Good day, and welcome to the Independence Contract Drilling third quarter 2022 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 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. Please go ahead. Good morning, everyone, and thank you for joining us today to discuss ICD's third quarter 2022 results. With me today is Anthony Gallegos, our President and Chief Executive Officer. Before we begin, I would like to remind all participants that our comments today will include forward-looking statements which are subject to certain risks and uncertainties. A number of factors and uncertainties could cause actual results in future periods to differ materially from what we talk about today. For a complete discussion of these risks, we encourage you to read the company's earnings release and our documents on file with the SEC. In addition, we refer to non-GAAP measures during the call. Please refer to the earnings release and our public filings for our full reconciliation of net loss to adjusted net loss, EBITDA and adjusted EBITDA, and for the definitions of our non-GAAP measures. Before I turn it over to Anthony, I just wanted to make one comment. We did file with the SEC today, along with our press release, an updated investor presentation, which will be available on our website as well. We encourage people to go take a look at that when they have a chance. With that, I'll turn it over to Anthony for opening remarks. Thank you, Philip. Hello, everyone. Thank you for joining us today for our third quarter earnings conference call. During my prepared remarks today, I wanna focus on a couple of key topics. First, the significant margin expansion that continued during the third quarter and our prospects for continued margin progression, which are bright. Second, operational achievements during the third quarter and our outlook for additional rig reactivations. Third, some overall strategic objectives we are laying the groundwork for as we look forward into 2023 and beyond. First, just a few comments on the quarter. Overall, ICD's third quarter results came in well ahead of expectations on revenues, margins, and adjusted EBITDA. We reported revenue per day of $28,646 and margin per day of $11,341. This is a 15% increase in revenue per day and a 27% increase in margin per day compared to second quarter reported results. We had some one-time items affect our reported SG&A numbers during the quarter, which Philip will go through in his prepared remarks. Overall, we're pleased to report third quarter adjusted EBITDA of $12.5 million, which is a 35% increase from the second quarter, also higher than expectations. I wanna point out that our reported revenue per day and margin per day are all records for ICD. To put this quarter's performance into perspective, the only time ICD has reported higher quarterly adjusted EBITDA was during the fourth quarter of 2018 when all 32 of our rigs were operating. We only operated about 18 rigs this quarter, which given we believe we're still in the early innings of this upcycle, really highlights how much stronger and well-positioned ICD is today than we were at any time in our history. We look forward to opportunities to report record EBITDA in the coming quarters and beyond. More excitingly, we expect this momentum to continue. Market conditions and demand for our pad-optimal super-spec rigs continues to be robust, and we are forecasting meaningful, significant improvements in margin per day, driven by continued recognition of the value provided by our rig fleet, including increasing market penetration of our 300-Series rigs, our 200-Series to 300-Series conversion opportunities, and additional planned rig reactivations which are in the pipeline. Philip will provide more detailed guidance for the fourth quarter, but I wanted to highlight that we currently expect our margin per day to increase to between $12,500 and $13,000 per day. Looking into the first quarter, we expect margin per day to further increase over reported third quarter results by 28%-32%. Now, it's not just our rig margins that are on par with or exceeding those of our larger public company peers. We believe our operations and the value we provide to our customers are best-in-class as well. To provide you some tangible evidence of this, we were proud during the third quarter to be the highest-rated U.S. land drilling contractor for service and professionalism by EnergyPoint Research, the leading third-party industry source for such information. This is the fifth consecutive year we have received this coveted award. In that same poll of E&P companies operating in the United States, we were also one of three drilling contractors recognized for overall customer satisfaction. I point this out because we talk a lot about our rigs and our 300-Series rig penetration, but it's our operating and field personnel who work hard every day to exceed our customers' expectations at the well site, which ultimately is driving so much of ICD's success. During the third quarter, we reactivated our eighteenth rig, which went to work under a one-year contract. Our nineteenth rig is mobilizing now, also under a one-year contract, and our twentieth rig is contracted and scheduled for mobilization later in the fourth quarter. Both of these additional rigs are going to work in the Haynesville and will generate revenue per day in the high 30s, allowing us to achieve simple payback of both rigs' reactivation CapEx in less than one year. We have slated our 21st and 22nd rigs for reactivation during the first quarter next year, and reactivation work is already underway. In our last call, I mentioned the 200- to 300-Series conversion program which we had commissioned. The first conversion is in progress as we speak for an existing customer of ICD and will be completed later this week. We have accomplished so much this year, and I couldn't be more proud of how our operations and field personnel have continued to deliver high levels of customer service and performance, which our customers have come to expect from ICD. This is especially noteworthy given the unprecedented challenges involving the labor market and supply chain, which continued to plague the global business community. I wanna touch on contract backlog. While our strategy thus far in the recovery has been on securing shorter-term pad to pad contracts, as day rates have continued to strengthen and accelerate over the last three or four months, we have begun increasing our backlog of term contracts when it makes sense for both ICD and our customer. Since the second quarter, we've increased our backlog 87% to $102 million. Approximately 69% of this backlog extends into 2023. We did not have to cut our rates to secure this backlog. In fact, our backlog extending into 2023 is priced at approximately $35,300 per day, the equivalent of over $17,500 of margin per day based upon third quarter cost per day metrics. Contracts contain margin protection features that protect our contracted margins against labor and other inflationary cost increases. This 2023 backlog pricing gives us a great deal of confidence about further margin progression beyond the first quarter of 2023 guidance I just provided. While we are increasing our contractual backlog, we are not calling the top of the market for day rate progression by any means, and right now, most of our rigs will reprice at least once more over the next three to six months. Instead, we are layering on some contract backlog because as we think about the large capital investments now required to reactivate rigs and consider the significant margin generating opportunities available in our market today, we feel like it makes sense for a portion of our available days to be termed up. This approach will provide us with continued exposure to future increases in margin per day opportunities, meanwhile helping to lock in a portion of our future cash flow to help position us regarding our near and longer term strategic initiatives. As we think about additional rig reactivations and conversions beyond our 22nd rig, we'll be balancing a variety of strategic factors. First and foremost, we'll continue to look for full contractual payback for all rig reactivations and conversions, essentially what we've been doing. In addition, we will look to balance the timing of these projects against several competing factors, including our level of contractual backlog, our desire to reduce or eliminate future dilution from additional PIK interest, especially considering the rising rate environment we're in and expecting to persist, working capital liquidity, and evaluating where we are in terms of marketing and contract windows for additional rigs, which we believe will be anchored around our customers' annual budgeting cycle based on what we've seen here in the back half of this year. I bring this up because while we are doing the things necessary today to put ourselves in a position to be able to reactivate our 23rd and 24th rigs during the summer of 2023, we also may consider pushing those reactivations toward the end of 2023 if it allows us, for example, the ability to stop paying interest earlier than we previously indicated without sacrificing planned working capital improvements. As I bring these prepared opening remarks to a close, I wanna say that at ICD, we're 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. We intend to do this through a combination of increasing adjusted EBITDA and accompanying free cash flow generation as we build our operating scale and eventually slow our investments in additional rig reactivations. For reference, we are currently at 3.41 times leverage on an annualized basis using our third quarter results. While we have some work to do in this regard, our forward visibility relating to rig reactivations and margin progression gives us a great deal of confidence that we will make meaningful progress towards this goal in 2023 and beyond. I'll make some additional concluding remarks, but right now I wanna turn the call over to Philip to discuss financial results and outlook in a little bit more detail. Thanks, Anthony. During the quarter, we reported an adjusted net loss of $4.8 million or $0.35 per share and adjusted EBITDA of $12.5 million. We operated 17.4 average rigs during the quarter. Anthony previously mentioned our revenue per day and margin per day metrics, so I will not focus on those during my prepared remarks. SG&A costs were $7 million, which included approximately $1.7 million of stock-based and deferred compensation expense. Both cash SG&A and stock-based comp expense were higher than guidance due to a couple of items. Cash SG&A was negatively impacted approximately $300,000 by a dispute settlement, and sequential increases in cash SG&A over the second quarter also were driven by higher incentive compensation accruals based upon improvements in the company's financial performance. Increases in stock-based compensation expense related to full quarter expensing of awards granted in June of this year. Interest expense during the quarter aggregated $8.1 million. This included $2 million associated with non-cash amortization of deferred issuance costs and debt discount, which we excluded when presenting adjusted net income. We paid accrued interest under our current convertible notes in kind at the end of the quarter. Tax benefit for the quarter was $700,000. During the quarter, cash payments for capital expenditures net of disposals were approximately $9.4 million, breaking this CapEx out approximately 54% related to rig reactivations and 200- to 300-Series conversions, 39% related to maintenance CapEx, and 5% related to investments in drill pipe, capital inventory, and spares. CapEx is trending higher based upon supply chain constraints, causing us to bring forward drill pipe and other capital spare purchases, as well as rig reactivation expenses. Of course, there are also inflationary pressures. In particular, we ordered earlier than expected long lead time items for our 21st and 22nd rigs during the quarter, aggregating approximately $5 million. Moving on to our balance sheet. Adjusted net debt was $170.4 million at quarter end. This amount represents the face amount of our convertible notes and borrowings under our ABL and ignores impacts from debt discounts, deferred financing, and finance leases. We did not issue any shares under our ATM program during the quarter. Our financial liquidity at quarter end was $27 and a half million, comprised of $7.6 million of cash on hand and $19.9 million available under our revolving credit facility. Moving on to fourth quarter guidance. We expect operating days to approximate 1,690 days, representing 18.4 average rigs working during the quarter. We expect to exit the year with 20 rigs operating and our 21st and 22nd rigs reactivating during the first quarter of 2023 or potentially early second quarter in the case of the 22nd rig. We expect margin per day to come in between $12,500 and $13,000 per day. We expect revenue per day to come in between $30,100 and $30,300 per day, with many of the day rate increases on contract rolls, only partially benefiting the fourth quarter. Cost per day is expected to range between $17,300 and $17,600 per day. Based on contracts in hand and assuming spot market pricing and operating costs remain stable, right now we would expect first quarter 2023 margins to come in between $14,500 and $15,000 per day. Unabsorbed overhead costs for the fourth quarter will be about $600,000 and are not included in our cost per day guidance. We expect fourth quarter cash SG&A expense to be approximately $5 million. Stock-based compensation expense is expected to be approximately $1.7 million. We expect interest expense to approximate $8.2 million. Of this amount, approximately $2 million will relate to non-cash amortization of deferred financing and debt discounts. Depreciation expense for the fourth quarter is expected to be flat with the third quarter. We expect any tax expense or benefit during the fourth quarter to be negligible. For capital expenditures, we expect approximately $13.5 million net of dispositions to flow through our cash flow statement during the fourth quarter. The majority of this will relate to the completion of our 19th and 20th rigs, as well as the acceleration of the purchase of long lead time items for our 21st and 22nd rigs. Some also relates to upgrades for which we will be reimbursed by customers. With that, I'll turn the call back over to Anthony. Thanks, Philip. Before opening up the call for questions, I wanna briefly summarize ICD's strategic positioning and what I think it means for ICD stockholders. As we think about this positioning, I think it's important to highlight how much we've truly transformed our company thus far and the opportunities for our investors going forward as we round out 2022 and step into 2023. First, our utilization and margin growth coming out of the pandemic is best in class. Since coming off the pandemic bottom, we've started up more rigs than anyone else in the contract drilling industry as a percentage of each contractor's working fleet at the pandemic bottom. 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. We have the youngest, and we believe the best-in-class rig fleet. The market for pad-optimal super-spec rigs is as tight as we've ever seen, and ICD is one of only a few drilling contractors with visible excess rig capacity that can be economically reactivated into this market. We continue to demonstrate our fiscal discipline by securing contracts that earn full simple payback on the reactivation CapEx we are investing. Finally, we are building contractual backlog, and 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. Summing all of 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, our operations are closing any historical financial gap between us and our larger public company peers, and we believe all these efforts and results 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 one on your telephone keypad. If you're using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. At this time, we will pause momentarily to assemble our roster. The first question will come from Don Crist with Johnson Rice & Company. Please go ahead. Morning, gentlemen. How are y'all today? Good, Don. How are you? We're doing great, Don. Very well. I wanted to touch on slide 21 of your presentation with revenue per day and contracted backlog and just ask. You know, I know there's differences between rigs and operators and contract from Series 2 to Series 300 rigs. I wanted to know, is the numbers for 2023 representative of average numbers or is that just the couple of rigs that you have contracted today? What would that delta be? Would it be 10% less on an average across your entire fleet or something like that? Yeah. What's in that presentation, what's in that backlog is gonna be a mix of rigs throughout the quarters. Obviously, towards the end, the fourth quarter, there's not that many rigs in the backlog. There's a mix of 300-Series and 200-Series rigs in there, and a couple of them are contracts on our rig reactivations. We're putting out the 19th and the 20th rigs that we have contracted. The delta between a 200-Series rig and a 300-Series rig is probably $2,500 a day. Could be a little less, could be a little more, depending on the application and the customer. We are seeing, you know, for the 300-Series rigs at the high end, you know, day rates, you know, in the high 30s, and we do have, you know, for a particular contract, revenue per day could be over $40,000 a day with adders. It's not quite that high on the high end for a 200-Series rig. Again, it's gonna be a couple thousand dollars a day below. Okay. Just looking at the kind of modeling purposes that these are good numbers for kind of an average across your fleet. Is that a correct way to say it? I would say skewed more towards the 300-Series, certainly on the higher day rates. Okay. We won't, you know, we got. Sorry, go ahead. Go ahead. Yeah, from a day rate perspective, we're gonna get, you know, there's gonna be a mix of rigs, you know, leading edge, what I just talked about, but not every rig's gonna get a leading edge because not every customer requires the same type of equipment as, you know, different customers have different drilling programs. Right. Okay. As far as the 200-Series upgrades, obviously last quarter you talked about a couple of them in the pipeline. Where do we stand on that? Obviously, you're doing your first one now, but how many more are in the pipeline, and what's the interest level there to complete, you know, a majority of your 200- to 300-Series upgrades? Yeah. Don, the first one, as we noted, is underway, will be completed by the end of the week. We are doing that in the field. It's a rig move that's a little longer than normal. Obviously, customer's on board with that. So that one will be complete. We talked about doing a couple of them by the end of the year. Timing on the second and the third has kinda slipped into 2023, and that's really being driven more by the customer's requirement than anything else. In terms of converting all of the fleet, you know, we've never said that we're gonna do that. I don't know that we'll have to do that. We're only gonna do it where, you know, there's an opportunity there for us to invest in incremental CapEx and earn a return on that incremental CapEx. You know, really pleased with what we've been able to do with our 200-Series rigs. You know, notwithstanding the upgrades, rigs continue to perform very, very good. Day rates on those are, you know, continue to move up like they are with the rest of our fleet. We look at that 200- to 300-Series conversion of that class of rig as really something more opportunistic for the company. We do have a couple of kits on the ground so that, you know, when our marketing team is talking to current customers and prospective customers, you know, it's something that we can execute on, very easily and very quickly. That's how we're thinking about them. Just one final one for me. You know, obviously, you've started to term up a little bit of your fleet here versus, you know, mid part of 2022 as you take advantage of pricing. What is the optimal level there? Do you wanna get to 40% or 50% of your fleet contracted, you know, with 1+ year term backlog, or what's your thoughts around that? Yeah, you know, obviously, we wanna think about where we are in the cycle. Certainly, the free cash flow generating opportunities that are available will factor into that decision as well. You know, what we've said and how we think about it is just looking at it from a portfolio perspective. You know, where we see better opportunities maybe for the bigger rigs, maybe you don't go quite as long on those if you're not investing incremental CapEx. Whereas the other part of the fleet, you might put a little bit more term on the books around those. I would expect as, you know, as we roll into 2023, especially as our customers begin to, you know, announce what their plans are, that's gonna provide us ample opportunities to look and try to find that optimal amount of backlog, you know, relative to the available days that we'll have in 2023. It's not a hard and fast number. I would expect us to continue to add some backlog, but not look to commit everything that we have. We just think there's more upside from where we are today, Don. I appreciate all the color. I'll get back in queue. Yes, sir. Thank you. Thank you. The next question comes from Steve Ferazani with Sidoti & Company. Please go ahead. Morning, folks. How you doing? Appreciate all the color on the call. Wanted to get a sense if you're seeing any shifts in demand. Are there any particular strong pockets? Sounds like the two rigs you're sending out, the most recent rigs that are coming out are coming into the Haynesville. Any diversification in demand and any areas you'd be more targeting? No, you know, we've been really pleased with the way our geographic markets have played out over the year. Obviously very, very excited, Steve, about what's happening in the Haynesville. You know, we were able to grow, for example, our market share in the Haynesville over the third quarter, and we currently represent about 14% of the market share over there compared to about 3% in the Permian. You know, we've talked in prior calls about how, you know, in the Haynesville, you know, we're one of few. The requirements over there, not just from a technical standpoint, but especially from an operational standpoint are higher. It allows us to exploit the competitive advantage that we have relative to some other contractors and continue to build on that presence over there. You know, obviously, gas prices have moved up over this year. Things have been a little bit more flat here over the last couple of months, but you know, a lot of optimism in the industry, certainly a lot of optimism within ICD about where the gas market's going over the coming years, and I'm very, very excited that we can play a part in that. Haynesville versus Permian, are customers more likely to want term in one or the other, or is it no difference? No, I think our opportunities to push term maybe are a little better in the Haynesville, and it gets back to just the number of players in that market. It's not quite as fragmented as it is in the Permian, for example. The technical requirements and like I said, certainly the operational requirements are a little bit higher. You know, frankly, that's probably where we put more backlog of the term on the books, is in the Haynesville market compared to the Permian. Yeah, I would acknowledge that there is an advantage in that respect for us in the Haynesville today. Right. Good. As you're rolling out these rigs, I'm assuming you're adding, what, roughly 20, 25 people per rig you're adding. How challenging is that becoming, and how do you mix the crews up as you're having to add to your crew sizes? Yes, your numbers are spot on. It's 22-25 people per rig coming out. You know, a lot of risk associated with starting up new rigs. The way that we manage it is you're gonna hire 22-25 people, but you don't put them on that rig coming out. They get dispersed within our fleet, our operating fleet, and we bring, you know, 22 people from existing rigs, people that have been with us a while, that understand and know our systems and processes, that, you know, have bought into our culture. You know, in terms of how hard has it been, we've not had a problem attracting talent and bringing them in the company. The challenge that I think all of us have had is around retention and retaining those people. The problem really is, and the challenge really has been at that lowest level, that entry level within the company. You're dealing with somebody that is gonna be very young, you know, most likely, you know, first time to have, you know, a job, especially one as demanding as our entry-level positions are. You know, we continue to try to be very creative in finding ways to enhance that retention because it's not just a dollar impact. There's impacts to safety, impacts to efficiency, productivity, client satisfaction, and all of those things. To answer your question, you know, as we have continued to bring rigs out, you know, we have been able to find that talent and continue to be very focused in the company on what we call people development, which is making sure that we have, you know, talent that's ready to step up and take that next position. Thanks, Anthony. Thanks, Philip. Appreciate the time. Thank you, Steve. The next question will be from Jeff Robertson from Water Tower Research. Please go ahead. Thank you. Good morning, Anthony and Philip. Anthony, you talked about. Morning, Jeff. You talked about reactivating rigs 23 and 24 middle part of next year. You also mentioned the decisions around how long you want to PIK interest on the note, just given where rates are. Can you talk a little bit more about the specifics of what your thought process is around continuing to PIK interest through, I believe it's the first quarter of 2024, and how that plays into your capital assumptions for the incremental reactivations? Yeah. I'll give you my views, and then I'll let Philip chime in as well. You know, look, we just, Jeff, we've said all along, we wanna be very, very deliberate in making capital investment decisions. You know, one big difference in oil field services and certainly ICD today versus prior cycles is we don't wanna grow just simply to grow. You know, it's undeniable that we live in a world and live in times with tremendous uncertainty. You know, very proud and pleased that we're gonna meet our goal of ending this year with 20 rigs operating. You know, another couple in the pipeline that are gonna come out in the first quarter. Where margins are today, with, you know, 20-22 rigs running, we believe that, you know, it will give us the scale to achieve the longer term goals as we're thinking about where we wanna take the company. You do have to be mindful of where CapEx is today on incremental startups. Look, we're gonna be spending, you know, $8 million+ on rigs in this kind of time period. You know, our debt, as you know, has a variable rate interest on it. As interest rates have moved up, that service cost is going up as well. That's kinda how I'm thinking about it. Philip, you wanna add anything? Yeah. The PIK interest feature does two things for us. It gives us capital to reactivate rigs right now, but the other important piece of it's allowing us to improve our working capital position. We do have some goals there to, you know, add cash to our balance sheet and to remove all that. We do have some debt borrowed on our revolver. If we can get to $15-$20 million cash and no revolver debt, that's kind of where we'd like to have the company. We think about an opportunity, if there's an opportunity to push a rig that we may put out in the middle of the summer to the fall, where actually that's a better marketing window 'cause it's closer to our budget, our customers' budgeting season, and we can remove, for example, that last PIK interest payment. Because the way we think about that PIK interest, if we're putting out a rig and we're PIKing interest, that interest component is a capital cost of that rig. We're looking at that as part of our return analysis as well. That would be the reason, or how we think about it. Just to follow up on slide 26, where you talk about the potential debt reduction and really the potential improvement in the leverage ratio. Philip, is there a point in time where or a leverage ratio target where you think the company could take advantage of or could consider some sort of capital market alternative to refinance the convertible notes into something more conventional? Yeah. The convertible note has a defeasance period begins 18 months prior to maturity, so that's gonna be in early 2015. There is a make whole, so doing it earlier is more expensive than doing it later. That would be the window where we can look at refinancing alternatives, and that's really what we're trying to do, and Anthony mentioned, we want, at that point in time in that window, to have our net debt to EBITDA ratio as low as possible. We can either refinance the notes and pay them off in their entirety with free cash flow, or if there's a portion we need to refinance, we're gonna do that on a regular way, refinancing. If you look at where we're going in that slide you're talking about right there, we're assuming, you know, margins that are consistent with what our first quarter guidance is. You know, so we feel very good about our ability to do that in a market that we think is gonna be constructive during this period of time. Yeah. The cash balance that you're showing growing should be a big benefit as you think about the options with those notes. Sure. I would like to thank you for taking my questions this morning. Thank you, Jeff. Thank you. The next question will be from Dave Storms from Stonegate. Please go ahead. Morning, gentlemen, and thanks for taking my call. Just wanna circle back on Don's question with regards to contract lengths. Are you currently happy with the length of the contracts, or if rates begin to rise, should we expect to see contract lengths that would expand even further? Yeah, Dave, starting to layer on some six-month and 1-year contracts. You know, I will tell you, we're in discussions right now on an 18-month contract as well. Yes, I believe the demand, the incremental demand that's coming into the market around 2023 programs is gonna create so much competition for super-spec pad-optimal rigs that there will be opportunities to contract rigs for longer than one year. Certainly in that environment, you would expect to see day rates continue to move up. In that environment, I would expect us to take advantage of those opportunities and put even more backlog on the books. Again, not contracting everything. I think we want the exposure, we want the torque that the pad-to-pad contracts are gonna provide. Certainly these kind of economics, I would expect us to take advantage of that. Dave, I think the other thing to think about, it's not just us, but the industry, the rigs that are reactivating are getting more expensive. There's inflation, there's supply chain constraints and things like that. As you look at the cost to reactivate rigs and what ICD or even one of our competitors is gonna need to reactivate those rigs, you're probably gonna see rates need to improve, and you're gonna, you know, possibly see contract tenors go out because you're looking at not only, you know, you want contractual payback of those reinvestments, but you wanna ensure your returns as well. Are you seeing any pushback from customers when you go to negotiate some of these contracts, or do they see it in their best interest as well to lock in these rates and, you know, it's kind of a win-win where you're also able to essentially defease some of the cost for reactivating some of these rigs? Yeah. I don't know that I would phrase it as pushback. There's a. You know, we're at historical levels in terms of day rates in U.S. land. You know, maybe not sticker shock is probably not the right word, but, you know, clearly as 2022 has played out, you know, we've been optimistic that day rates would continue to increase. There are some E&Ps that believe they, you know, have maybe they've reached a ceiling. No, we're very optimistic that day rates will continue to go up. You think about the types of capital investments that are being made. You know, if you've listened to any of our competitors talk about maintenance CapEx, for example, that number continues to go up as well. Look, at the end of the day, we have to earn returns in excess of our cost of capital. When you look at, you know, the current economics around this today, maybe we're treading water in that regard, but we have to generate returns in excess of our cost of capital or we're destroying value. I believe that you know, it's another big difference in oilfield services today compared to prior cycles, is that I believe we're all thinking about things in this way. All that tells me that day rates will continue to increase for no other reason, just from an economic necessity standpoint. That's perfect. Thank you. Sure. Thank you, Dave. Again, if you have a question, please press star, then one. The next question is from David Marsh from Singular Research. Please go ahead. Hey, guys. Thanks for taking the question. Just quickly on the convertible note, is there any kind of feature in the convertible note that would allow you guys to force conversion of it if the stock closes above the strike price for a certain number of days? Is that something you guys would consider at all? As it's drafted now, there's not a mandatory convert feature in there like that. It's the conversions at the option of the holder. Got it. Just doing some quick math, I'm getting about 37.7 million shares at the current par value if it were fully converted. Is that the right number? It'd be $170.1 million divided by 451. Whatever that number is. Yeah. I think you're about right. Yeah. Yes. Yeah. Okay. Beyond that, I know it's probably still a little bit in the planning stages. Do you guys have a CapEx budget for 2023 yet? No, we're just starting to work on that now. You know, the two big variables will be, you know, ultimately what is our maintenance CapEx on a per operating rig basis, but also, how many incremental rigs are we gonna bring out for 2023. We have started that process. We are working on it now. It's a bit early to give you guys any guidance today. Sure. Completely understand. Then lastly, when you look kind of across the industry, I mean, obviously, you know, we have a pretty strong idea of your utilization and where you're going, where do you think the industry is kind of globally in you know here in the U.S. with regards to you know with regards to utilization? I think it's very high. The reason I say that is if you look at where demand is coming from, today in the United States, it's in the US unconventional plays. Within those plays, in order to be effective, you have to have what we call a super-spec pad-optimal rig. You know, best we can tell, when you look at that market today, their utilization is well above 90%. Another key difference today compared to prior cycles is most of that capacity is controlled by just a handful of companies. Where I get really excited is, you know, when people talk about what 2023 will look like, I think the consensus is there's, you know, obviously, there's gonna be more demand for rigs. There's numbers out there ranging from 50-100 incremental rigs over the next 12 months. What gets me really excited is when you look at where is that incremental supply gonna come from, there's only four or fove companies out there. ICD is one that has some capacity that can come out at something that's reasonable in terms of economics. Half of that incremental supply of super-spec rigs is held by one guy, one company, and it's 48% of it. That guy just came out and said he's only gonna bring out 16 rigs in the next 12 months. This is something that's probably underappreciated by people, but I think it speaks to how strong the market is today and how strong we believe it's gonna be in 2023. Obviously, we're very excited for all of those reasons. Thanks, guys. That's great insight. Really appreciate it. Thank you. Sure. Thank you, Dave. The next question is a follow-up question from Don Crist from Johnson Rice. Please go ahead. Thanks for letting me back in, guys. I just wanted to ask about the supply chain and more specifically drill pipe, because one of the major suppliers reported a couple of days ago and said that there was some weakness in their, you know, growing backlog for five-and-a-half-inch drill pipe. Can you just talk about that market and just overall supply chain and kind of where you see it trending into the first half of 2023? There are some drilling contractors that actually buy and rent their 5 1/2-inch drill pipe with their rigs. We don't do that. That's not included in our day rates and things like. We're not buying that type of drill pipe. We're typically buying 5-inch pipe when we buy it. You're looking at six-nine months is what we're seeing delivery times. That's really what you're looking for there. It's pushed out a little bit, but it's manageable, but it is pushing out. What about the other key components for, you know, just the reactivation? Is it getting better or worse or about the same as it's been over the last, call it six months or so? I think it's pushed out a little bit from if we talked six months ago. When we're talking about reactivating one of our rigs, we're not really buying a lot of brand-new equipment. We're overhauling engines, top drive, mud pumps that haven't been used for a while. Just like the other contractors, you know, the first rigs that went out, we put them out with the pumps and engines and top drives that were the easiest to put out. Now we're kind of all at the end of our inventory. So it's really a lot of maintenance CapEx in a lot of ways that we're having to spend on the front end. Just like everyone is supply constrained, a lot of those shops are also supply constrained, so we've gotta get in the queue sooner rather than later. That's why we've brought forward some of the in particular, the March rig. We've already ordered a lot of items for that rig just because we needed to keep it in the queue. We'll be doing the same thing on the 23rd and 24th rigs as well. That pushed out a lot. It's not 12 months, but it's there's things we're having to order six or seven months before a rig's gonna be reactivated. I appreciate the color. Thanks. Ladies and gentlemen, this concludes our question and answer session. I would like to turn the conference back over to Anthony Gallegos for any closing remarks. All right. Thank you. I just wanna be brief here and thank everyone for their time and dialing in this morning and participating in our call and wanna wish you all a safe and productive day. Thank you. Go Astros. Thank you, sir. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.