Good day and welcome to the Independence Contract Drilling, Inc fourth quarter and year-end 2023 financial results and 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 a touch-tone phone. To withdraw your question, please press star, then two. Please note this event is being recorded. I would now like to turn the conference over to Philip Choyce, Executive Vice President and Chief Financial Officer. Please go ahead. Good morning, everyone, and thank you for joining us today to discuss ICD's fourth quarter 2023 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 at the SEC. In addition, we refer to non-GAAP measures during the call. Please refer to the earnings release and our public filings for our full reconciliation of net loss, adjusted net loss, EBITDA and adjusted EBITDA, and for definitions of our non-GAAP measures. With that, I'll turn it over to Anthony for opening remarks. Hello, everyone. Thank you for joining us for our fourth quarter 2023 earnings conference call. During my prepared remarks, I'll talk about the current Super-Spec rig market and progress we've made on some important strategic initiatives. Also, I'll close out by talking about our plans for 2024. But first, just a few comments looking back on the fourth quarter and full year in which ICD achieved some meaningful accomplishments. Most important, we continued our fleet evolution towards 300 series specification, and this trend was turbocharged in the back part of the year. To provide some context, we initiated our 200- 300 series conversion program about 18 months ago, and at the beginning of 2023, we had completed only one conversion and only 50% of our operating rigs met 300 series specification. Since the beginning of 2023, however, we have transformed our operating fleet. Today, 90% of our operating rigs meet 300 series specifications, with five conversions having occurred since September 1st. Today, all but one of our former 200 series rigs operating today is a 300 series rig budgeted for the remaining 200 series rig to be converted later this year, depending on customer requirements. I'd be remiss if I did not point out that we have received full cash payback or more during the initial contract term on the CapEx required for all of our 200 - 300 series conversions to date. This fleet transformation paid significant dividends for ICD in 2023 as we navigated a severely depressed Haynesville gas market and an overall decline in the Permian rig count as well. In fact, as of today, we've increased our Permian rig count by over 40% compared to the beginning of 2023, even while the overall rig count in the basin declined 15%. Along with our reputation for operational excellence and customer service, our ability to efficiently execute our 200 - 300 series conversions drove this significant market outperformance. As we enter 2024, our conversion strategy is continuing to pay dividends on contract renewals and extensions. For example, we just executed several multi-year contract extensions with one of the Permian's largest operators and signed another term contract with a new Permian customer. The majority of these contract extensions involved 300 series rigs that were converted by us in 2023. In 2023, we also began to take advantage of the part paydown opportunity in our indenture by paying down a total of $15 million worth of convertible notes, including a $5 million paydown in the fourth quarter. We have mentioned in the past that positioning the company for a potential refinancing of our convertible notes is a high priority for us. As you may have noticed in our press release today, although our convertible notes do not mature until March of 2026, the refinancing window for these notes will open later this year, and we have appointed a special committee of independent directors to proactively begin the process of reviewing and evaluating opportunities regarding the notes and any other strategic opportunities that can be considered in connection with that review. Moving on to our fourth quarter results, Philip will provide more details during his prepared comments, but I wanted to make a few. While our margins came in on the higher end of our guidance, our overall results came in at the low end almost entirely due to higher rig reactivation expenses, much of which was related to higher labor and related expenses originally earmarked to perform maintenance and upgrade CapEx on rig reactivations that ultimately did not materialize. The offset, of course, is that outlays for CapEx during the fourth quarter was only $2.7 million. Now I'd like to talk about the market for Super-Spec rigs and our target markets, including what we are seeing from a day-rate perspective and what has changed from our last conference call. Obviously, our Permian market has held up pretty well based on ICD's increased rig utilization in that basin, but let me begin with our gas-directed Haynesville market. It's no secret that the Haynesville market was severely depressed throughout 2023, but early in Q4 of last year, as we entered the winter season, we started to see some small opportunities for rig adds in 2024. Unfortunately, the combination of further declines in commodity prices driven by a very warm winter has paused these opportunities. With these factors combined with DUC inventory builds in the area and customer consolidation, our expectation today, unfortunately, is for further decline in the Haynesville rig count overall and for ICD. We had three rigs working in the Haynesville at the beginning of this year. However, two of our customers with whom we were anticipating contract extensions notified us that they were not going to continue their programs. We've already relocated one of these rigs to West Texas, including completing a 200-300 series conversion during the rig move and placing it on a six-month contract with a new customer, all with zero off-rate time. While movement of this rig did cannibalize an opportunity we previously had earmarked for an incremental rig add, the rig is performing exceptionally well, and we feel we have a very good opportunity to add a second rig with that customer later this year, assuming their plans remain in place. With the second Haynesville rig, where we received notice, we have been successful in placing that rig on a follow-on opportunity with a different customer, but it is a short-term program, and we are continuing to market the rig for follow-on opportunities. The takeaway of all this is that we expect to run two or so rigs in the Haynesville for the foreseeable future and are scaling our operations accordingly. Our West Texas market, on the other hand, has held up much better, and we obviously have been successful in adding rigs across our customer base and increasing term contract exposure where it makes sense. We currently have 14 rigs running in West Texas. However, capital discipline and increasing consolidation of E&P companies kept a lid on the overall rig count in the Permian Basin during the second half of 2023, and all indications today are for a flattish overall rig count in the Permian during the first half of this year. We also expect continued elevated churn and rig movement within this overall flat rig count driven by a rebalancing of fleets following the closings of recent E&P consolidation transactions. Thus, incremental rig adds for ICD in the Permian are going to be predominantly directed toward high-grade opportunities displacing lower spec and/or underperforming competitor rigs. These opportunities are very competitive, but so far, we have been successful in winning more than our fair share. In light of the flattish rig count overall at around 600 rigs, day rates in general have moved sideways, which is what we expect for the first half of 2024. Day rates and daily margins for Super-Spec rigs are still healthy, but obviously lower than they were a year ago. This is more pronounced for incremental rig adds with new customers, for example, compared to when we renew or roll over a contract with existing customers. As you might expect, there's more day-rate pressure in the Haynesville than in the Permian. Spot market day rates on competitive awards can be up to $2,000 per day lower than rollover rates, owing to efficiencies earned and friction costs of changing out rigs that are performing at today's required level of performance. Day rates in the Permian for our 300 series rigs have remained stable in the low $30,000 range, and for our remaining 200 series rig, the high $20,000s. There are some competitors bidding rigs at day rates less than this, but the largest providers have held up their pricing, which is helpful. We continue to earn full cash-on-cash payback over the initial contract for any CapEx associated with a 200 - 300 series conversion. In light of this backdrop, our strategic operating objectives and priorities as we move forward are as follows. While we still believe we can return to a 21 operating rig fleet, that goal has been pushed to the right in light of the market dynamics I just described. During the first half of 2024, our priority will be to navigate the increased churn and choppiness we are seeing in the Haynesville and from customer consolidation in the Permian and focus on maximizing utilization on the rigs we currently have operating as we expect to deal with some rig movements here in the first half of this year as the effects of lower gas prices and customer consolidation and capital allocation priorities work their way through the system. Beyond that, I expect we will see opportunities to grow our Permian Basin presence as this year plays out, as the benefits of our 300 series rigs and our 200 - 300 series conversion program combined with our ICD Impact offerings continue to bring new customers into the fold and allow us to expand existing customer relationships. In the face of a likely flat overall Permian rig count in the near term, we will likely need to continue to punch above our weight class to drive incremental rig reactivations, but I think we've shown that we're more than able to do that. Obviously, if the Permian rig count moves upward sooner, that will only increase our opportunities for rig reactivation and margin improvements in the first half of 2024. As I mentioned, given further declines in the Haynesville, we don't see recovering that basin until mid-2025, given the very warm winter, which is winding down, large gas storage levels, significantly lower net gas prices, and the DUC inventories which E&P companies have assembled. But we are leaving the door open for an eventual return when market dynamics in that basin turn more positive for drilling contractors with strong brands and reputations in the challenging operating environment which the Haynesville presents. So rolling all this up, I'm confident that ICD is ready for the year which has now started. Overall CapEx budget net of disposals for 2024 has been set at $18.2 million, and we have set our cash SG&A budget for fiscal 2024 at $15.3 million, both reflective of a flatter operating environment which we are now experiencing. I'll make some additional concluding remarks before opening the call up for questions, but right now, I want to turn the call over to Philip to discuss our financial results and financial outlook in a little more detail. For the fourth quarter of 2023, we reported an adjusted net loss of $8.6 million or $0.61 per share and adjusted EBITDA of $9.9 million. In calculating adjusted EBITDA and loss per share, we excluded $600,000 associated with non-cash SG&A marketing expense during the quarter, which related to an amendment to some contractual assets. We also excluded $14.7 million associated with a non-cash impairment charge. The impairment charge relates to idle equipment that we do not believe will be usable in the company's fleet of 26 marketed rigs on a go-forward basis, as well as capital spares that will be disposed of in connection with efforts to consolidate the company's yard locations. During the quarter, we operated 14.9 average rigs in line with our prior conference call guidance. Margin per day during the quarter came in at $12,313 per day at the high end of guidance. However, as Anthony mentioned, reactivation costs of $2.1 million exceeded guidance from our last conference call, and there were no early termination revenues during the quarter. SG&A costs were $5.7 million during the quarter, which included approximately $1.8 million of stock-based and deferred compensation expense, as well as the non-cash operating expense I previously mentioned. Cash SG&A expense during the quarter was $3.9 million, relatively flat with the third quarter and in line with guidance. Interest expense during the quarter aggregated $9.8 million. This included $2.6 million associated with non-cash amortization of deferred issuance costs and debt discount, which we excluded when presenting adjusted net income. Tax benefit for the quarter was $900,000, and during the quarter, cash payments for capital expenditures net of disposals were approximately $2.7 million. Moving on to our balance sheet, we paid $5 million of convertible notes at par at quarter end. The overall adjusted net debt during the quarter was reduced by $4 million. Our financial liquidity at quarter end was $26.2 million, comprised of cash on hand of $5.6 million and $20.6 million of availability under our revolving credit facility. Now, moving on to guidance for fiscal 2024 and the first quarter of 2024. As Anthony mentioned, we have set our capital expenditure budget at $18.2 million net of disposals for 2024. This includes completion of a 200-300 series conversion on the lone 200 series rig we have operating today. The budget is based upon 17 operating rigs in the near term. As Anthony mentioned, we're expecting a relatively flat operating rig count for at least the first half of 2024. We would expect to adjust our capital budget upward on any incremental rig adds that increase our operating rigs above 17 earlier than these expectations. I would note that due to white space created by rig churn, our reported average operating day during a particular quarter will likely be below 17 until we begin reactivating additional rigs. We have set our cash SG&A budget for 2024 at $15.3 million. This is a reduction of approximately 8% compared to fiscal 2023 and represents consolidation of various corporate functions that occurred early in 2024. Non-cash stock-based compensation during 2024 is expected to be approximately $5 million, but much of this is tied to variable accounting that is driven by increases or decreases in relation to our stock price at period's end. We are budgeting interest expense in 2024 to approximate $30 million. In addition, we expect to recognize $12 million of non-cash interest expense associated with amortization of debt discount and offering costs. And finally, we expect our effective tax rate in 2024 to be approximately 5%. Now, moving on to more specific guidance for the first quarter of 2024, we expect operating days to approximate 1,343 days. We expect margin per day to come in between $10,400-$11,000 per day with a sequential decline relating to lower day rates on contract renewals. Breaking out the components, we expect revenue per day to range between $30,100-$30,400 and cost per day to range between $19,300-$19,600. Based upon cost efficiency initiatives instituted at the beginning of 2024, we are expecting positive trends in our overall cost per day compared to 2023. Unabsorbed overhead expenses will be about $800,000 during the quarter, and we've excluded those expenses from our cost per day guidance. This includes approximately $200,000 associated with relocating rigs from the Haynesville to the Permian. We expect first quarter cash SG&A expense to be approximately $4.4 million, which includes severance costs of approximately $400,000. Cash SG&A during the year is somewhat front-loaded due to year-end professional fees. Similar to our expectations around cost per day, we are expecting positive trends in our cash SG&A expense in future quarters based upon cost efficiency initiatives instituted at the beginning of the year. Stock-based compensation expense for the quarter should approximate $1.4 million, assuming no material changes to our stock price that would impact variable awards. For the first quarter, we expect interest expense to approximate $10 million, and of this amount, approximately $2.7 million will relate to non-cash amortization of deferred financing costs and debt discounts. Depreciation expense for the first quarter is expected to be flat with the fourth quarter, and we expect our tax benefit during the quarter to be de minimis. With that, I'll turn the call back over to Anthony. Thanks, Philip. So wrapping all this up, I believe ICD performed very well last year as we navigated many challenges successfully. In the process, we grew our Permian Basin presence, and we were able to expand some key customer relationships and attain some new customers, all the while delivering world-class performance, including industry-leading HS&E results. We continue to make progress on the three most important strategic initiatives we have, which include paying down debt, increasing our exposure to the 300 series market, and leveraging our ICD Impact offerings. So with that, we'd like to take your questions. Operator, please open up the line for Q&A. We will now begin the question and answer session. To ask a question, you may press star, then one on your touch-tone phone. If you're using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star, then two. Our first question comes from Steve Ferazani with Sidoti. Please go ahead. Good morning, Anthony. Philip, thanks for all the color on the call. Just first, just so I can clarify the guidance, it sounded like you were setting CapEx based on 17 operating rigs, but it sounds like your guidance for Q1 is probably slightly less than 15 given some white space. Can you sort of connect the two? Yeah. When you look at our fleet, Steve, this is Philip. We've got 17 what I call hot rigs. There's about three or four of them that really are moving around on us right now. There's a couple in the Haynesville, as Anthony talked about in his prepared remarks. We've got one I would characterize as caught up in the consolidation that's gone on where the customer's going to, we're moving that around. And then you always have one. We've got one. So there's four or so rigs that we're moving around right now. So there's 17 hot rigs. And so that's really why the difference between the average rig count in the quarter and what we're dealing with as far as actual rigs moving around. That's helpful. When I think about how you're seeing 2024 play out, and we know that the warm winter, obviously, had a significant impact on the Haynesville, but in general, you're talking about day rates being somewhat sideways. What's your risk level to that given if the Permian at best flattish through the first half? I think it's a good question, Steve. The risk, I mean, obviously, day rates could go higher. It could go lower. But we've been in this kind of pattern for the last three or four months where rig counts more or less move sideways. U.S. land rig counts around 600. It's up five. It's down five. This and that. Pricing has been pretty steady and also pretty level during that same period as well. Where we've been able to add, such as out in the Permian, it's been more on rig spec and capability as opposed to being the low bid, for example. So I feel pretty good. I I feel pretty confident about the margin guide. The message I think we've tried to convey is we think here in the first half of the year, it's flattish. We're optimistic about the back half of the year. That's how we think about it. Feel pretty good about it. Okay. That's helpful. Steve, I might add. I mean, okay. I might add just if you're looking from fourth quarter to first quarter, we don't have all of our legacy contracts that were at higher day rates signed back when the market was stronger. Those have all expired or rolled over. Yep. You highlighted the fact that, obviously, the Permian was softer in 2023, yet you were able to move a lot of rigs there from the Haynesville and win contracts. What's your ability in this environment? Because clearly, you've had the ability with the 300 series rigs to displace other rigs. Is that harder now? No. I think, obviously, we need the programs to continue. We need to have a long enough rig line in front of us for the customer to justify kind of the friction of changing a competitor out. But I think it's why you've heard us pound the table now for going on two years about the need to continue to evolve our fleet toward the 300 series spec because in this environment we're in now, the laterals are getting longer. Our customers are more interested today in evaluating and adopting technology. That's why the stuff we've been doing in the background that we refer to as ICD Impact is so important. And I think we've proven, certainly over the last year, that we can increase our utilization. In some cases, that's coming at the expense of a competitor's rig. But I mean, that's how I think about that. So to the extent the rig lines continue, we've proven our ability to do that, and our expectation will continue to be able to do it. It won't happen as fast as any of us would like, but we'll continue to chip away at it. Thanks, Anthony. Thanks, Philip. Thanks. The next question comes from Don Crist with Johnson Rice. Please go ahead. Morning, gentlemen. How are y'all doing today? Great. Good morning, Don. Anthony, in the press release, you talked about tech packages on about half of your rigs. Can you remind us what kind of uplift that gets you, and is there opportunity to kind of expand that across the rest of the operating fleet if it's about half today? Yeah. I do think there's opportunities to continue to expand it. Don, been very pleased with what we've been able to do so far. If anything, that number may be understating what we're actually doing when you think about all of the tools that are out there. But the adder, the most important part of the adder would be the margin uplift anywhere from $200 a day to, in some cases, a little higher than that. So I could see someone say, "Well, look, the other company over there is charging a couple thousand." Well, that other company's got a lot of capital invested in that. Our strategy has been to be a very fast-second mover here to partner with people that probably know more about the intricacies of it, the IT part of it than we do, that have been working on this in some cases for more than a decade, and leverage their capability, combine it with the AC pad optimal Super-Spec rig, which we have, and deliver value working together to our customer. So like I said, we probably aren't able to bring as much to the bottom line or to the margin per day as some of our competitors, but we've essentially got very little invested in this. Right. And on the contracting side, it sounds like you've signed a couple longer-term contracts here in the last couple months or so. But are you getting significant inbounds from the people that you're working for today to kind of term up for two or three years? And what is your willingness to do that today? Yeah. We're not getting a lot of inbounds. In this particular case, it was a very important strategic client for the company. They did approach us, asked us what our thoughts were around that. And as we sat here and thought about the next year or two and some of the things that we have to get done, especially around addressing the convertible notes that aren't going to mature until March 2026, we felt that it would be good and prudent for the company to put some backlog on the books. And I mean, there's a couple of two-year contracts in that mix, just so you know. So I think we made the right decision. Didn't have to get, in fact, the day rate on the longer term, the two-year term, was higher than the spot market rate. So I hope we're in a situation where a year from now, we feel like we left some money on the table because that's going to be really good for the industry and certainly is going to be good for ICD. But yeah, we did it. And we would continue to evaluate it, especially as we navigate 2024 and start to chip away at some of the stuff we've got to get done. Okay. One final one for me. One of your major competitors at a conference last week talked about some strength maybe in the fourth quarter in the gas basins, but it sounds like you're not really seeing that in the Haynesville. Is it kind of just splitting hairs there, or do you think that there could be some uplift in the fourth quarter in the gas basins as we move forward? Obviously, that'll be dependent on the strip as it progresses through the year, though. Yeah. Maybe he or they have spent more time on it than we have. I'm just looking at it at a very high level, Don. And what I see with inventory levels, the ability to liquefy and export gas, you look at the DUC inventory levels as well. It's just hard for me to see where there's going to be any real pickup until we get into the middle part of next year. I think we've got to work through winter of 2024 rolling into 2025, I think, as the strip moves up. What a lot of our customers are going to do is they're going to reach into their inventory of DUCs and complete them. And then they're going to have to replenish those. So that's why I may be a little bit more bearish on that. Longer term, still very bullish on gas, U.S. gas, what it's going to do for society, what it's going to do for our country in terms of energy security, energy transition, and all of that. Just I think the next 12-18 months are going to have some headwinds. I appreciate all the color. Thanks, guys. Thank you, Don. The next question comes from David Storms with Stonegate Capital. Please go ahead. Good morning. Morning, David. Good morning. Just hoping we could start. Last quarter, we talked about some of the smaller contractors kind of pulling pricing down a little bit. There was a comment around their capacity hopefully drying up through this first half of the year. Just curious if you saw that come to fruition and kind of where you see pricing going from here in relation to the smaller contractors' capacity? Yes. I think the last time we talked, Dave, we were pretty optimistic about the rig count actually starting to increase as we exited 2023 and then in the first half of this year. Two things have occurred since then. One, the rig count has been flat, and there's all kinds of reasons for that. And then I think also the churn that's being created as a function of the M&A that's happening among our customers. Those two things, flat rig count and then the churn, have created a situation where we thought more of our smaller competitors' rigs might get soaked up in an increase. Obviously, that's not happened, so it's still there. Good news is you do see a bifurcation in pricing. You've got the big three that are doing a really good job at standing their ground. It gets a little bit more competitive below that. But we have seen to have landed at a floor in terms of pricing. We've not seen any real movement on spot market pricing among that group the last few months. But where you see that impact ICD in our margin per day is that as our rigs have rolled off of legacy contracts at higher day rates, they've had to reprice into a spot market that is a few thousand dollars a day less. And that's what you're seeing reflected in kind of how we're thinking about the first half of this year. Understood. Very helpful. And then just one more from a more macro level. Are you seeing any demand fluctuations in relation to the Canadian Trans Mountain pipeline and the impact that that's expected to have on the North American energy segment? Not in the lower 48. I don't follow the Canadian market, but my understanding is they're busier up there than they've been in a long time. It's very good for them, but I'm not aware of any impact. We're not working in the Bakken anymore, so I don't have a good feel for what's happening up there. That would be an area where maybe they might see some uplift and benefit from it. But in the lower 48, especially in our target markets, I'm not aware of any impact. That's perfect. Thank you for taking my questions. Sure. This concludes our question and answer session. I would like to turn the conference back over to Anthony Gallegos for any closing remarks. Okay. Great. Thank you, sir. I'd like to close out the call. I want to say thank you to our many employees at ICD for their hard work and dedication. Also, I want to say thank you to our customers for their business, and we'd like to thank you for taking the time today to participate in this call. With that, we'll sign off from here. Thank you. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.