Good day, welcome to the Independence Contract Drilling's second quarter 2023 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 than one on your telephone keypad. To withdraw your question, please press star than two. Please note, today's event is being recorded. I would now like to turn the conference over to Philip Choyce, EVP and CFO. Please go ahead. Good morning, everyone, and thank you for joining us today to discuss ICD's second 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 complete discussion of these risks, we encourage you to read the company's earnings release in our documents on file at 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 second quarter 2023 earnings conference call. During my prepared remarks today, I want to talk about the following. First, I want to highlight some significant steps we took during the second quarter toward important strategic initiatives. Second, I want to update you on the transition efforts around our Haynesville fleet, which are essentially complete. Third, I want to talk about the current market for super-spec pad-optimal rigs and how ICD is performing. Lastly, I want to close out talking about some things we're doing to position ICD for the future. First, just a few comments on the quarter. Overall, ICD's second quarter results came in ahead of expectations in terms of revenues, margin per day, and adjusted EBITDA. I'm particularly pleased with how reported margin per day held up in the face of market headwinds, driven primarily with our Haynesville market, buoyed by sequential improvement in reported cost per day. Overall adjusted EBITDA came in at $18.7 million. During the second quarter, we took the first step in the most important strategic initiative for our company, which is delivering our balance sheet. I feel this way because in addition to delivering industry-leading service and professionalism to our customers, reducing the debt level of our company is the most impactful action we can undertake. During the quarter, we redeemed $5 million of convertible notes at par and also reduced revolver borrowings, while at the same time improving our net working capital position. I'm pleased that we were in a position for our lenders to accept our offer to redeem $5 millions of our convertible notes at par at the end of the second quarter. During the second quarter, we essentially completed our fleet geographic rebalancing process. As a reminder, ICD started 2023 with 10 rigs working in the Haynesville market and 10 rigs working in the Permian. We were more levered than any other drilling contractor to the Haynesville, and in light of the softening we saw early this year, we made the decision to relocate several rigs from the Haynesville to the Permian. The choppier Permian market we experienced in the second quarter impacted the pace at which we were able to recontract ICD rigs relocated from the Haynesville. As of today, we have four rigs remaining in the Haynesville, and three of those are currently contracted. Although it is possible that we relocate additional rigs from the Haynesville, depending on how the markets develop over the next 12 months, for the time being, our rig transition program is complete. Overall transition costs, including trucking and crew transition costs, totaled approximately $2.8 million during the second quarter and $3.4 million in aggregate, below our initial estimates of $4 million total. Turning to market conditions in our target markets. The overall U.S. land rig count is down 105 rigs year- to- date through the end of the second quarter. Although the Permian market has remained strong, consistent with our expectations at the beginning of this year, we have seen some softness, resulting in an overall Permian rig count decline of about 11 rigs caused by weaker commodity prices early in the second quarter and the recent banking issues. These factors resulted in some reshuffling of rigs by E&P operators and more rig on rig competition. In spite of all this, ICD increased its permanent contracted rig count by 20% year- to- date in the face of numerous competitive pressures. I think that speaks to the quality of our people and equipment and our strong brand. We remain optimistic about market momentum re-accelerating in the back part of this year, primarily in the Permian, based on recent moves in commodity prices, our customers having better access to credit, current customer inquiries and discussions we are having, and our expectation that WTI will continue to strengthen in the back half of 2023, rolling into 2024. I also think the effects of recharged E&P capital budgets next year will provide additional boost to our Permian market. While we expect some rigs to go back to work in the Haynesville, we believe that gas-driven gas markets will remain challenged for at least the rest of this year. We have, however, seen inquiries for work in the Haynesville pick up over the last couple of weeks. In addition, Permian permitting activity for the Permian in June increased 25% month-to-month, and overall permits for U.S. land year-to-date compared to 2022 are up slightly in spite of the softer commodity prices we saw early second quarter. Based on all this, we believe US land rig counts is finding a bottom as we speak and will begin increasing in the coming months. On the day rate front, current leading-edge super-spec day rates in the Permian are coalescing in the low to mid $30,000 range, including adders. Right now, there are minimal data points for spot day rates in the Haynesville, but I would expect they are just a little bit lower, maybe $1,000-$2,000 a day compared to the Permian. In terms of enhancing our fleet, we are planning some 200-to-300 Series conversions in the back half of this year, one of which is in process in connection with a contract extension into mid-2024, which we just executed for a rig working in the Permian Basin at a mid-$30,000 day rate, including the adders. In this arena, we are seeing customer interest in high torque top drives, iron roughnecks, and drill strings increase as a function of E&P's increasing well lateral lengths and their unrelenting focus on drilling efficiencies. These are trends we expect will continue. Our investors should feel good knowing that the majority of our working rigs already have these capabilities embedded. The rest can be outfitted to have these capabilities with very modest amounts of CapEx. As I close out my prepared remarks, I want to mention our efforts regarding our technology rollout, which we call ICD Impact, which accelerated during the second quarter. Our strategy in this arena has been to leverage ICD's youngest rig fleet in the industry and the years of effort and investment made by our third-party partners by working with their professionals, collaborating with our customers, and applying the knowledge, skills, and insight of our employees. We have technology systems deployed on approximately 30% of our active rigs today, with objectives to improve this percentage over time as customer demand warrants. We are excited about what ICD Impact means for our customers and other stakeholders going forward. I'll make some additional concluding remarks before opening the call up for questions, but right now, I'd like to turn the call over to Philip to discuss our financial results and outlook in a little more detail. Thanks, Anthony. During the quarter, we reported an adjusted net loss of $1 million, or $0.07 per share, and adjusted EBITDA of $18.7 million. We operated 15 average rigs during the quarter. This excludes 2 average rigs earning revenue on an early termination basis during the quarter, and early termination revenues during the quarter were $5.1 million. Moving on to our per-day statistics. These statistics exclude both the early termination revenues and transition expenses. We had a number of rigs moving between customers and locations and our overall operating days fell by an average of 4.4 rigs compared to Q1, we're pleased we saw only minimal degradation in our revenue, cost and margin per day statistics. Revenue per day during the quarter was $34,467, representing a slight decrease from the first quarter. Cost per day during the quarter was $19,005, representing sequential improvement. Overall margin per day was $15,462, representing only a 1% sequential decline compared to the first quarter. SG&A costs were $5.2 million during the quarter, which included $1.3 million of stock-based and deferred compensation expense. These costs declined sequentially by 22% overall. Breaking out the components, cash SG&A expenses decreased sequentially by 21% compared to Q1, due to lower incentive compensation accruals and cost-cutting efforts implemented during the quarter. Non-cash stock-based compensation expense also decreased sequentially, in this case, by 27% due to the effect of a lower quarter end stock price and variable accounting on performance-based stock awards. Interest expense during the quarter aggregated $8.3 million. This included $1.2 million associated with non-cash amortization of debt discount and deferred issuance costs, which we excluded when presenting adjusted net income. Tax benefit for the quarter was de minimis. During the quarter, cash payments for capital expenditures, net of disposals, were approximately $11.5 million. This includes final payments of capital expenditures on rig react on our rig reactivation program, including our 21st rig that reactivated at the beginning of the quarter. There's approximately $5.1 million of CapEx accrued in accounts payable at quarter end. Breaking out our $11.5 million cash payments on CapEx during the quarter, approximately 53% related to rig reactivations and 200-to-300 Series conversions, 35% related to maintenance CapEx, and 12% related to investments in drill pipe, capital inventory, and spares. For the remainder of the year, so when we move towards 18 or so working rigs by year-end, we expect capital expenditures during the back half of the year to aggregate approximately $9.5 million, which assumes two 200-to-300 Series conversions and approximately $1.5 million in tubular purchases. Moving on to our balance sheet. As Anthony mentioned, our strategic focus has shifted from rig reactivations to overall debt reduction. This also includes steady improvements in our working capital position as well. We made progress towards both of these goals during the quarter, where we paid $5 million of convertible notes at par and also reduced revolver borrowings by $5.3 million during the quarter. We were able to do this while slightly improving our net working capital position as well. Adjusted net debt at quarter end was approximately $191.2 million, also a decrease from March. I want to point out our adjusted net debt statistics include accrued interest we have elected to pay in kind on September 30th of this year. Our financial liquidity at quarter end was $19.1 million, comprised of cash on hand of $5.6 million and $13.5 million of availability under a revolving line of credit. This is in addition to the networking capital improvement I just mentioned. Now, moving on to third quarter guidance. We expect operating days to approximate 1,240 to 1,250 days, representing approximately 13.5% average rigs earning revenue during the quarter. This excludes rigs earning revenue on an early termination basis, which will be minimal during the third quarter. We expect margin per day to come in between $14,250 and $14,750, with the sequential decline relating to lower day rates on contract renewals. We also expect some sequential cost inefficiencies during the quarter associated with the lower operating base and reduced operating days. From a contract mix standpoint, the vast majority of our rigs are now operating on short-term pad-to-pad contracts and reflect the current day rate environment. For example, during the third quarter, we expect only 25%-30% of our revenue days to be earned on contracts that were entered into prior to March 31st of this year. Unabsorbed overhead expenses will be about $600,000 and also are not included in our cost per day guidance. As Anthony mentioned, our Haynesville to Permian transition program is complete. We do not expect to incur any transition expenses during the third quarter. We expect third quarter cash SG&A expense to be approximately $4.3 million, with a small sequential increase, primarily tied to expected increases in recruiting and onboarding costs as we begin staffing up for expected reactivations in late third quarter and early fourth quarter. Stock-based compensation expense is expected to be approximately $1.9 million, assuming no material changes to our stock price as of today, that would further impact variable awards. We expect interest expense to be approximately $9.5 million, and of this amount, approximately $2.4 million will relate to non-cash amortization of debt discount and deferred financing costs. Depreciation expense for the third quarter is expected to be flat with the second quarter. We expect tax benefit to be flat with the second quarter. With that, I'll turn the call back over to Anthony. Thanks, Philip. Before opening the call up for questions, I want to briefly summarize where we are as we enter the second half of 2023. While this may not be the year that we thought it would be, 2023 is proving to be a very important year for ICD. Initiating our efforts to deleverage our balance sheet, repositioning our rigs to a more appropriate geographic positioning and balance, and executing on our technology pathway are all very strategic initiatives which are happening. These initiatives will provide value to the stockholders, customers, and employees of ICD in the coming years. I would like to thank our many operations, support, and corporate team members who work hard every day to deliver high levels of safety, performance, customer service, and professionalism, which our customers expect from ICD and which we expect of ourselves. 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 touchtone phone. If you are using a speakerphone, we ask that you please pick up your handset before pressing the keys. To withdraw your question, please press star then two. We'll pause momentarily to assemble our roster. Today's first question comes from Don Crist at Johnson Rice. Please go ahead. Good morning, gentlemen. How are you all today? Doing good. You, well? I wanted to explore the topic of adding rigs back in, you know, late third quarter, fourth quarter, and possibly into 2024. You know, we've heard several anecdotes from other companies and just wanted to get your take on what gives you confidence. Are there, you know, significant tenders that are out there today, or are they just conversations today? Certainly, Don, the nature of the discussions with customers has changed over the last couple of months. I think, you know, obviously, strengthening commodity prices have helped. You know, the macro picture in the U.S. and what's happening there, I think have helped. I think those things, along with some others, have given some customers some confidence that, you know, they can step back in and add. You know, just to give you a little transparency, you know, we're not doing a lot of work today for the supermajors. We do work for the independents, and we do a lot of work for privates as well. And it's in that last bucket where we've probably seen the most change over the last couple of months, with the private E&Ps. Remember also, you know, they were the first ones about a year ago, to start laying down rigs. They kind of sat on the sidelines the last few quarters, I think as we look out over third and fourth quarter, for us at least, that's where we see opportunities, to bring rigs up. Just to take that a step further in the Haynesville, are you getting into conversations now, given that the 24 strip is over $3, to actually add some rigs back in the Haynesville? I know that's not going to be a priority since you moved a lot of rigs out of the area, is that market starting to see some tightening versus loosening over the past several quarters? Yeah, certainly over the last couple of weeks, Don. Those discussions have also picked up as well. You know, we bottomed out at two of the four rigs that we had earning revenue there. We're at three today. Pretty optimistic the fourth one will go back to work before we talk to you guys again. Rig count over there has bottomed out at around 44 rigs. That's down from mid-70s, so quite a drop. Strip has moved. I was looking at it earlier this week, and, you know, you look out past October this year, it's above $3, and in January, it's over $3.70. That's, you know, what we hear from customers is, you know, $3.25, $3.50, they're thinking about growing. We're pretty optimistic about being able to put that fourth rig to work, probably in the third quarter. I appreciate that color. Just one final one for me on the conversions. Are those customer-driven conversions from 200 -to-3 00 Series? How many more of those do you think you could do, over the next couple, several quarters? Yeah, it's been great. I'm really proud that we were able to sign this second one up. In both of the instances, they were customers that were using our 200 Series rig, it's doing a great job for them. Obviously, they were very happy. You know, our customers would like maximum flexibility as they look out over the coming quarters and coming years, to be able to take a rig and work across the spectrum of projects which they have. In both cases, the operators, the customers were very supportive of the conversion to 300 Series capability. I would point out in both cases, we were able to, you know, we're going to earn a premium day rate relative to what that rig would have earned had we not converted it. You know, this will be the second one that's in motion as we speak. You know, we have a handful more that we can do. We have some kits on the ground. You know, our strategy is to use those kits when there's opportunities to earn that incremental payback over the course of the contract, and we've been able to do that now twice. It's, flexibility for us. You know, when we talk about our 200 Series rigs, they're super-spec, they're pad-optimal. They're, you know, they have all the bells and whistles that the standard super-spec pad-optimal rig has. As the unconventional play, continues to play out, as the laterals continue to get longer, you know, if our customers need that added capability, we have the flexibility to be able to offer it. I appreciate all the color. I'll turn it back. Thanks. Thank you, Don. Thank you. Our next question today comes from Stephen Ferazani with Sidoti. Please go ahead. Afternoon, Anthony, Philip. Regarding your commentary around day rates, in the Permian, and then your guidance for, for margins going into 3Q, it sounds like day rates might be coming down a little bit, but certainly not necessarily significant, given how much rig count has, has dropped. What are you seeing in day rates, and are the conversations getting harder? Yeah, day rates have softened some, Steve, but just to put it into perspective, when you look at what's happened year- to- date, the Permian market is only off a dozen or so rigs, at 4%, since the beginning of the year. There has been some trimming, as you guys know, but there's been some people that have added some rigs as well. There's a lot of churn in the background that you know, you don't have the insight into. Regardless, you know, day rates have obviously held up pretty nicely. You know, when you look at the margin per day that we just reported, very proud of that. And we're guiding down a little bit as we think about Q3, and we're, we're saying Q4 is going to be flat with Q3. If you think about that, especially on a historical basis, for these kind of margins, you know, that's really good. It's another reason why we're very optimistic about what the next several quarters are going to allow ICD to do on those big, important strategic initiatives that we have underway. What's your confidence level now in getting some rigs back to work in Q4? Very high. Yeah? Okay. Very high. We're, going to bring out, I think it's 3 minimum before the end of the year. Really? Yeah, they'll probably happen sooner rather than later. Excellent. Any kind of color you can give around the early termination with those rigs in the Haynesville, and did they have a lot of term left, given the $5 million? One is still on contract, on standby, in fact, through November of this year. The other one, its early term, provision ended here about 10 days ago. Of, of the three rigs that we have working in the Haynesville today, you know, only one is sitting there earning standby. The other two are on a day work basis. Yeah, the $5.1 million, it was really three rigs, and pretty much all of it, it ended by the end of the second quarter. Okay, great. It took a lot of costs out here, obviously helped out a lot. How much of that do you think comes back with getting those rigs back to work? Was that a lot of very temporary cuts, or was there anything you took out that could be permanent? On the SG&A side, some of it in the second quarter clearly was, we weren't in hiring mode, we'll go back to that. So when you think about the sequential guide up from the second quarter to third quarter, that's what we're really talking about there. There's probably about $1 million in SG&A that I would consider permanent, which is really some headcount, type of things that we've done and some other efficiency, things that we've put in. Then on the operating side, that's really temporary from the standpoint of operating costs. Those are going to go up and down. Right As the rig count goes up and down. We will have some choppy, you know, when you talk, the earlier question on margins, you know, part of the guide down is not all day, right. Some of it's we're going to be, you know, it's going to be a choppier third quarter as we put rigs back to work and things like that. There's going to be some churn, and that does affect your cost per day statistics. Understood. Perfect. Thanks, Anthony. Thanks, Phil. Yes, sir. Thank you. Our next question today comes from Dave Storms with Stonegate Capital Markets. Please go ahead. Good morning. Morning, Dave. Morning. Just hoping you could touch on, you know, some of the banking issues that you mentioned, that were seen in the quarter, and looks like most of them have kind of cleared up. Do you see any potential for any of that to kind of rear its head again, either in the next quarter or further on down the line? Yeah, so what I was referring to was really access to credit on the part of our customers. You know, you think, you guys know better than I do. You think back to what was playing out in the second quarter, with especially around the regional banking crisis, redeterminations around credit lines and stuff like that, just, you know, we think those issues, while they're, may not be completely resolved, we think they're better today than they were in early second quarter. You know, one anecdote I would give you guys is, you know, we were verbally awarded a program back in March. It's a big program out in the Permian, but it's a private E&P operator. You know, March for a May start, well, May slipped to June, it slipped to July. Well, now, you know, we're in the process of papering that up. What's changed is the financing side of the project for the customer. That's an anecdote that I would share with you guys. It's just my understanding and view that I think our customers will have more access to capital, which, you know, when we talked about the reasons why commodity prices, other things like that are going to help drive that. That's very helpful. Thank you. Then the other thing you mentioned, just around rig counts, finding a bottom with the increase expected in the coming months. Can you just help us get a sense of when that demand does come back, the breakout between, you know, the demand for 300 Series rigs versus 200 Series rigs? Yeah, we're bottomed out in the, I think, 660 is where we are right now. Maybe it goes to 650. When you look at, you know, where the rig count rigs are working in rig count, about half the rigs are working out in the Permian. You know, we would expect that percentage to continue and even grow. You know, out in the Permian, there's the Midland Basin work, there's the Delaware Basin work. I think you would expect to see some ads in the Delaware Basin, just because of the productivity that you're hearing E&Ps talk about out there. You know, what's important for us is that. We're not making a call and saying the entire market's going to move to 300 Series specification, but what's important for us and our stockholders is if that's where it were to go, you know, we have a very clear pathway toward being able to meet those opportunities or that incremental demand. That's perfect. Thank you for taking my question, and congrats on the quarter. Yep. Thank you, Dave. The next question today comes from David Marsh at Singular Research. Please go ahead. Hey, guys. Thanks for taking the questions. First, Phil, if I could, I just wanted to ask a question about the convertible note repurchase here. Looks like in the cash flow statement, you spent $5 million exactly to repurchase, but then it said, you know, par plus accrued. I just was wanting to get a little color, like, to make sure I understood, did you retire $5 million in principal of this note? Yes, it was $5 million, and the accrued interest was probably $100,000 on it. That would be up in the other part of the cash flow statement, in the operating piece. It's $5 million paid down at par, yes. Got it. Are they continuously callable at par at this point? There is a mandatory offer provision where we make an offer at the end of each quarter through 2024 to pay down at par. So it's $5 million each quarter through the end of this year, and then it's $3.5 million each quarter through next year. This was the first quarter, June 30. This is the first under the indenture this is the first offer that we made, and then they accepted it. Got it. I understand. Then, are you guys still picking at this point? Or, could you kind of update us on plan to possibly transition to cash interest payment on this? Yeah. I think what we've said publicly is our plan was to pick through March 2024. Certainly, you know, with the opportunity to, you know, cease picking at September, where we sit here today, assuming the mandatory offers are being accepted, and that's what we think is the most likely scenario, though, that's up to our lenders, then we probably would, you know, we'll, we'll be funding the mandatory offers. We probably would go ahead and pick through March 2024, and then our plan would be to stop picking at that point in time. Got it. I'm guessing that the, you know, kind of refinancing market is still not quite favorable enough for you guys to consider some type of an open market refinance at this point? You know, the kind of refinancing window under the indenture doesn't open up until September of next year. Obviously, we're in a little bit of a down market here as far as our, you know, EBITDA and reported EBITDA. It wouldn't be ideal for us to, to do something now, in my opinion, just because it's a negotiation. You know, it's pretty early as far as when that window opens up. I think, you know, with the opportunity to get some more rigs out, I think that, you know, that there's probably some better opportunities, you know, and discussions we can have next year. Yeah, I would absolutely agree. I just, you know, just trying to put a finger on the pulse of it. You guys moved, you know, you guys called out some costs in the press release with regard to moving rigs from the Haynesville to Permian, $600,000 in Q1, $2.8 million in Q2. How many rigs were moved in total? Six rigs in total. Okay, perfect. That just helps me understand the cost of moving one. That's really helpful. I appreciate it. That's all I have. Let me, yield to someone else here. Thank you, Dave. Thank you. Our next question today comes from Jeff Robertson with Water Tower Research. Please go ahead. Thank you. Good morning. Anthony, as the turn maybe slows down in the Permian Basin, do you expect at that point that day rates will start to firm up and margins start to improve as you put rigs back to work late this year and heading into 2024? Yeah, I think it's going to be a little quarter later than what people may expect, Jeff. The reason is that, you know, there's been rigs laid down. You know, the big players in the business have maintained good discipline in pricing. You know, as there are opportunities presented for people to step into the batter's box, you know, they're going to be aggressive in, in trying to get their rigs out. The good news is, I think it's a relatively limited number of rigs that we're talking about. Because of that dynamic, the margin probably lags the uptick in utilization by a quarter. That's why we're kind of, you know, laying out for you guys, you know, slight decrease in the third quarter and then sideways for the fourth quarter. Very optimistic about 2024. There, there's only been a 100 rig decline throughout the United States over this year, as you know, and very few of those have been in the Permian. The inflection to get back to pricing increases, I think is probably sooner than people may realize, but it's going to be a little longer, a little later than we would like. Do you get the sense that any customers are starting to worry about how they might get a rig back to the Haynesville if they start to look at the back half of 2024 and the maybe more optimistic view of gas markets then and into 2025? Yeah, absolutely. Jeff, we've had guys actually have that conversation with us, as they're starting to think about 2024. It likely becomes a challenge for them. I think one of the biggest reasons is, you know, we talked, I think, on the last call about how activity in the Haynesville is drifting south and west. What's important to note from an equipment standpoint is, as it does, it's typically deeper. Of course, all the laterals are getting longer, and, you know, that just requires a bigger rig. And if you want to look at some extreme examples, look at what, I think it's Comstock that made an announcement earlier this week, and what they're doing in the extreme western edge of the Haynesville. This is the stuff over in Texas and Robertson County, in that area. The well results that were published earlier this week, I think it was 34 million cubic feet a day of gas. That's very similar to what a lot of the E&Ps are seeing in the Haynesville. You know, as exciting as that, now they're going to test the deeper Bossier bench over there as well. The reason I point that out is, like I said, remember, the Haynesville, as it moves west, it gets deeper, the hook loads get higher. You're talking big equipment, and there's, you know, a limited number of those in the industry. You know, million-pound type rigs, big setback capacities, things like that. I think that bodes. That dynamic, along with just the general Haynesville picking up, is going to bode really well for contractors that have that kind of equipment. And of course, we're one of them. That play is migrating toward your rigs in terms of the specifications needed? Absolutely, the 300 Series. Yes, sir. Philip, you mentioned that you anticipate that the lenders will accept the redemption offers. It, that really drives or should allow ICD to naturally deleverage between reducing the principal amount of those convertible notes, which also, I guess, ultimately decreases the refinancing burden, but also it appears you should still be able to add cash to the balance sheet. Your leverage profile as that refinance window opens up, like you mentioned, late next year, the company's just natural leverage ratio starts to look a lot better and maybe have more opportunities. Is that a fair way to think about it? Yeah, I think certainly, compared to guidance that we've provided in the past, because I think in the past, we hadn't not really spoken much about them accept be cause we didn't know until what their plans would be until we saw what they did this quarter. With them accepting those mandatory offers, that certainly accelerates kind of the debt paydown. You know, it's beginning now as opposed to really in March of next year. Thank you very much. Thank you, Jeff. Thank you. Our next question today comes from John Daniel with Daniel Energy Partners. Please go ahead. Hey, guys. Thank you. Anthony, Hi, John. I apologize. I missed part of the prepared remarks. Can you tell me what the working rig count is today? We have 14 rigs today, earning revenue. Okay. ICD. And then. One of those on early term or on standby, rather. Okay. 14 are turning to the right or 13? Thirteen are turning to the right. Perfect. Okay. Yeah, Don asked some pretty good questions, so I'm going to follow up with a little add on to his. But I know you mentioned some of the incremental rigs that you're going to deploy, likely go to private operators. I'm curious, you know, you guys are probably pretty busy getting ready for earnings and all that, but if you listen to all of the E&P earnings calls last week and, you know, so far this week, the majority of them are saying flat activity, maybe bleeds a little bit lower. I'm curious, as your sales guys are getting inquiries from customers, how often are you catching any disconnects where the E&Ps are publicly saying one thing, but they're calling you and asking something else? Obviously, you don't want to give names, but I'm just curious your thoughts. Yeah, no problem, John. I wouldn't say it's a disconnect. I think it's just more of a perspective into the market. You know, we're not working for any of the supermajors today, although we have in the past. So when we're in these discussions, it's with large independents and especially on the private side. The opportunities that we're pursuing with the large independents, for the most part, are high-grade opportunities, where they have an underperforming rig or a rig that may have, lesser capability than a rig that we have, we can offer. Those are the opportunities with the independents. Where we do see or where we are seeing the incremental adds is more with the privates, and we talked about that earlier in the call. You know, as I look out over, third quarter and certainly by the end of the year, where I see three rigs going back to work, you know, two of those are 300 Series rigs that we have, that were working just a couple of months ago. We probably put another 200 Series out. The question is, do we upgrade it or not, to 300 Series capability? That's going to depend on the requirement that we're pursuing and whether or not we think we can get paid for it. Right. I wouldn't say there's as much of a disconnect. It's just the where we fit into the market with those three classes of customers. Okay. If you go back the last several months, you were probably more clairvoyant than others with respect to the Haynesville rig count, where it might trough. You know, if you use Baker as your proxy, I think it's low 40s right now. I think it was in the low 70s, you know, when times were hopping. Where do you think we hit in 2024? What would the inquiry suggest we could be at in 2024? Look, if you look at the strip, you listen to what customers say they're, you know, what price they need to stimulate activity, John, I could see dozen rigs easy over there. Okay. That's really ignoring what's happening in that extreme western part of the play, which I described a second ago. Yeah. Just looking at the Haynesville proper, that is, we've all known, I see a dozen pretty easy. Okay. I mean, obviously, crap happens. If we have a cold winter, things change pretty fast. The inquiries today don't necessarily put us back to where we were in Q4 2022. That's a fair statement, knowing it's still early? Correct. Remember, your available supply is lower than it was, too. You probably see a bigger pricing response at a lower rig count in the Haynesville, than you needed before. Yeah. Awesome. Thank you for very granular answers. Yes, sir. Thank you, John. Thank you. As a reminder, ladies and gentlemen, please press star then one to ask a question. Our next question comes from Dick Ryan with Colliers. Please go ahead. Thank you. Anthony, on your strategic initiatives, the technology pathways, where are you in that rollout? You know, can you provide a little commentary? What's your ultimate goal? Will that help you, you know, be in a better position to take some share in the market? Can you just provide a little more commentary on that? Yes, great. I appreciate you letting me talk about that, Dick Ryan. We haven't talked a whole lot about that. You know, look, like all other industries out there, I mean, we've expected the technology and demands for technology and appreciation for what it's going to do would make its way into oil and gas, and I think it is in a big way. You know, we've chosen, over the last couple of years, to not get into the arms race of trying to develop this technology ourselves. You know, part of that's just to, you know, some of the limitations that we have. We also felt that over time, you know, there would be a shakeout phase. Our strategy, you know, stated strategy is that we wanted to be a very fast second mover on this front. In the meantime, make sure that, you know, we had the right platform in place to be able to deploy technology, and we do with the AC rigs that we have, especially the control systems. Over half of our rigs are precision-controlled rigs. You know, think about your operating system on your iPhone. You've got to make sure that you have a platform in place to be able to deploy this technology. As we rolled into 2023, as we were thinking about the business and talking to customers, it was pretty apparent to us that, you know, going forward, the requirement to have a technological offering and be able to add to our customers' efforts to, you know, be productive, that those are going to increase over the coming years. We wanted to spend time in 2023 proving what I just described, which was to, you know, deploy third party's technology on our rigs and demonstrate where we can create value, not just for our customers, but also for ICD and our stockholders. I guess, the point that I'm trying to make is that that's happening now. You know, we have four of these systems deployed. You know, we've been very lucky because our biggest customer in the Permian Basin has been very supportive of these efforts, so we have a couple of systems that are on being used on a trial basis. We've got some things around the edges where we are getting paid for this stuff. Very positive results so far. We, you know, have a drill string oscillator, we have some stick-slip mitigation software, back-to-bottom sequencing. You know, what we're seeing is that, you know, all of those things are being mitigated. Trip times are being improved. You know, where do we think this can go? You know, Philip and I have sat around and thought about this. Look, we think there's somewhere between $500 and $1,500 a day of incremental margin that could come to us. Now, you know, just like with all contractors, it may not get deployed on every rig that we have operating, but obviously, over time, if this thing can prove its value, then customers are going to be willing to pay for it. I'm really pleased and proud of the third-party partners that we're working with. I appreciate the customer that we have working with us. Like I said, we just haven't talked a lot about this over the last couple of years. I didn't want people to think we're not doing anything about it, because we have been. It's been very quiet, but it's been very deliberate. Really pleased with what we've been able to show year- to- date on this front. Got it. Appreciate the color. Thank you. Yes, sir. Thank you, Dick Ryan. Thank you. Ladies and gentlemen, this concludes our question-and-answer session. I'd like to turn the conference back over to the management team for any final remarks. Well, we appreciate that. I want to thank everybody for making time to participate in today's call and giving us the opportunity to update you and talk about the exciting things going on here. Best wishes to all of you for safety and prosperity until we talk again. With that, we'll close out. Thank you. Thank you, sir. This concludes today's conference call. We thank you all for attending today's presentation. You may now disconnect your lines and have a wonderful day.