Hello, and welcome to the Independence Contract Drilling, Inc. fourth 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. To ask a question, you may press star, then one on your telephone keypad. To withdraw from the question queue, please press star, then two. 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. Good morning, everyone, 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 in our public filings for our 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. With that, I'll turn it over to Anthony for opening remarks. Hello, everyone. Thank you for joining us for our fourth quarter earnings conference call. During my prepared remarks today, I wanna talk about three things. First, I wanna highlight our 2022 accomplishments. Second, I wanna describe the current market for super-spec pad-optimal rigs and how that will impact ICD. Third, I wanna close out with what we're focused on as we navigate 2023 and beyond. 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. Philip will go through the detail, but I wanna 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've produced record results. As the full year 2022 played out, we saw adjusted EBITDA increase by more than five times, measuring fourth quarter to the first quarter of last year. 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 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, having activated two additional rigs during the fourth quarter. Both of those rigs went to work in the Haynesville on very good contracts. We successfully completed our first 200 Series to 300 Series conversion involving a rig working for a customer in West Texas. Proving that our 200 Series to 300 Series conversions are technically and commercially viable 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 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 continued 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'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. 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. 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've put into positioning ICD while bouncing off the pandemic bottom will be on full display as we navigate the new year. With that, I wanna shift to our current market perspective, 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 and 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. Philip will provide more detailed guidance. 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 four months has created a disparity between our two primary operating basins. In the Permian, which is oil-directed activity, demand remains robust, and we're 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 E&P's response to Henry Hub natural gas prices, which have declined from $9.68 on August 22nd to $2.12 per million BTU last week. As we're 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 price is to remain softer longer. With that market backdrop, we see two primary impacts on ICD. First, the overall Haynesville-directed rig count's gonna 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 trimming their active rig fleets. The impact to ICD's Haynesville fleet will include some rig relocations to West Texas, which have already commenced. 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. The process has already started with one rig relocating without any operational white space. 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 white space 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. Rigs brought from the Haynesville into the Permian will likely 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've mentioned on prior calls, 80% utilization or above is typically where drilling contractors are able to maintain and increase pricing. Over the next two quarters or so, there's gonna 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. 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. 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 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, 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 19-20 average rigs during this year, taking into account the transition time that might occur on rig relocations during the second and third quarter. Philip will go through more of the details, financially our backlog of contracts in the Haynesville will mute much of the potential financial impacts while rigs are transitioning. 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 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 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 1 to 1.5 times during the refinancing window involving our Convertible Notes. For reference, we're currently at 2.5 times levered on an annualized basis using our fourth quarter results. Based upon the market expectation I just described, we expect to exit 2023 around 2 times or below utilizing the same metric. 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. I'll make some additional concluding remarks, but right now, I wanna turn the call over to Philip to discuss our financial results and outlook in a little more detail. Thanks, Anthony. We were essentially break even 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 2023. 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. 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 wanna 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 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. 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 $15,000 and $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 locations 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. 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 will relate 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. 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 or 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 costs associated with this exercise to be approximately $3 million-$4 million, 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 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 there'll 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'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 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 a cash federal tax income payer. For weighted average shares outstanding and periods of net income, our fully diluted shares outstanding will include the shares associated with the assumed full conversion of the Convertible Notes. With that, I will turn the call back over to Anthony. Thanks, Philip. Before opening the call up for questions, I wanna 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 basins. 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. Finally, we have substantially improved our liquidity and balance sheet and expect meaningful improvements in leverage ratios and other debt metrics as we move through 2023 and beyond. 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 Series 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. 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 shale plays in U.S. 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 execute upon ICD's 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 1 on your telephone keypad. If you are using a speakerphone, please pick up your handset before pressing the keys. 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 Crist with Johnson Rice. Please go ahead. Morning, gentlemen. How are y'all this morning? Good. Good, Don. Morning, Don. Anthony, I wanted to start with obviously the macro is very topical these days. You know, it's the contention amongst analysts and the investing community that the rig count's gonna get a little bit weak, you know, towards the summer, possibly, but then, you know, increase as we go into the fall. The genesis of my question is: what do we look like in 2024? You know, we all think that it's gonna be weak in 2023, 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 2024 as that Haynesville or gas-directed drilling increases? Yeah, Don, that's exactly what we see over the next 12 to 24 months, where on a geographic basis, where you'll likely see a rig count decline is in the Haynesville. I'm talking about our target markets of Texas and the contiguous states. you know, based on our conversations, 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 adds. you know, in the short term, there's some high-grade opportunities where some lower spec rigs are getting changed out. Then there's a tranche of E&Ps that maybe haven't been busy that are picking up rigs. 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 anecdote 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. 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. No, I think it's a relatively flattish type rig count first half of the year. Beginning Q3, Q4, 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. You touched on it in the comments just a second ago. Can you just talk about pricing? You know, we've heard a couple 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, you know, 50% margins. Are you seeing any kind of haggling there on price? Haven't had any customers come to us and ask for a day rate reduction. You know, we had positioned quite a few of our rigs, and especially the rigs in the Haynesville to roll over here in the second quarter anyway, which, you know, was gonna give us an opportunity to increase rates a little more. You know, just to give you some a feel for what we're seeing, day rates are, you know, maybe they're $1,002. $1,000 a day less than we would have thought they would be at this time of the year, compared to, you know, when I answered that question the last time we had a call. It's not a disaster by any means. As you said, margins are still very, very strong. Philip just provided some guidance on what we see here in the 1st quarter and even in the quarters beyond, in terms of it being relatively flattish. You know, 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'm in sales mode, right? I'm always in sales mode. He's telling me that he's taken advantage of an opportunity to pick up 2 super-spec rigs and replace some lower spec AC rigs that he had running. The comment he made was already on the first pad, they're seeing the benefits of the super-spec equipment. You know, I'd point out for our investors that that's 100% of our fleet, super-spec pad-optimal. You know, when I think about rigs moving into the Haynesville, of course, we're gonna 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 gonna bear the brunt of, you know, the flattish rig count with the increasing supply. 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. Day rates since-- I mean, look, our customers have to do their job and make sure they're spending money wisely. When you look at the typical Permian well, a 15-day well that costs $6 million-$8 million, you know, the rig is less than 10% of that. I would question just how sensitive they will be or how sensitive the day rates will be to the overall economics of what they're doing. I appreciate all the color. I'll jump back in queue. Thanks. Yes, sir. Thanks, Don. The next question comes from Steve Ferazani with Sidoti. Please go ahead. Morning, everyone. Appreciate all the detail on the call this morning. A lot of data here. Right. I do wanna follow the previous questions, in terms of your confidence level that you can get five of your Haynesville rigs into the Permian, given there'll be some competition there. Is that you're thinking that there's that many rigs that can 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. Yes. Thank you for the question, Steve. I do think we're gonna be successful. In fact, you know, two of the five, one is already in basin. The second one, we signed the contract this morning for, so it's gonna start moving next week. When you compare what its day rate was in the Haynesville to what it's gonna earn on the new contract, it's an increase in day rate. That's two out of the five right there. Got a couple more that are gonna come to me here in the first part of the second quarter. Team's doing a great job. 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. 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 Eagle Ford. Yeah, we've worked in the Chalk. These two basins are home for us where we have a very strong reputation. As you know, Stephen, none of that would be possible if it wasn't for the hard work and dedication of our people. Yes, I'm very optimistic that we're gonna 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. 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've put some analysis to this question. You know, 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 24 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. You know, if you sum both of those up, that's 60-ish rigs that should be high-grade opportunities for the super-spec pad-optimal fleet that we have. Like I said, we're only moving five. I don't think you're gonna see a mass exodus of rigs out of the Haynesville. Certainly, we're gonna move a handful. I suspect some others might move a few. Yes, I'm very confident we're gonna be able to do this. You know, are we gonna be able to move all five without, you know, a single day of white space? Hopefully we can, but, you know, I would assume there's a small break in one or two of those. We think that, you know, we kind of hit the bottom in terms of that transition here in the second quarter. Certainly by the end of the year, and I would hope within the fourth quarter, we're back to 21 rigs running and positioned for what should be a really good 2024 when you think about the macro. Excellent. Excellent. Appreciate the explanation. 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 rig count in 2Q, and then some of the costs. In terms of the downtime as you move the time it takes to move from Haynesville to Permian now... Yes. How you get paid during that interim, just a little bit of detail there to explain it to everyone. Yeah. Steve, it's really a long rig move is what it is. Look, you know, a year and a half ago, we were moving rigs from Permian to Haynesville, and now we're going back. You know, the entire time to affect that mobilization is seven days, 10 days. Our contracts in the Haynesville have demobilization provisions. There's typically a demobilization fee. You know, sometimes that's back to Houston, sometimes there's a lump sum. What we're doing, to mitigate the financial impact is taking the demo 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, you know, we're doing that. It's really not as big of a financial hit as you might think. I think where the exposure is, if we're not successful moving them straight from one location to another, in other words, contract to contract, and there's idle time, because we see this as a relatively short-term phenomenon, our plan is to keep the crews. Right. you know, so you would incur the crew cost. Like I said, we've signed two contracts so far, optimistic that we're gonna get them all done and mitigate that. That would be where exposure is. It really is the crew cost. Philip, you wanna add anything? Yeah. For the rig, when we're successful going kind of, on these first two, there was really I mean, just other than a long rig move, there were no incremental transportation costs and really no incremental crew costs. To the extent we're successful going from, you know, contract to contract kind of direct continuation, that $3 million-$4 million guidance we gave could go to zero. It's gonna be hard to do that on all five. We're probably a little ahead right now, on where we thought we would be with these first two. We'll just have to wait and see. It's not a big, 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 white 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 gonna be paying cash interest moving without given the limited CapEx you're now expecting this year or the less than you were previously? Yeah. 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 we've. Right. What's on the table now is we could, you know, 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, you know, starting now. We've got, we've got some, you know, items related to the rigs we reactivated in AP at 12/31, we're gonna pay that, and then we'll look to increase our cash balance. We'll make the decision in September whether to pick interest 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 par, beginning in June of this year, $5 million a quarter of notes. Don't know whether the note holders will accept that or not, but that'll be a use of cash, that'll help de-lever the company as well if they accept those offers. There's a couple different things moving there. Great. Philip, Anthony, thanks for the responses this morning. Yes, sir. Thank you, Steve. The next question comes from Dave Storms with Stonegate Capital Markets. Please go ahead. Morning. Appreciate you all taking my call. Yes, sir. Just starting with the delta between the 200 and 300 rigs, I thought I remember right, the last quarter is approximately 2,500 wasn't too sure if that has changed, now with the market changing, you know, moving rigs from Haynesville to the Permian. No, I don't, I don't think it's changed. Dave, the only thing that has changed, and it's positive, is in the fourth quarter, we were successful in converting one of those from 200 to 300 Series. 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. It's a very modest amount, right? I think we said $650,000, that we actually can earn a return on that. We ticked all of those boxes with that conversion. 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. you know, 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. I think just the two that we've already moved and contracted, show that, you know, the 200 Series rates in the Permian Basin, except for the little bit of softness I mentioned a second ago on the call, it's pretty much held up. Okay. Perfect. Thank you. Are you seeing any customers not wanna do the conversion just because the 200 spec rigs meet all their everything that they need? Yes, we are. 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. When we made the pitch to them that, "Look, okay, if you wanna drill an extra couple 1,000 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 gonna have to pay for it." They said, "Yes, let's do it." That was the first one we did. No, these, the 200 Series rigs, you know, they're super-spec, they're pad-optimal, 3 mud pump, 4 gen. They're Omron controlled. They're Ferraris. They're very, very fast moving. You think about, work, for example, in the Midland Basin, where we're drilling, eight, nine, 10-day wells. We drill four wells on a pad and we move. Rig move time is very, very important to the customer. They have their advantages. The customers that love them, and we're just giving them an opportunity to love them even more, but we have to get paid for it. Absolutely. That's a great color. One more, if I could. Sure. Anthony, I know you mentioned that you're not expecting a mass exodus from Haynesville. 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 to transfer rigs between Haynesville to the Permian? No, we haven't. We haven't yet, Dave. You know, one of the things that Philip and I are looking at, for example, is trucking cost. If, if we were gonna see a mass exodus of rigs out of the Haynesville going to the Permian, you would expect trucking to become tighter and the costs to go up. In fact, we were talking right before the call, the latest rounds of bids, the costs are actually less than the one 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 exodus of rigs out of the Haynesville. That's perfect. Thank you very much. Mm-hmm. The next question comes from David Marsh with Singular Research. Please go ahead. Thank you for taking the questions. Good morning, guys. How are you? This is David Marsh from Singular Research. Morning, Dave. Thank you. Quickly on, you know, 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. You know, as the numbers come in and leverage continues to decline, would you potentially take another look at that and maybe revisit rates on that agreement? On the ABL? we could, yes. Certainly, we're always gonna be looking for opportunities to reduce our costs. Right. I mean. 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 0 here this year. That's not gonna be a significant cost to us going forward. I've 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? Yeah. The converts are closely held by two holders. The indenture wouldn't allow. We would have to negotiate that with, you know, with the 2 holders. Got it. Got it. 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. Don't know whether they're gonna accept those or not. It's at their option, but we do make those offers to them beginning in June of this year. Mm. We're certainly hopeful they're gonna accept the redemption offer, though. I guess. 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. You know, the sooner we can make progress, certainly on a net debt basis, we're gonna do it anyway, but the sooner we can make progress in actually taking out notes, the better in my mind. Right. Absolutely. Well, congrats again on the quarter and good luck going forward. Sounds like you guys are on a great path. 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- Yeah. Spot market exposure. Yeah. Can you talk about the impact of rig transitions to the Permian and how that'll impact rig pricing as you look into 2023 and 2024, I'm sorry, third and fourth quarter when you're pretty much exposed to the spot market? Yeah. You know, we made the decision in the 2nd quarter of last year to put some backlog on the books, as you might remember, Jeff. We did that. 4th quarter was about positioning our contracts to take advantage of what we thought was gonna 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 1-year contract opportunities out there right now. It's more 6 months or pad to pad, which, you know, is fine with where the market is and what we're doing. We think it's gonna take 2 quarters for this to shake out. I think where you see the next inflection point is gonna be in the fourth quarter around 2024 CapEx programs as our customers begin to execute on those. It's just gonna kind of move sideways here for the next couple of quarters. You look at where we are today in terms of margin generation, the guidance that Philip's provided as well, this is still gonna be a pretty good year for ICD. It's gonna be good from an EBITDA perspective, but more importantly, from a free 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 gonna happen this year, tells you the 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 in the company. All that's is actually being accelerated as this year's playing out. When you move rigs to the Permian. 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? 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 Haynesville and that, you know, that's gonna happen here in the second quarter. Our goal would be, as we finish the one contract in the Haynesville, we wanna have a contract in the Permian that hopefully we're able to move pad to pad. 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. Lastly, is there much of a margin difference between operating rigs in the Permian versus the Haynesville? It, we think there's a little bit of a margin improvement, when we work in the Haynesville. You know, it's a function of longer wells in terms of duration. You're on pads longer. You know, some things like that, but it's not significant. Okay. Thank you. Yes, sir. Thank you, Jeff. The next question comes from Richard Ryan with Oak Ridge Financial. Please go ahead. Thank you. Richard, how are you? Congratulations on a good quarter. Say, most of the questions... Thank you. -have been asked. 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? Does that allow you any flexibility on discussing terms for, you know, these new contracts? On the first point, you gotta remember, Richard, 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-by-four configuration, the whole bit. Because of the market tightness, they weren't able to. That, that's a very logical and obvious target for, you know, the rigs that we're bringing over because they meet the, you know, what I just described. Mm-hmm. no. Yeah, if you recall, the only way you could get a, you know, in the fourth quarter to get an additional rig was to take a rig out of stack or reactivation. You know, all of our intelligence and what we're seeing is that's an $8 million-$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, weren't willing to sign a year or longer contract that would require that. Obviously those opportunities, they now have an opportunity to take a rig that maybe they didn't have a chance to take before. Obviously, after the market settles, if the rig count does tick up again, we'll be back. If they need incremental rigs, they're gonna have to come back out at, you know, from reactivations, and we'll have to see when that occurs. Richard, I would also add, you know, our marketing team, Scott and Mark, they do an amazing job. Some of the opportunities that we're contracting today with the rigs coming out of the Haynesville are opportunities that you wouldn't see on any active customer chart. 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. 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. 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. Okay, we go to them with a sister rig, like what's already there. We've been able to execute that here in the first part of the year. Like I said, it's kinda churned in the basin, so you won't see it. As we look out over the next couple of quarters, we're gonna look to try and create more of those kind of opportunities like that. We're in some pretty good discussions right now around those opportunities. Good. Okay, great. Thank you, and congratulations. Thank you so much, Richard. The next question is a follow-up from Jeff Robertson with Water Tower Research. Please go ahead. Thanks. Anthony, you mentioned the refinancing window for the PIK notes. 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? 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 Notes in place about this time last year. We wanna build cash, and we're gonna 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 defeasance period. You wanna say that? Yeah. That, that period begins in September of 2024. we're... Yeah. There's a make whole under the terms of that. 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 would it make economic sense. As you move closer to maturity, it gets cheaper. 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. Also depends on what the note holders are interested in doing as well. As far as the terms of the indenture, it's begins September of 2024, and then, that's when the window opens up. There's a make whole, so it's pretty expensive at September, and it gets cheaper as we move closer to maturity. Yeah. Jeff, I would just add, I mean, I'm so glad that we're able to give Philip 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. You know, I hope what everybody's taken away from this call is that, you know, this is gonna be a pretty good year for ICD. You know, maybe not the year that we all thought three or four months ago, when you think about, you know, making sure we're 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 gonna be a pretty good year toward making that progress. Yeah. looking at slide 27 and the deleveraging profile, just in terms of the leverage ratio, as you transition rigs is 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 wanna 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 excited about 2023. Looking forward to updating you on our progress when we report our first quarter results here pretty soon. Until then, we wanna wish you all safety and success in 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-