense under our convertible notes. We operated 18.5 average rigs during the quarter, representing a 6% increase compared to the third quarter. Anthony previously mentioned our fourth quarter revenue and margin per day were quarterly records for ICD.

Revenue per day of $32,778 represented a 14% increase compared to the third quarter and margin per day of $14,517 represented a 28% sequential increase compared to the third quarter metrics. SG&A costs were $7.7 million, which included approximately $1.9 million of stock-based and deferred compensation expense. Sequential increases in cash SG&A over the third quarter were driven by higher incentive compensation accruals based upon improvements in the company’s safety, operational and financial performance compared to performance goals. Interest expense during the quarter aggregated $8.6 million. This included $2.4 million associated with non-cash amortization of deferred issuance costs and debt discounts, which were excluded when presenting adjusted net income and loss.

During the quarter, cash payments for capital expenditures, net of disposals were approximately $18.8 million in this CapEx out approximately 79% related to rig reactivations and upgrades and 21% related to maintenance CapEx. Moving on to our balance sheet, adjusted net debt was $182.5 million at quarter end. This amount represents the face amount of our convertible notes and borrowings under our ABL and ignores the impacts from debt discounts, deferred financing costs and finance leases. I do want to point out that the adjusted net debt we reported this quarter also includes accrued interest at year end that we intend to pay in time when due in March of 2023. Our backlog at year end was $79.1 million, with an average day rate over $35,000 per day.

Our financial liquidity at quarter end was $26.6 million comprised of $5.3 million of cash on hand and $21.3 million available under our revolving credit facility. Now moving on to guidance for the first quarter and some items related to fiscal 2023. Let me start with the first quarter. We expect operating days to approximate 1,715 days, representing approximately 19 average rigs working during the quarter, reflecting some rigs beginning to transition from the Haynesville to the Permian. Our 21st rig is not expected to reactivate until the second quarter. We expect margin per day to come in between $15,500 per day as Anthony mentioned. We expect revenue per day to come in between $33,200 and $33,600 per day. Cost per day is expected to range between $18,100 and $18,400 per day.

Unabsorbed overhead expenses will be about $600,000 and are not included in our cost per day guidance. We also estimate approximately $800,000 of transition expenses associated with rig relocations to the Permian, principally related to crew carrying costs during the transition period and unreimbursed transportation costs. We expect first quarter cash SG&A expense to be approximately $5.9 million and stock-based compensation expense is expected to be approximately $2 million on top of that. We expect interest expense to be approximately $8.8 million. Of this amount, approximately $2.4 million were related to non-cash amortization of deferred financing costs and debt discounts. Depreciation expense for the first quarter is expected to be $11 million.

As Anthony mentioned, we will be transitioning rigs from the Haynesville to the Permian. That process has already begun and we currently expect it to occur over the second and third quarters of 2023 with most movement during Q2. Although as Anthony mentioned, our first relocation occurred with minimal non-operating days. There could be some transitional time between contracts. Although we will look to minimize these periods, it is dependent on the timing of our Permian customers drilling programs. So, our internal planning processes are budgeting that we generate revenue on approximately 17, 18 average rigs during the second quarter, approximately 19 to 20 rigs in the third quarter, and then we resumed full effective utilization of our 21 reactivated rigs in the fourth quarter by year end.

We will incur transitional costs associated with relocating the rigs, expect to maintain crews due to the brevity of this transition period. We currently estimate total transition cost associated with this exercise to be approximately $3 million to $4 million, with the majority of it occurring during the second quarter of 2023. And moving on to guidance relating to fiscal 2023 as a whole, overall, our SG&A budget for 2023 is $27 million comprised of $18.5 million of cash SG&A and $8.5 million of stock-based and deferred compensation expense. There is a component of stock-based compensation that is variable and tied to the value of our common stock for accounting purposes. So, it will be some variability in that metric based on changes in our stock price at the end of each reporting period during the year.

Capital budget for 2023 is $30,400,000 net of disposals. It does not assume that we reactivate our 22nd rig, which Anthony mentioned we have postponed. Breaking out our capital budget $4.5 million relates to the reactivation and upgrade costs principally associated with reactivation of our 21st rig, $21.5 million relates to maintenance CapEx and other matters, and $4.4 million relates to planned tubular purchases. For 2023, we expect our overall effective tax rate to be 20% although we do not expect to be cash federal tax income there. For weighted average shares outstanding in periods of net income, our fully diluted shares outstanding will include the shares associated with assumed full conversion of the convertible notes. And with that, I will turn the call back over to Anthony.

Anthony Gallegos: Thanks, Phillip. Before opening the call up for questions, I want to briefly summarize ICD’s strategic positioning and what I think it all means for ICD’s stockholders. Last year, we significantly transformed our company and positioning. In terms of our positioning, I think about three important facts. First, our utilization and margin growth coming out of the pandemic has been best in class. This speaks to the quality of our people, our assets and our performance. Also, today, our daily rig margins are the best in ICD’s history and are on par with and exceeding some of our larger company peers as we continue to earn recognition from our customers for industry leading customer service and professionalism. The company has never performed better.

Second, we have the youngest and we believe the best-in-class rig fleet. The market for pad-optimal super-spec rigs remains strong outside of the gas driven basis. We continue to demonstrate our fiscal discipline by securing contracts that earn full simple payback on the reactivation CapEx we are investing and by deferring further investments in additional reactivations beyond the 21st rig, which will come out early this year until this market settles out. And finally, we have substantially improved our liquidity and balance sheet and expect meaningful improvements and leverage ratios and other debt metrics as we move through 2023 and beyond. Although softness in gas markets will impact the pace of rig reactivations and will require us to reposition some rigs, ICD has never been in a better position to navigate these types of short-term challenges.

Our operational strength and reputation with our customers has never been stronger. Our fleet which has been transformed by the market penetration of our 300 series rigs and our ability to market and complete 200 to 300 series conversions has never been more valuable. From a revenue per day, margin per day, EBITDA and free cash flow perspective, the outlook for ICD to improve those metrics in 2023 is intact and in many ways will accelerate. To summing all this up, ICD checks all the boxes, whether you are looking for best-in-class assets, leading rig margins or an outstanding customer base in rigs focused on the most important oil and gas shale plays in U.S. and conventional, ICD delivers on those metrics. With all this in place, we are poised to generate meaningful free cash flow during 2023, which we believe will work toward closing the stock valuation gap between ICD and our peers as we continue to execute upon ICD’s strategic initiatives.

With that, operator, let’s go ahead and open up the line for questions.

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Q&A Session

Operator: Thank you. Today’s first question comes from Don Crist with Johnson Rice. Please go ahead.

Don Crist: Good morning, gentlemen. How are you all this morning?

Philip Choyce: Good, Don.

Anthony Gallegos: Good morning, Don.

Don Crist: Anthony, I wanted to start with obviously the macro is very topical these days. And it’s the contention amongst analysts and the investor community that the rig count is going to get a little bit weak towards the summer possibly, but then increase as we go into the fall. And the genesis of my question is what do we look like in 2024? We all think that it’s going to be weak in €˜23. But if gas directed drilling comes back to a similar level to where it is today. Could we find ourselves in a rig shortage opportunity there and potential for higher day rates as we go into €˜24 as that Haynesville or gas directed drilling increases?

Anthony Gallegos: Yes, Don. That’s exactly what we see over the next 12 to 24 months, where €“ on a geographic basis, where you will likely see a rig count decline is in the Haynesville. And listen, I am talking about our target markets of Texas and the contiguous states. Based on our conversation, certainly, the negotiations that we have been in the last couple of months, we see the Permian relatively flat here in the first half of the year. What’s interesting is when we talk to customers about the back half of the year and rolling into 2024 most of them are talking to us about incremental adds. In the short-term, there is some high-grade opportunities where some lower spec rigs are getting changed out. And then there is a tranche of E&Ps that maybe haven’t been busy that are picking up rigs and that’s where we are finding opportunities today.

I am encouraged by the fact that we are not having to take a deep discount in day rate to be able to place those rigs. One other anecdote I’d share with you is even in the Haynesville, this is true when we talk to our customers who maybe reducing activity levels, they are working very, very hard to make sure that they keep their people. And that’s a pretty strong signal to me that they expect activity to pickup maybe a little sooner than the overall market maybe expecting. So no, I think it’s a relatively flattish type rig count in the first half of the year beginning Q3, Q4, I begin €“ I think it begins to tick up. We all know how tight it was in the fourth quarter of last year. And I think that’s the environment that we are back in probably sooner than people realize.

Don Crist: And you touched on it in the comments a second ago can you just talk about pricing? We have heard a couple of anecdotes of E&Ps €“ larger E&Ps that are operating multiple rigs kind of going back to operators and securing 5% or 10% discounts, but that still equates to 50% margins. Are you seeing any kind of haggling there on price?

Anthony Gallegos: Haven’t had any customers come to us and ask for a day rate reduction. We had positioned quite a few of our rigs and especially the rigs in the Haynesville to rollover here in the second quarter anyway, which was going to give us an opportunity to increase rates a little more. Just to give you some a feel for what we are seeing day rates are maybe there are 1,000, 2,000 a day less than we would have thought they would be at this time of the year compared to if I €“ when I answered that question, the last time we had a call, not a disaster by any means. As you said, margins are still very, very strong. Phillip just provided some guidance on what we see here in the first quarter and even in the quarters beyond in terms of it being relatively flattish.

So I think one thing, Don, that probably isn’t appreciated as much as it should is the benefits that the super-spec rig fleet provides our customers. I was at a dinner last week here in Houston and was talking with a CEO of an E&P company. Of course, I am in sales mode, right. I am always in sales mode. And he is telling me that he has taken advantage of an opportunity to pickup a couple of super-spec rigs and replace some lower-spec AC rigs that he had running. And the comment he made was already on the first pad, they are seeing the benefits of the super-spec equipment. And I’d point out for our investors that, that’s 100% of our fleet super-spec pad-optimal. And when I think about rigs moving into the Haynesville, of course, we are going to move a few in, we have talked about that.

We really think it’s the SCR rigs that are running and the lower-spec AC rigs that are running that’s going to bear the brunt of the flattish rig count with the increasing supply. And I’d close with this comment, Don and you know this, remember how small the rig cost is and the total cost of a well. So day rate since €“ I mean, look, our customers have to do their job and make sure they are spending money wisely. But when you look at the typical Permian well, a 15-day well, that cost $6 million to $8 million, the rig is less than 10% of that. So I would question just how sensitive they will be or how sensitive the day rates will be to the overall economics of what they are doing.

Don Crist: I appreciate all the color. I will jump back in queue. Thanks.

Anthony Gallegos: Yes, sure. Thanks, Don.

Operator: The next question comes from Steve Ferazani with Sidoti. Please go ahead.

Steve Ferazani: Good morning, everyone. Appreciate all the detail on the call this morning. A lot of data here. I do want to follow the previous questions in terms of your confidence level that you can get 5 of your Haynesville rigs into the Permian given there will be some competition there and is that your thinking that there is so many rigs, but can you replace drilling programs just you have a better rig or how are you thinking about that? It just seems challenging to think that many rigs can move over to the Permian at similar day rates.

Anthony Gallegos: Yes and thank you for the question, Steve. I do think we are going to be successful. In fact, 2 of the 5, 1 is already basin. And the second one we signed the contract this morning for. So it’s going to start moving next week. And when you compare what its day rate was and in the Haynesville to what it’s going to earn on the new contract, it’s an increase in day rates. So that’s 2 out of the 5 right there. We have got a couple more that are going to come to me here in the first part of the second quarter. Team is doing a great job. But look, it’s a function of having the right equipment, the super-spec pad-optimal equipment. It’s a function of the reputation that ICD has in both basins. We are very concentrated in terms of our target market.

I think everybody knows that. The Permian and Haynesville are home markets for us. Yes, we have worked in Eagle Ford. Yes, we’ve worked in other in the Chalk. But these two basins are home for us where we have a very strong reputation. And as you know, Steve, none of that would be possible if it wasn’t for the hard work and dedication of our people, so yes, I am very optimistic that we are going to be successful in doing that without having to significantly drop day rates. In the process, we are only talking about 5 rigs, right, in a 300-rig market. And like I said, we posted a PowerPoint this morning. And Phillip did some really good analysis out there. There is a slide there. I referred to it as the Pac Man slide, where we have put some analysis to this question.

And the way we look at it in the Permian, there is roughly 40 of what we would call lower spec AC rigs. And then there is about two dozen SCR rigs that are running. I am ignoring the mechanicals because we are probably not the right tool for the work that the mechanical rigs are employing. But if you saw on both of those up, that’s 60ish rigs. That should be high grade opportunities for the super-spec pad-optimal fleet that we have. And like I said, we are only moving 5. I don’t think you are going to see a mass exodus of rigs out of the Haynesville. Certainly, we are going to move a handful. I suspect some others might move a few. But yes, I am very confident we are going to be able to do this. Are we going to be able to move all 5 without a single day of whitespace?

Hopefully, we can. But I would assume there is a small break in one or two of those. But we think that we kind of hit the bottom in terms of that transition here in the second quarter. But certainly, by the end of the year and I would hope within the fourth quarter, we are back to 20 rigs run €“ 21 rigs running and position for what should be a really good 2024 when you think about the macro.

Steve Ferazani: Excellent, excellent. Appreciate the explanation. And if you can just walk through a little bit in terms of the mobilization time how you are paid, I know Phillip gave some detail on pricing the average rig count in 2Q and then some of the costs, but in terms of the downtime as you move the time it takes to move from Haynesville to Permian now, how you get paid during that interim, just a little bit of detail there to explain it to everyone?

Anthony Gallegos: Yes. Steve, it’s really a long rig move is what it is. And look, we €“ a 1 year, 1.5 year ago, we were moving rigs from Permian to Haynesville and now we are going back. So the entire time to affect that mobilization is 7 days, 10 days. Our contracts in the Haynesville have demobilization provisions. There is typically a demobilization fee. Sometimes that that’s back to Houston, sometimes there is a lump-sum. And what we are doing to mitigate the financial impact is taking the demote fee that we would receive to bring the rig back to Houston. To the extent, we have to top it off to pay all of the trucking, we are doing that. And it’s really not as big of a financial hit as you might think. I think where the exposure is, is if we are not successful moving them straight from one location to another, in other words, contract to contract and there is idle time, because we see this as a relatively short-term phenomenon, our plan is to keep the crews.

And so you would incur the crew cost. But like I said, we have signed two contracts so far optimistic that we are going to get them all done and mitigate that, but that would be the work exposure. Is it really is it the crew cost? Phillip, you want to anything?

Philip Choyce: Yes. For the rigs, when we are successful going kind of on these first two, there was really no, I mean, just other than a long rig move, there were no incremental transportation costs and really no incremental crew costs. So to the extent we are successful going from contract to contract kind of direct continuation that $3 million to $4 million guidance we gave if you go to zero, it’s going to be hard to do that on all 5. So we are probably a little ahead right now on where we thought we would be with these first two. And so we will just have to wait and see. But it’s not a big financial. The rig moves a small part of it. The biggest part is just how we handle the crews if there is a month or two of whitespace between contracts.

Steve Ferazani: Make sense. Thanks for that. Last one for me in terms of how you are handling the toggle notes now, it sounds like you are saying €“ you are switching, are you going to be paying cash interest without given the limited CapEx you are now expecting this year or the less than you are previously?

Philip Choyce: Yes. So, we had previously guided to we would start paying cash interest in March. I think we could look at doing that March of 2024. I think what’s on the table now is we could start paying cash interest beginning of September. I think if you look at our working capital, we need to improve that and that’s starting now. And we have got some items related to the rigs reactivated, and at 12/31, we are going to pay that and then we will look to increase our cash balance. And we will make the decision in September whether to pick interest for that, or pay cash at that point in time. The other kind of thing that’s available to us is, under the indenture, the mandatory offers we started offering to pay back at par beginning in June of this year, $5 million a quarter of notes.

I don’t know whether the note holders will except that or not, but that will be a use of cash, that will help de-lever the company as well if they accept those offers. So, there is a couple of different things moving there.

Steve Ferazani: Great. Philip, Anthony, thanks for the responses this morning.

Anthony Gallegos: Yes, sir. Thank you, Steve.

Operator: The next question comes from Dave Storms with Stonegate Capital Markets. Please go ahead.

Dave Storms: Good morning. Appreciate you all taking my call. So, just starting with the delta between the 200 rigs and 300 rigs. I thought I remember right, in the last quarter there is approximately 2,500, wasn’t you sure if that has changed, now with the market changing, you are moving rigs from Haynesville to the Permian?

Anthony Gallegos: No, I don’t think it’s changed. Dave, the only thing that has changed and its positive is in the fourth quarter, we were successful in converting one of those from 200 series to 300 series. And that was very, very important for us, because we needed to prove it technically, but also prove it commercially that, look, we are making the capital investment that €“ and it’s very modest amount, right. I think we said $650,000, that we actually can earn and return on that. And we ticked all of those boxes with that conversion. So, as the marketing team is sitting here today, and thinking about the placement of the rigs that we are moving, for example, which are predominantly 200 series rigs, they have that optionality.

In other words, that is an option to the extent that the customer needs the enhanced racking capacity and is willing to pay for it, we can do that. But I think just the two that we have already moved and contracted, show that the 200 series rigs in the Permian Basin, except for the little bit of softness, I mentioned a second ago on the call, is pretty much held up.

Dave Storms: Okay. Perfect. Thank you. Are you seeing any customers not want to do the conversion just because the 200 spec rigs meet all their €“ everything that they need?

Anthony Gallegos: Yes. We are. And in fact, we are seeing the opposite too that the one rig that we converted back in November has been working for an operator. It’s one, if not the biggest private operator in the Permian Basin. They love everything about that rig. I don’t think they would ever let it go. But when we made the pitch to them that look, okay, if you want to drill an extra couple thousand feet of lateral, here is a rig that you know what, you love it, it’s a well performing rig. We can make this enhancement to it, but you are going to have to pay for it. And they said yes, let’s do it. And that was the first one we did. But no, they are these €“ the 200 series rigs, they are super-spec, they are pad-optimal, three mud pumps, 4 Gen.

They are online controlled. They are Ferraris. And they are very, very fast moving. So, you think about work, for example, in the Midland Basin, where we are drilling 10-day wells. And we drilled four wells on a pad and we moved, rig move time is very, very important to the customer. So, they have their advantages, their customers that love them, and we are just given them an opportunity to love them even more, but we have to get paid for it.

Dave Storms: Absolutely, that’s great color up. One more if I could, and I know you mentioned that you are not expecting a mass exodus from Haynesville. But you did mention that you are expecting to see other operators move out? Are you seeing any competition for logistics or the machinery equipment needed for the transport moving to Permian?

Anthony Gallegos: No, we haven’t. And we haven’t yet, Dave. One of the things that that Philip and I are looking at for example is, trucking cost. If we were going to see a mass exodus of rigs, out of the Haynesville going into the Permian, you would expect trucking to become tighter and the cost to go up. And in fact, we were talking right before the call the latest rounds of bids, the costs are actually less than the two that we have €“ the one that we have already moved and the one that we are about to move. So, it gives me a little bit more confidence that there is just €“ there is not a mass exit of rigs out of the Haynesville.

Dave Storms: That’s perfect. Thank you very much.

Operator: The next question comes from David Marsh with Singular Research. Please go ahead.

David Marsh: Thank you for taking the questions. Good morning guys.

Anthony Gallegos: Hi. How are you?

Philip Choyce: Good morning Dave. Thank you.

David Marsh: So quickly on, I really appreciate the commentary about reducing leverage here as we move forward. I know you guys just took an opportunity in September to push out the ABL to 2025. But as the numbers come in, and leverage continues to decline, would you potentially take another look at that and maybe revisit rigs on that agreement?

Philip Choyce: On the ABL, we could, yes. Certainly, we are always going to be looking for opportunities to reduce our costs.

David Marsh: Great. And I mean

Philip Choyce: I wouldn’t predict it using that, and we wouldn’t use that. We were not €“ we probably wouldn’t be using our ABL much in a debt reduction that we will probably be paying that to zero here this year. And so that’s not going to be a significant cost to us going forward.

David Marsh: And I have been a little out of touch with the market, but are there any restrictions on your ability to potentially repurchase any of these converts in the open market, should the market present that opportunity to you?

Philip Choyce: Yes. So, the converts are closely held by two holders. The indenture wouldn’t allow. We would have to negotiate that with the two holders.

David Marsh: Got it.

Philip Choyce: We do have the mandatory redemption provisions where we make an offer to them beginning in June. And we would buy those, it’s $5 million a quarter, and we would buy those notes back at par. I don’t know whether they are going to accept those or not. It’s at their option, but we do make those offers to them beginning in June of this year.

Anthony Gallegos: We are certainly hopeful, they are going to accept the redemption offer, that you guys know, we are very focused on doing the things necessary to bring the leverage down on the company. I think we are on a glide path to do that. So, the sooner we can make progress. Certainly on a net-net basis, we are going to do it anyway. But the sooner we can make progress and actually taken out notes, the better in my mind.

David Marsh: Absolutely. Well, congrats again on the quarter and good luck going forward. It sounds like you guys are on a great path.

Anthony Gallegos: Great. Thank you, Dave.

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

Jeff Robertson: Thank you. Good morning. Anthony, on Slide 22 of the deck you posted this morning, you have your backlog and spot market exposure. Can you talk about the impact of rig transitions to the Permian? And how that will impact re-pricing as you look into €˜23 and €˜24, I am sorry, third quarter and fourth quarter, when you are pretty much exposed to the spot market?

Anthony Gallegos: Yes. We made the decision in the second quarter of last year to put some backlog on the books. As you might remember, Jeff, we did that. Fourth quarter was about positioning our contracts to take advantage of what we thought was going to be increasing commodity prices this year, and the activity that that would spur along. That’s why you have seen the backlog level come down that combined with the fact that there is not a lot of 1 year contract opportunities out there. Right now, it’s more six months, or pad-to-pad, which is fine with where the market is and what we are doing. So, we think it’s going to take a couple of quarters for this to shake out. I think where you see the next inflection point is going to be in the fourth quarter around 2024, CapEx programs as our customers begin to execute on those.

But they are €“ just going to kind of move sideways here for the next couple of quarters. And you look at where we are today in terms of margin generation, that the guidance that Philip provided as well. This is still going to be a pretty good year for ICD. It’s going to be good from an EBITDA perspective, but more importantly, from a free cash flow generating perspective. And the fact that we have made the decision and we have announced to you guys now that the 22nd rig is not going to happen this year, tells you that things that Philip mentioned a second ago about enhancing our working capital, making sure that we have cash to redeem these notes when the opportunity presents itself to bring the leverage down in the company, all that is actually being accelerated as this year is playing out.

Jeff Robertson: When you move rigs to the Permian, the remaining three, I am sorry, put to the Permian, the remaining three rigs that you have in Haynesville that you would like to move. Are you €“ you are waiting on contracts to move those so they go to work immediately, is that correct?

Anthony Gallegos: Well, they are all working today, Jeff. We don’t have any idle rigs. So, we have got to finish off the commitment that we have today in the Haynesville and that’s going to happen here in the second quarter. And as the €“ so our goal would be as we finish the one contract in the Haynesville, we want to have a contract in the Permian, that hopefully we are able to move pad-to-pad. And that’s what we did with the first one. That’s what we are about to do with the second one. Hopefully, we will do that with all them.

Jeff Robertson: And then lastly, is there much of a margin difference between operating rigs in the Permian versus the Haynesville?

Anthony Gallegos: We think there is a little bit of a margin improvement when we work in the Haynesville. It’s a function of longer wells in terms of duration, you are on pads longer, some things like that, but it’s not significant.

Jeff Robertson: Okay. Thank you.

Anthony Gallegos: Yes. Thank you, Jeff.

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

Dick Ryan: Thank you and congratulations on a good quarter. So, most of my questions have been asked, but I was looking at your Pac Man chart, Philip and Anthony. What motivates the operator to pay a higher day rate when you are bringing those things into the Permian? And does that allow you any flexibility on discussing terms for these new contracts?

Anthony Gallegos: Yes. On the first point, you got to remember that there were several operators last year, that would have liked to contract a rig, like we are talking about, something that’s super spec and pad-optimal, all the bells and whistles, before configuration the whole. But because of the market tightness, they weren’t able to. So, that’s a very logical and obvious target for the rigs that we are bringing over, because they meet the €“ what I just described to know we

Philip Choyce: Yes. If you recall, the only way you could get us, in the fourth quarter to get a super, an additional rig was to take our rig on stack or reactivation. And all of our intelligence and what we are seeing is, that’s an $8 million to $10 million investment by the drilling contractor, we are requiring contractual payback, a lot of operators just couldn’t for a lot of different reasons were willing to sign a year or longer contract that would require that. So obviously, those opportunities, they have an opportunity to take a rig that maybe they didn’t €“ maybe didn’t have a chance to take before. And then obviously, after the market settles, if the rig count does tick-up again, they will be back and if they need incremental rigs, and they are going to have to come back out from reactivation. So, we will have to see when that occurs.

Anthony Gallegos: Dick, I would also add, our marketing team, Scott, Mark, they did an amazing job. And some of the opportunities that we are contracting today with the rigs coming out of the Haynesville are opportunities that you wouldn’t see on any active customer chart. So, there are guys that wound down a program in the first half of last year they were idle, or maybe they couldn’t get their hands on a super-spec rig in the back half of the year. And now we are in a New Year, new budget season. Like said, the guys did a great job, stayed in touch with a whole wide array of customers. And we are being very, very successful there. In addition to increasing the number of multi-rig clients that we have guys that we have been working for, that have maybe an underperforming rig, not a rig of ours, but someone else’s.

And okay, we go to them with a sister rig, like what’s already there. And we have been able to execute that here in the first part of the year. Like I have said, it’s kind of churn in the basin, so you won’t see it. But as we look out over the next couple of quarters, we are going to look to try and create more of those kinds of opportunities like that. And we are in some pretty good discussions right now around those opportunities.

Dick Ryan: Okay. Great. Thank you and congratulations.

Anthony Gallegos: Thank you so much Dick.

Operator: The next question is a follow-up from Jeff Robertson with Water Tower Research. Please go ahead.

Jeff Robertson: Thanks. Anthony, you mentioned the refinancing window for the pick notes. But can you just talk about the options that going into that window with much stronger balance sheet as you talked earlier, push the 21st activation out and build cash and improve the metrics on the balance sheet? What kind of options that will give you as you think about alternatives to refinance the notes into something a little more conventional?

Anthony Gallegos: Yes. We are kind of limited in what we can do right now outside of negotiating something with our creditors, our creditors or great partners, Jeff. As you know, we put the convertible note in place, about this time last year. And we want to €“ we are going to have to build cash. And we are going to have to take advantage of these mandatory redemption opportunities that we have. And make sure that we continue to build cash as we enter this defeasance period and

Philip Choyce: So, that the fee €“ that period begins in September of 2024, so early, and then there is a make-whole under the terms of that. So, it’s pretty expensive to do it at that point in time. So, we would have to look at what’s available to do that at that point in time and would it make economic sense. As we move closer to maturity, they gets cheaper. So, it’s hard to say now, what opportunities will lie ahead. And what alternatives there will be until we see what the market looks like, and also depends on what the note holders are interested in doing as well. But as far as the terms of the indenture, it’s begin September of €˜24. And that’s when the window opens up. But there is the make-whole. So, it’s pretty expensive at September, and it gets cheaper as we move closer to maturity.

Anthony Gallegos: And Jeff, I would just add, I mean I am so glad that we are able to give Philip a headache, thinking about these kinds of things now. It’s a function of just everything that we have worked so hard to accomplish over the last couple of years. We had to get to an operating scale, one where we can survive the bumps and bruises that a cyclical industry like ours presents. But more importantly, so that we had operating scale to be able to, like seriously think about these kinds of things and have these kinds of discussions. I hope what everybody has taken away from this call is that this is going to be a pretty good year for ICD, and maybe not the year that we all thought three months or four months ago. But when you think about making sure, we are making progress down the pathway of being able to accomplish our long-term goals this 2023 in spite of any softness coming out of the Haynesville is still going to be a pretty good year towards making that progress.

Jeff Robertson: Looking at Slide 27, the de-leveraging profile just in terms of the leverage ratio, as you transition rigs, it seems like a pretty strong testament to the strength of the business?

Anthony Gallegos: Yes, sir. Thank you. I would agree.

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

Anthony Gallegos: Well, thank you MJ. Look, I hope as everybody has heard here, there are so many good things going on here at ICD. I want to make sure that I say thank you to all of the team members here, especially those around the rotary tables where the work gets done. Obviously, we are very, very excited about 2023, looking forward to updating you on our progress when we report our first quarter results here, pretty soon. So, until then, we want to wish you all safety and success in your endeavors and we will sign-off now. Thank you.

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