Q4 2022 Independence Contract Drilling Inc Earnings Call

Speaker 2: Hello and welcome to the Independence Contract Drilling Inc. 4th Quarter and Year-End 2022 Financial Results Conference Call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions.

Speaker 2: To ask a question, you may press star then 1 on your telephone keypad.

Speaker 2: To withdraw from the question queue, please press star, then too.

Speaker 2: Please note, this event is being recorded.

Speaker 2: I would like to turn the conference over to Philip Choice, Executive Vice President, and Chief Financial Officer. Please go ahead.

Speaker 3: Good morning, everyone, and thank you for joining us today to discuss ICD's fourth quarter 2022 results.

Speaker 3: With me today is Anthony Guyagos, our President and Chief Executive Officer.

Speaker 3: 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.

Speaker 3: A number of factors uncertainties could cause actual results in future periods to differ materially from what we talk about today.

Speaker 3: For a complete discussion of these risks, we encourage you to read the company's earnings release and our documents on file at the SEC.

Speaker 3: In addition, refer to non-GAAP measures during the call.

Speaker 3: Please refer to the earnings release in our public filings for our full reconciliation of net income and loss to adjusted net income and loss, EBITDA and the justity of EBITDA and for definitions of our non-gat measures.

Speaker 3: And with that, I'll turn it over to Anthony for opening remarks.

Speaker 4: Hello everyone, thank you for joining us for our fourth quarter earnings conference call. 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 SuperSpec pad optimal rigs and how that will impact ICD.

Speaker 4: and third, I want to close out with what we're focused on as we navigate 2023 and beyond.

Speaker 4: 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.

Speaker 4: Philip will go through the detail, but I want to point out that our reported revenue per day, margin per day, and quarterly adjusted EBITDA, we're all again records for ICD. This is the second quarter in a row we've produced record results.

Speaker 4: In addition, as the full year 2022 played out, we saw a justity of the DA increase by more than five times measuring fourth quarter to the first quarter of last year. And we're 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 pre-cash flow.

Speaker 4: As we closed that 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 two additional rigs during the fourth quarter. Both of those rigs went to work in the Haynesville on very good contracts.

Speaker 4: In addition, we successfully completed our first 200-300 series conversion involving a rig working for a customer in West Texas.

Speaker 4: Proving that our 200 to 300 series conversions are technically and commercially viable is 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.

Speaker 4: On the operational and 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'm very proud of how our operations and support teams continue to deliver high levels of customer service, performance and professionalism.

Speaker 4: 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.

Speaker 4: Looking ahead, we're 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.

Speaker 4: We're 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.

Speaker 4: 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 a materially increased the percentage of rigs marketed with our 300 series specification. ICD has never been stronger.

Speaker 4: All of the hard work we put into positioning IE while bouncing off the pandemic bottom will be on full display as we navigate the new year.

Speaker 4: And with that, I want to shift to our current market perspective, and in particular, what's on everyone's mind, what the softness and natural gas prices means for ICD strategically in 23.

Speaker 4: First, let me address the overall market and outlook for rig activity for pad optimal super spec rigs in our target markets of Texas and the contiguous states.

Speaker 4: Overall, demand for pad optimal super spec rigs remains strong. Today overall utilization remained above 90% in the industry, and we expect continued improvement in our rig margin for day in the first quarter driven by contract rollovers as we reprised rigs contract at early last year.

Speaker 4: The Philippa will provide more detailed guidance, but I wanted to highlight that we currently expect our March 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.

Speaker 4: However, the sharp decline in natural gas prices during the past four months has created a disparity between our two primary operating basins.

Speaker 4: In the Permian, which is all directed activity, demand remains robust, and we're expecting an overall uptick in the SuperSpec rig count, Matt Basin in 2023.

Speaker 4: 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 EMP's response to Henry Hub natural gas prices, which had declined from $9.68 on August 22nd to $2.12 per million BTU last week. As we're nearing the end of winter, we're going to be looking at the

Speaker 4: 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.

Speaker 4: With that market backdrop, we see two primary impacts on ICD.

Speaker 4: First, the overall Haynesville directed rig count is 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 of the Haynesville are also trimming their active rig plates.

Speaker 4: The impact ICD's hands will fleet will include some rig relocations to West Texas, which have already commenced.

Speaker 4: Right now we're confident that we'll need to relocate five to six rigs, which will take place primarily during the second and third quarters of this year.

Speaker 4: The process has already started with one rig relocating without any operational white space.

Speaker 4: And I would be remiss if I didn't point out that we received a day rate increase in the process.

Speaker 5: We are in final contract negotiations for our second relocation, which will also occur with minimal white space and a day rate increase.

Speaker 6: 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.

Speaker 7: We are already seeing some lower spec rigs get displaced as the results of the churn underway.

Speaker 8: Also, rigs brought from the haines will end to the Permian, will likely absorb rig count growth opportunities previously reserved for rig reactivations.

Speaker 9: In this environment, we expect overall rig reactivation is 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.

Speaker 10: 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.

Speaker 11: As we've mentioned on prior calls, 80% utilization or above is typically where drilling contractors are able to maintain and increase pricing.

Speaker 12: But over the next two quarters or so, there's 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 and margin acceleration to moderate. So as we move past the first quarter...

Speaker 13: and all of the rigs have reprised to current market day rates. I expect day rate and margin improvement to flatten out for ICD after the first quarter. Philip 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.

Speaker 14: 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.

Speaker 15: 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.

Speaker 16: Phillip will go through more of the details, but financially our backlog of contracts in the hands will mute much of the potential financial impact while rigs are transitioning.

Speaker 17: So how will all this impact ICD this year and strategically?

Speaker 18: Overall, we do not expect it will have a material overall impact other than to postpone rig reactivations.

Speaker 19: All of ICD's strategic and financial goals regarding generating significant free cash flow and reducing overall leverage remain intact.

Speaker 20: As Philip 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 rigged 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.

Speaker 21: Just 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.

Speaker 22: One of our long term goals is to reduce our net debt to adjusted EBITDA ratio meaningfully towards the range of less than one to one and a half times during the refinancing window involving our convertible notes.

Speaker 23: The reference would currently at two and a half times 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 two times or below utilizing the same metric.

Speaker 24: So while we have some work to do in this regard, everything's in place for ICD to achieve its short and long-term financial and strategic goals.

Speaker 25: I'll make some additional concluding remarks, but right now I want to turn the call over to fill up to discuss our financial results and outlook in a little more detail.

Speaker 26: Thanks Anthony. We were essentially break even from a profitability standpoint in the fourth quarter. During the quarter we reported an adjusted loss of $87,000 or one cent per share and adjusted EBITDA of $18.5 million.

Speaker 27: Reported as just to the biddaw increased sequentially 48% compared to the third quarter of 23. Adjusted net loss and income exclusive impact of attack benefit recognized during the fourth quarter. Falling completion of our analysis regarding the deductibility of interest expense under our convertible nets.

Speaker 28: We operated 18.5 average rigs during the quarter, representing a 6% increase compared to the third quarter.

Speaker 29: Anthony previously mentioned our fourth quarter revenue in Margin, per day were quarterly records for ICD.

Speaker 30: 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.

Speaker 31: which included approximately $1.9 million of stock base 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. First expense during the quarter aggregated $8.6 million.

Speaker 32: 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 are disposals for approximately 18.8 million dollars.

We're taking 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 kind.

when due in March of this, 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 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 Hansville 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 $33,233,600 per day.

The cost per day is expected to range between $18,118,400 per day.

Unmissorbed 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 locations for the Permian, principally related to crew carrying costs during the transition period and unreimbursed transportation costs.

We expect first quarter cash as GNA expense to be approximately 5.9 million dollars and stock based compensation expense is expected to be approximately 2 million dollars on top of that.

Effect interest expense to be approximately $8.8 million of this amount, approximately $2.4 million, will relate to non-cash amortization of deferred financing costs and debt discounts.

Appreciation 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 Hanson Lee 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 19-20 rigs in the third quarter, and then we resume full effective utilization of our 21 reactivated rigs in the fourth quarter of our 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 costs associated with this exercise to be approximately three to four million dollars with the majority of it occurring during the second quarter of 2023.

Moving on to guidance relating to fiscal 2023 as a whole.

Overall, our SGNA budget for $2,023 is $27 million, comprised of $18.5 million of cash SGNA 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 fur counting 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 million.

400,000 neted disposals. It does not assume that we'll reactivate our 22nd rig, which Anthony mentioned we have postponed. Breaking out our capital budget, 4.5 million relates to the reactivation and upgrade cost, principally associated with the 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 a cash federal tax income payer.

For weighted average shares outstanding in periods of net income, our fully diluted shares outstanding will include the shares associated with the Zoom full conversion of the convertible

And with that, I will turn the call back over to Anthony.

Thanks, Philip. Before opening the call up for questions, I want to briefly summarize ICD strategic positioning and what I think it all means for ICD 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, Rick Fleet. The market for pad-offimal super spec rigs remain strong outside of the gas-driven bases. We continue to demonstrate our fiscal discipline by securing contracts that earn full simple payback on the reactivation cat-backs we are investing in by deferring further investments in additional reactivations beyond the...

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.

and 2023 is intact and in many ways will accelerate.

So summing all this up, ICD checks all the boxes. Whether you're looking for best in class assets, leading rig margins, or an outstanding customer base and rigs focused on the most important oil and gas shell plays in US unconventional, 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 ex-apon, execute upon ICD strategic initiatives.

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

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

So withdraw from the question queue. Please press star then to. At this time we will pause momentarily to assemble our roster. Today's first question comes from Don Christ with Johnson Rice. Please go ahead.

To withdraw from the question queue, please press star, then two. At this time, we will pause momentarily to assemble our roster. Today's first question comes from Don Christ with Johnson Rice. Please go ahead. Morning, gentlemen. How are y'all this morning?

Yeah, good job. Morning, Dawn. Anthony, I wanted to start with obviously the macro is very topical these days and it's the contention amongst analysts and the invested community that. Okay.

The rig count is going to get a little bit weak, you know, towards the summer possibly, but then...

you know increase as we go into the fall and the genesis of my question is what do we look like in 2024? You know we all think that it's going to be week 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 as that Haynes bill or gas directed drilling increases?

Yeah, Dawn, that's exactly what we see over the next 12 to 24 months, where on a geographic basis where you likely see a rig count decline is in the hands. I'm talking about our target markets of Texas and the contiguous states.

You know, based on our conversation, certainly the negotiations that we've 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 ads. You know, in the short term, there's some high-grade opportunities where some lower spec rigs are getting changed out, and then there's a tranche of EMPs that maybe haven't been busy that are picking up rigs.

And that's where we're finding opportunities today. I'm encouraged by the fact that we're not having to take a deep discount in day-rate to be able to place those rigs. One other antidote I'd share with you is even in the Haynesville, this is true, when we talk to our customers who may be

reducing activity levels, they're 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 pick up maybe a little sooner than the overall market may be expecting.

So no, I think it's a relatively Flatish type rig count first half of the year beginning Q3 Q4. I began 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're back in Probably sooner than people realize

And you touched on it in the comments a second ago. Can you just talk about pricing? You know, we've heard a couple of antidotes of ENPs, larger ENPs that are operating multiple rigs, kind of going back to operators and securing five or 10% discounts, but that still equates to, you know, 50% margins. Are you seeing any kind of haggling there on price?

Having had any customers come to us and asked for a day rate reduction, we had positioned quite a few of our rigs, especially the rigs in the Haynesville to roll over here in the second quarter anyway, which was going to give us an opportunity to increase rates a little more.

You know, just to give you some feel for what we're seeing, day rates are maybe there a thousand, two thousand a day less than we would have thought they would be at this time of the year compared to, you know, 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.

that the SuperSpec RigFleet provides our customers.

I was at a dinner last week here in Houston and was talking with a CEO of an EMP company. Of course, I'm in sales mode, right? I'm always in sales mode. And he's telling me that he's taken advantage of an opportunity to pick up a couple of Super Spec rigs And replace our tech fixtures and replace our20 seams and our

some lower spec AC rigs that he had running. And a comment he made was already on the first pad, they're seeing the benefits of the super spec equipment.

And, you know, I'd point out for our investors that that's 100% of our fleet, super spec, pad optimal. And, you know, when I think about rigs moving into the Haynesville, of course we're going to move a few in, we've 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 flatish 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 wealth. So day rates, I mean, look, our customers have to do their job and make sure they're

overall economics of what they're doing.

I appreciate all the cova I'll jump back into. Thanks.

Yes sir, thanks not.

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

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 five of your hands, little rigs into the Permian given.

There will be some competition there. And is that you are thinking that there are that many rigs that can replace drilling programs just to 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.

Yes, and thank you for the question, Steve. I do think we're going to be successful. In fact, two of the five. One is already in 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 in the hands bowl to what it's going to earn on the new contract, it's an increase in day rates. So that's two out of the five right there. 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 off equipment. It's a function of the reputation that ICD has in both basins. You know, we're very concentrated in terms of our target market. I think everybody knows that. Permian and Haynesville are home markets for us. Yeah, we've worked in the Eagle for...

that we're going to be successful in doing that without having to significantly drop day rates. In the process, we're only talking about five rigs, right, in a 300-rig market. And like I said, we posted a PowerPoint this morning and Philip did some really good analysis out there. There's a slide there. I refer to it as the Pac-Man slide, where we put some analysis.

to this question. The way we look at it in the Permian, there's roughly 40 of what we would call lower spec AC rigs. There's about two dozen SCR rigs that are running. I'm ignoring the mechanicals because we're probably not the right tool for the work that the mechanical rigs are employing. But if you sum both of those up, that's 60-ish rigs that should be high-grade opportunities

for the SuperSpec pad optimal fleet that we have. And like I said, we're only moving five. I don't think you're gonna see a math exodus of rigs out of the hands. Certainly we're gonna move a handful. I suspect some others might move a few. But yes, I'm very confident we're gonna be able to do this. Are we gonna be able to move all five without a single day of white space?

Hopefully we can, but I would assume there's 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're back to 21 rigs running in position for.

What should be a really good 2024 when you think about the macro? Excellent, excellent. I appreciate the explanation. And if you can just walk through a little bit in terms of the mobilization time, how you're paid, I know Philip gave some detail on pricing, the average rate count into Q and then some of the costs. But in terms of the downtime as you move the time it takes.

The entire time to affect that mobilization is seven days, 10 days. Our contracts in the Hainesville have demobilization provisions. There's typically a demobilization fee. Sometimes that's back to Houston. Sometimes there's a lump sum. And what we're doing to mitigate the financial impact is taking...

short-term phenomenon, our plan is to keep the crews. And you know, so you would incur the crew cost. But like I said, we've signed two contracts so far, optimistic that we're going to get them all done and mitigate that. But that would be the where exposure is. It really is the crew cost. Philip, you want to add anything? Yeah, for the rig, when we're successful going kind of on...

It's going to be hard to do that on all five. So we're probably a little ahead right now on where we thought we would be with these first two. So we'll just have to wait and see. But it's not a big financial. The rig move is a small part of it. The biggest part is just how we handle the crews.

if there's a month or two of wide space between contracts. Yep, makes sense. Thanks for that. Last one for me in terms of how you're handling the toggle notes now. It sounds like you're saying are you switching, are you going to be paying cash interest without giving the limited cap backs you're now expecting this year or the less than you were previously? Yeah, 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 in September . I think if you look at our working capital, we do need to improve that, and that's starting now. We've got some items related to the rigs we reactivated in.

AP at 1231 we're going to pay that and then we'll look to increase our cash balance and we'll make the decision in September whether to Pick interest for that for that, you know 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 start offering to pay back at Paul

things moving there.

Drag

Fill up out the name thanks for the responses this morning. Yes sir, thanks Dave. The next question comes from Dave Storms with Stonegate Capital Markets. Please go ahead.

More and I appreciate you all taking my call. Just starting with the delta between the 200 and 300 rates, I thought I remember right the last quarter is approximately 2500. Wasn't you sure if that has changed now with the market changing? Can you move from right from from hand still to the permits?

No, I don't think it's changed. The only thing that has changed and is positive is in the fourth quarter we were successful in converting one of those from 200 to 300 series and that was very, very important for us because we needed to prove technically but also prove it commercially that look for making the capital investment and it's a very modest amount, right? I think we said 650,000.

that we actually can earn a 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're 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've already moved and contracted show that the 200 series rates in the Permian Basin, except for the little bit of softness I mentioned a second of going to go on to call is pretty much held up.

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? Yes, we are. And in fact, we're seeing the opposite too. The one rig that we converted back in November has been working for an operator. It's one of, 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's a rig that you know it, you love it, it's a well-performing rig. We can make this enhancement to it, but you're 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, the 200 series rigs, they're super stacked, they're pad, optimal, three mud, four gin, they're on-ron controlled, they're for raries. And they're very, very fast moving. So you think about...

work, for example, in the Midland Basin, where we're drilling eight, nine, ten day wells. We drill four wells on a pad and we move. Rig move time is very, very important to the customer. So they have their advantages. They're customers that love them. And we're just...

given on an opportunity to to level me even more, but we have to get paid for it.

absolutewe've pass great color up. one more, if I could andknow. You mented that you're not expecting a mass acodus from hay, So but you did mentioned that you are expect an see how their operators move out. Are you seeing any competition for logistics or the machinery equipment needed to transfer to? Between me, those are perent.

No, we haven't and we haven't yet Dave. One of the things that Philip and I are looking at, for example, is trucking costs.

If we were going to see a mass exodus of rigs out of the hands, we'll go into the permanent, you would expect trucking to become tighter and the cost to go up. In fact, we were talking right for the call, the latest rounds of bids, the cost to actually less than the two that we've already moved and the one that we're about to move.

It gives me a little bit more confidence that there's not a mass X that's going to break out of the hands.

That's perfect. Thank you very much. The next question comes from David Marsh with Singular Research. Please go ahead.

Thank you for taking the questions. Good morning guys. Thank you. Good morning. Good morning, Dave. So quickly, you know, I really, 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 you know, as the numbers come in and leverage continues to decline, which you potentially take another look at that and maybe revisit rates on that agreement.

On the ABL? We could, yes. Certainly we're always going to be looking for opportunities to reduce our costs. Right. And I mean, do you think that... I wouldn't predict us using that. We wouldn't use that. We probably wouldn't be using our ABL much in a debt reduction. We'll probably be paying that to zero here this year.

And so that's not going to be a significant cost to us going forward. And I've been a little out of touch with the market, but is 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?

Yeah, so the converts are closely held by two holders. The indenture wouldn't allow, we would have to negotiate that with the two holders.

by two holders. The indenture wouldn't allow. We would have to negotiate that with the two holders. We've got it. We've got it.

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're 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. We're certainly hopeful they're going to accept the redemption offer though.

As you guys know, we're very focused on doing the things necessary to bring the leverage down on the company. I think we're on a glide path to do that. So the sooner we can make progress, certainly on a net debt basis, we're going to do it anyway, but the sooner we can make progress and actually take it out in notes, the better, in my mind. Absolutely. Absolutely. Absolutely. Absolutely.

Bob, congrats again on the quarter and good luck going forward. Sounds like you guys are in great pass.

Great, thank you Dave. The next question comes from Jeff Robertson with Water Tower Research. Please go ahead. Thank you good morning Anthony. On slide 22 of the deck you all posted this morning you have your backlog and spot market exposure. Can you talk about that?

impact of rig transitions to the hank to them to the Permian and how that will impact rig pricing as you look into 23 and 24 I'm sorry third and fourth quarter

when you're pretty much exposed to the spot market? Yeah, 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've seen the backlog level come down that combined with the fact that there's not a lot of one year contract opportunities out there right now it's more six months or pad to pad, which is fine with with where the market is and what we're 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 there's just we're 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, the guidance that Phillips 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 pre-cash flow generating perspective. …

The fact that we've made the decision and we've 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, you know, enhancing our working capital, making sure that we have cash to redeem these notes when the opportunity presents itself.

to bring the leverage down company. All that is actually being accelerated as this year's playing out.

When you move rigs to the Permian, the remaining three, I'm sorry, yeah, to the Permian, the remaining three rigs that you have in the Haynesville that you'd like to move.

Are you waiting on contracts to move those so they go to work immediately? Is that correct? Well, they're all working today Jeff. We don't have any idle rigs So it we've got to finish up the commitment that we have today in the hands. Well, and that you know that's gonna 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're able to move pad to pad. And that's what we did with the first one, that's what we're about to do with the second one. Hopefully we'll do that with all of them. And then lastly, is there much of a margin difference between operating rigs in the Permian versus the Haynesville?

We think there's a little bit of a margin improvement when we work in the Haynesville. It's a function of longer wells in terms of duration, your own pads longer, some things like that. But it's not significant.

We think there's a little bit of an margin improvement when we work in the Haynesville. It's a function of longer wells in terms of duration, your own pads longer, some things like that, but it's not significant. Okay. Thank you. Thank you.

Yes, sir. Thank you, Jeff. The next question comes from <expletive> Ryan with Oak Ridge Financial. Please go ahead. Thank you, Larry. Congratulations on a good quarter. Say, most questions have been asked, but I was looking at your Pac-Man chart, Philip and Anthony, what motivates the operator to pay a higher...

you know, day rate when you're bringing those things into the Permian and does that allow you any flexibility on discussing terms for, you know, these new contracts?

Yeah, 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're talking about, something that's super spec and pad optimal, all the bells and whistles, three before configuration, a whole bit. 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're bringing over because they meet what I just described. So no, we... Yeah, if you recall, the only way you could get in the fourth quarter to get an additional rig was to take a rig out of stack or reactivation.

and all of our intelligence and what we're seeing is that's an $8 to $10 million investment by the drilling contractor. We are requiring contractual payback. A lot of operators just couldn't, you know, for a lot of different reasons. We're willing to sign a year or longer contract that does.

that would require that. So obviously those opportunities, they now have an opportunity to take a rig that maybe they didn't have a chance to take before. And then obviously after the market settles that the rig count does tick up again, they will be back in the, in the, if they need incremental rigs, then they're going to have to come back out of, you know, from reactivations and we'll have to see when that occurs.

And <expletive> , I would also add, you know, our marketing team, Scott Mark, they did an amazing job and some of the opportunities that we're contracting today with the rigs coming out of the hands full are opportunities that you wouldn't see on any active customer chart.

So they're guys that wound down a program in the first half of last year that they were idle or maybe they couldn't get their hands on a Super Spec rig in the back half of the year. Now we're in a new year, new budget season. Like I said, the guys do a great job staying in touch with a whole wide array of customers. And we're being very, very successful there. In addition to...

increasing the number of multi-rig clients that we have, guys that we've been working for that, you know, 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've been able to execute that here in the first part of the year. Like I said, it's kind of churned in the basin, so you won't...

follow-up from Jeff Robertson with WaterTower Research. Please go ahead.

Thanks, Anthony. You mentioned the refinancing window for the pick notes. Can you just talk about the options that going into that window with...

The much stronger balance sheet, as you talked earlier, pushed the 21st activation out and in build cash and improved the bench of some of 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?

Yeah, we're kind of limited in what we can do right now outside of negotiating something with our creditors. Our creditors are great partners, Jeff. As you know, we put the convertible note in place about this time last year. And we've lost to a huge fires and biodiversity. We ve got through so many of them going

We want to we're going to have to build cash and we're going to have to you know take advantage of these mandatory redemption opportunities that we have and Make sure that we continue to build cash as we enter this defeats period and The defeat that that period begins in September of 2024

So we're all, and then, and there's a make hole under the terms of that. So it's pretty expensive to do it at that point in time. So we'd have to look at what's available to do that at that point in time and what to make economic sense as you move closer to maturity against it gets cheaper.

So it's hard to say now what opportunities will lie ahead and what you know, alternatives there'll be until we see what the market looks like and also depends on what the node holders are interested in doing as well. But as far as the terms of the indenture, it's begin September of 24 and then that's when the window opens up but there's a may call so it's pretty expensive at September and it gets cheaper as we move closer to maturity.

Jeff, I would just add, I'm so glad that we're able to give Phillip a headache thinking about these kind of things now. It's a function of just everything that we've 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 I said, seriously think about these kind of things and have these kind of discussions. I hope what everybody's taken away from this call is that this is going to be a pretty good year for ICD. Maybe not the year that we all thought three or four months ago.

that progress.

Yeah, I'm looking at slide 27 and the de-leveraging profile just in terms of the leverage ratio.

As you transition, Riggs seems like a pretty strong testament to the strength of the business. Yes, sir. Thank you. I would agree.

This concludes the question and answer session. I would like to turn the conference back over to Anthony Gallegos for any closing remarks. Thank you, MJ. Look, I hope as everybody's 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're 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 and your endeavors and we'll sign off now.

those around the rotary tables where the work gets done. Obviously, we're 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 and your endeavors and we'll sign off now. Thank you.

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

So J.