Good day, and welcome to the Independence Contract Drilling, Inc. Q1 2023 Financial Results Conference Call. All participants will be in listen only mode. Should you need assistance, please signal conference specialist by pressing the star key followed by 0. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press Star, then one on your telephone keypad. To withdraw your question, please press Star, then 2. 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 Q1 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 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 income to adjusted net income, 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 Q1 2023 earnings conference call. During my prepared remarks today, I wanna talk about 4 items. First, I wanna highlight our Q1 2023 results. Second, I wanna talk about the current market for super-spec pad-optimal rigs. Third, I wanna update you on the transition efforts around our Haynesville fleet, and I wanna close out with how all of this is impacting ICD from a financial perspective and where our focus will be. First, just a few comments on the quarter. Overall, ICD's Q1 results came in ahead of expectations in terms of adjusted net income, revenues, margin per day, and adjusted EBITDA. Philip will go through the detail, but I want to point out that our reported revenue per day, margin per day, and quarterly adjusted EBITDA were again all records for ICD. This is the Q3 in a row we've produced record results in one or more of these areas and provides another data point regarding ICD's operating and financial transformation since exiting the pandemic. Overall, adjusted net income came in at $2.4 million, buoyed by sequential margin per day improvements of 8% that drove sequential improvements in adjusted EBITDA of 16%. In addition to being a record quarter financially, the end of the Q1 also marks an important pivotal milestone in transition for ICD when it comes to strategic focus and capital allocation priorities. Since August of 2020, our focus in capital allocation decisions were driven by the need to increase operating scale. As signaled in our last conference call, the delivery of our 21st rig will be the last rig we reactivate until market conditions improve, which means meaningfully reducing our overall net debt and related financial ratios will be our highest priority from a strategic and capital allocation perspective. In fact, we improved our net working capital position by $11.7 million, as of today, we have already repaid $3 million of revolver debt since the end of the Q1, and we look to steadily reduce net debt going forward. Philip will go through more details in his prepared remarks regarding our plans around this very important initiative for ICD and our stockholders. Now turning to the market. In terms of the overall market and outlook for pad-optimal super-spec rigs in our target markets of Texas and the contiguous states, demand for pad-optimal super-spec rigs remains strong in the Permian Basin. While the overall Baker Hughes rig count for U.S. land shows a rig reduction since the end of the Q4 2022, most of that reduction occurred in unconventional oil basins outside of the Permian. In fact, the Permian Basin added rigs since the beginning of the year while the Haynesville has seen a drop. There will be more rig count reductions coming in the Haynesville, which I'll address in a minute. We are witnessing some churn in the Permian rig market, and what we're seeing is lower spec rigs, including some AC rigs, being replaced with higher specification AC rigs being made available by some Permian and Eagle Ford E&Ps trimming their rig count or being displaced by higher specification rigs relocating into the basin from the Haynesville and other basins. As a consequence, we are seeing a little more rig on rig competition where rig additions are occurring or a rig replacement opportunity exists. As we indicated last quarter, we expected to see day rate momentum slow, and that expectation is playing out. While margin per day remains robust, we expect it will flatten for the next few quarters and could be choppy for us during the second and Q3, in particular on the cost line as rigs transition from the Haynesville to the Permian. Still not a bad situation for ICD, given current levels and what those levels will allow us to do in terms of pursuing our corporate goals around deleveraging. We remain optimistic about market momentum accelerating again in the back part of the year, primarily in the Permian, based on our expectation that WTI will remain elevated in the back half of 2023 rolling into 2024. We believe the Haynesville rig market will remain challenging for at least the rest of this year. In spite of the choppiness in the Permian rig market, I mentioned earlier that we were successful in securing a contract for our 21st operating rig, which went to work in the Permian Basin early in the 2Q. This 21st rig was a reactivation project that we started back in October of last year and will be our last reactivation for a while. Like our other 300 series rigs. This rig brings to bear the technical capabilities that our target customers prefer today, including being super-spec, pad-optimal, three-by-four mud pump to generator configuration and enhanced setback and racking capacity. The rig went to work for an existing customer, which happens to be one of the largest private E&P companies operating in the Permian Basin. I'd like to provide a quick update regarding the transition efforts involving our Haynesville rig fleet. During our last earnings call, I described what we expected the impact of low natural gas prices would be in the Haynesville drilling rig market. For reference, natural gas prices had declined significantly in the prior couple of quarters, and we were anticipating a significant decline in the number of working rigs in the Haynesville as E&P companies held back drilling activities aligned to an oversupplied U.S. natural gas market. You can see that reduction has commenced in earnest here in the Q2 as drilling contractors are finishing up the pads that they were on during the Q1 when those rig count trimming decisions were made by Haynesville E&P companies. ICD started 2023 with approximately 50% of our working fleet, 10 rigs deployed in the Haynesville market. For us, the decision to relocate rigs from the Haynesville to the Permian was obvious. In response to the impending Haynesville rig count decline on our prior earnings call, we set forth our plans to reallocate a portion of our Haynesville rig fleet to the Permian Basin with a goal to reach effective utilization of 21 operating rigs by the end of the year following this rebalancing. At that time, we estimated relocation costs could range between $3 million-$4 million. Today, I'm pleased to report that we remain on schedule to achieve these goals with the caveat that we are still in the early stages of the process right now. We have seen some recent choppiness in oil prices, which if this trend continues, could slow the pace of ICD reaching 21 operating rigs by the end of the year. 2 rigs have already been relocated and are drilling in the Permian with minimal transitional idle time, and I'm pleased that our out-of-pocket transition costs for both of these rigs were primarily absorbed by our customers. 3 additional rigs have been physically relocated. Out-of-pocket trucking costs for these relocations also were not material and below our budgeted estimates. One of these 3 rigs is earning early term revenue, we would not expect it to recommence operations until the Q3, while we are marketing the other 2 rigs into opportunities with customers who currently plan for late May and mid-June start dates. Overall, we believe market demand and strength in the Permian for pad-optimal super-spec rigs, as well as our customer base, will be strong enough to absorb rig additions to the basins. That leaves us with 5 rigs remaining in the Haynesville at this time. For those rigs, as of today, we have successfully recontracted or signed extensions for 2 rigs which had contract expirations occurring during the Q1 or early Q2. For the other three rigs, which we have contract terms extending in the third and Q4, we expect those rigs to continue operating or earning stand-by revenue during their terms, depending on customer requirements. Depending on market conditions in the Haynesville, later this year, any of these rigs also could be candidates to move west, depending on the interplay between the two rig markets. Big picture, we're on track with our rig relocation plans and overall transition costs are coming in better than expected at this time. We are still in the early process, but we feel confident in our outlook so long as oil prices remain constructive. I am pleased that today all of our strategic and financial goals around generating significant free cash flow and reducing overall leverage remain intact. We expect 2023 to be a record year for ICD from a revenue per day, margin per day, EBITDA, and free cash flow perspective. I'm excited that in the near term, our free cash flow and net debt reduction plans have commenced and will accelerate as we improve our working capital position by paying down debt and putting cash on the balance sheet as we slow our capital investments and additional rig reactivations. Strategically, we remain laser focused on creating a pathway toward generating free cash flow, steadily decreasing our net debt position as we move towards the refinancing window for our Convertible Notes. Here in the Q2, we must offer to repurchase $5 million worth of our Convertible Notes at par. The offer is at the lender's option. If they don't accept that offer, the cash will remain on our balance sheet. Overall, we must make offers over the next seven quarters, which, if accepted by our lenders, will total $15 million over the balance of 2023 and $14 million in 2024. In addition, depending upon market conditions, we may also be in a position to stop picking interest sooner than we've previously indicated, which also is likely dependent upon the elections of our lenders relating to the mandatory offers I just outlined. As we have discussed, one of our long-term goals is to reduce our net debt to adjusted EBITDA ratio meaningfully towards a range of less than 1 to 1.5 times during the refinancing window involving our Convertible Notes, which begins in early 2025. For reference, we are currently 2.27 times levered on an annualized basis using our Q1 results, which even with completion of rig reactivation CapEx and seasonal Q1 working capital investments, represented an improvement over the same metric of 2.5 times at year-end. As I mentioned earlier, we've already begun the process of paying down debt. Everything's in place for ICD to achieve its short and long-term financial and strategic goals. Before I hand the call over to Philip, as I'm sure everyone is aware, Danny McNease retired from our board a few weeks ago. I wanted to thank Danny for his many years of service to ICD's board. I'll make some additional concluding remarks. Right now I wanna turn the call over to Philip to discuss our financial results and outlook in a little more detail. Thank you, Anthony. During the quarter, we reported an adjusted net income of $2.4 million or $0.14 per fully diluted share and adjusted EBITDA of $21.4 million. We operated 19.4 average rigs during the quarter. Our 21st rig commenced operations early April and did not benefit the quarter. Revenue per day during the quarter was $34,870, and margin per day was $15,665, all sequential improvements. Cost per day of $19,205 increased sequentially primarily due to higher R&M expense. Q1 costs also include seasonal increases for payroll taxes. During the quarter, we incurred $600,000 of unreimbursed costs relating to our Haynesville to Permian relocation program, which are excluded from our cost per day metrics. Selling general and administrative costs were $6.7 million during the quarter, which included approximately $1.8 million of stock-based and deferred compensation expense. Sequel decreases in cash SG&A over the Q4 primarily relate to lower incentive compensation accruals compared to the prior quarter. Interest expense during the quarter aggregated $8.7 million. This included $2.4 million associated with non-cash amortization of deferred issuance and debt discount, which we've excluded when presenting adjusted net income. We paid accrued interest under our Convertible Notes in kind at the end of the quarter. Tax benefit for the quarter was de minimis. During the quarter, cash payments for capital expenditures net of disposals was approximately $18.1 million. Approximately $16.2 million related to payment of prior year CapEx accrued at year-end. Breaking these cash payments out, approximately 75% related to rig reactivations and 200 series to 300 series conversions, which included payments associated with our 20th rig, which was commenced operations in late December, as well as our 21st rig, which we completed during the quarter. 20% related to maintenance CapEx and 5% related to investments in drill pipe, capital inventory, and spares. As Anthony mentioned, we have paused our rig reactivation program, so for the time being going forward, CapEx will principally relate to maintenance CapEx and tubular purchases. Overall, we have not adjusted our CapEx budget for 2023, which was front-end weighted. As Anthony mentioned, we currently remain on schedule with our rig relocation program and currently do not expect any major adjustment to our rig operating assumptions for the year that would impact our maintenance CapEx assumptions. Moving on to our balance sheet. From a working capital perspective, in addition to payments on prior year CapEx deliveries, our Q1 balance sheet reflects the normal seasonal impacts from the payments of year-end incentive compensation, ad valorem taxes and related payments. Those payments aggregated $5.5 million during the quarter. Overall, as a result of these payments and the payments on the CapEx, net working capital increased approximately $11.7 million during the quarter. Adjusted net debt at quarter end was $194 million. This amount represents the face amount of our Convertible Notes and borrowings under our ABL net of cash and ignores impacts from debt discounts, deferred financing costs, and finance leases. As Anthony mentioned, following reactivation of our 21st rig, our capital allocation focus has now pivoted away from reactivations towards debt reduction. Since quarter end, we have already paid down $3 million of debt. Financial liquidity at quarter end was $22.1 million, comprised of cash on hand and $15.4 million of availability under our revolving credit facility. This is in addition to the working capital improvement I just mentioned. Moving on to Q2 guidance. Operating days to approximate 1,632 days, representing 17.9 average rigs earning revenue during the quarter, which assumes several of our recently idle rigs commence operations late May to mid-June on contracted opportunities we are currently pursuing. If those projects slid to the right or did not materialize, exposure to the quarter is approximately 60 operating days. We expect margin per day to come in generally flat with the Q1, but with some cost inefficiencies associated with higher contractual churn given the number of days, excuse me, the number of rigs moving between basins. Overall, we estimate margins to come in between $15,000 and $15,500 per day. Unabsorbed overhead expenses will be about $600,000 during the quarter and also are not included in our cost per day guidance. Unreimbursed costs associated with our Haynesville to Permian relocation program are expected to be approximately $2 million during the quarter and are not included in our cost per day guidance. We expect Q2 cash SG&A expense to be approximately $5 million and stock-based compensation expense to be approximately $1.9 million. We expect interest expense to be approximately $9.8 million. Of this amount, approximately $2.6 million are related to non-cash amortization of deferred financing costs and debt discounts. Depreciation expense for the Q2 is expected to be relatively flat with the Q1. Finally, we expect tax expense to be de minimis for the Q2. 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 it all means for ICD stockholders. Here are a couple of points for you to consider. First, our utilization and margin growth since August of 2020 has been best in class. This speaks to the quality of our people, our assets, and our performance. Today, our daily rig margins are the best in ICD's history and are on par with and exceeding some of our larger company peers as we continue to earn recognition from our customers for industry-leading customer service and professionalism. The company has never performed better. I believe all of this will be on display over the remainder of 2023 as we navigate transitioning a large part of our rig fleet from the Haynesville to the Permian. Second, we have the youngest, we believe, best-in-class rig fleet. The market for pad-optimal super-spec rigs remains strong outside of the gas-driven basins. We continue to demonstrate our fiscal discipline by deferring further investments and additional reactivations beyond the 21st rig, which came out early Q2. Finally, we have substantially improved our liquidity and balance sheet and expect continued progress as we move through 2023 and beyond. Although softness in gas drilling markets will impact the pace of rig reactivations and is requiring us to reposition some rigs, ICD has never been in a better position to navigate these types of short-term challenges. Our operational strength and reputation with our customers has never been stronger. Our fleet, which has been transformed by the market penetration of our 300 series rigs, has never been more valuable. I'd like to thank our many operations support and corporate team members, which work hard every day to deliver high levels of safety, performance, customer service, and professionalism, which our customers expect from ICD. With that, operator, let's go ahead and open up the line for questions. Thank you. We will now begin the question-and-answer session. To ask a question, you may press Star then 1 on your telephone keypad. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press Star then 2. At this time, we will pause momentarily to assemble our roster. The first question comes from Don Crist with Johnson Rice. Please go ahead. Morning, gentlemen. How are y'all today? Good. Doing good, Don. I wanted to start with kind of rig demand. One of the other companies that reported today offered up a rig count assumption that kind of surprised me, and I thought was very aggressive of another kind of 50-75 rigs coming off the market by kind of late summer. Are you seeing kind of any significant reduction in demand? Because that would imply that you would see some softness in the oil markets as well. Just curious if you're seeing anything of that kind of magnitude out there. Don, thanks for the question. 50-75 rigs by the end of the summer feels extreme to me. As you know, I mean, I don't have a lot of visibility into the conventional oil or conventional gas markets or markets outside our target markets. I think we've been pretty clear on what we expect is gonna happen in the Haynesville. You know, we see another 15-20 rigs coming out of the Haynesville. That's in motion. I know there's been some questions on why we haven't seen it up until now, and I think that's really a function of when decisions were made to scale back activity and just how long the wells take to drill and how many wells there are in a pad in the Haynesville. I think, you know, here in the Q2, you've started to see that deceleration. We expect that's gonna continue. You know, again, staying within our target market, Eagle Ford has given up some rigs as well. I think since the beginning of the year, that market's down about 10 rigs. That's, call it 15%. Could be a little bit more trimming down there, especially in the gas window. I would just point out, I mean, about three-quarters of the rigs working in the lower 48 today are in the U.S. unconventional oil basins. You know, while we've seen some softness in oil prices, you know, it has moved back up here recently. I think the actions that OPEC+ took a couple of weekends ago, helpful. Certainly, you know, when we're talking to customers about activity, you know, Q3, Q4 this year, you know, most of them are talking about, not just flat activity, but in some cases, actually, adding rigs. That, that feels extreme to me, 50-75 rigs. I do think it is gonna drop a little more from here, in our target markets, and that's gonna be principally be in the Haynesville. Okay. To just follow on to that, you know, obviously there's a lot of discussion around LNG and filling up the pipes before that LNG comes on in, call it, late 2024, early 2025. Are you seeing any early discussions, particularly in the gas basins, on putting rigs back to work in the third, Q4 or early 2024? Not a lot, Don. The takeaway issues are gonna be there for a little bit. We've got to get the infrastructure built out along the Gulf Coast. There are a few customers that have started talking to us about, "Hey, you know, we're gonna need a high-spec rig, you know, sometime in 2024," and they're concerned that a lot of that capacity will have moved out of the market by then. I do know that's on their minds, but, we're certainly not aware of a lot of people planning to recommence activity here in 2023. Okay. Just one final one for me. You know, obviously you bought back a little bit of debt and you have the $5 million that you're required to offer in the Q2. What about cash taxes, I mean, cash interest versus payment in kind? Are you contemplating that decision now for the fall? We'll make the next decision, Don, end of September, whether we would pick that next six interest payments. We'll have to see where we're at at that point in time, where the market is. That may depend on whether the lenders have elected to, you know, take the, take the buy down to $5 million at the end of June or the end of September. That could impact it as well. We'll make that decision at the end of September for whether we pick that 6-month interest payment up until March. Our plan would be not to pick any interest after March of 2024. Hopefully, we're not picking interest after September. Okay. Can you remind me exactly what that cash would be if you paid it in cash? Yeah, it's gonna be SOFR plus 12.5%, so it's gonna be close to you know, 17%. Okay. I appreciate it, thank you. You know. Our next question comes from Steve Ferazani with Sidoti & Company. Please go ahead. Good morning, everyone. Appreciate all the detail on the call. You're obviously not the only contractor looking to move rigs into the Permian. I guess it's kind of a two-part question. One, how many rigs do you really think that can be absorbed specifically on the super-spec, whether you'd be able to replace enough lower spec rigs? What's your anticipation for pressure on day rates knowing that multiple contractors are looking to move rigs there? Great. Thank you, Steve. We do think there is capacity in the Permian market to receive incremental super-spec supply. You have to remember, you know, if you dial back into, say, Q3 last year, things were still pretty good. It was hard for some operators to get their hands on the latest, greatest technology. There are some immediate opportunities for us to displace rigs that are lower spec. There, you know, there are more SCR rigs running than you might realize out there, for example. There are some AC rigs that are outfitted with only 2 mud pumps or maybe they only have 3 generators. Of course, the equipment that we're looking to move into the basin has all of that, the 3 mud pumps, 4 gens. You know, we have the ability and a pathway toward enhanced setback capacity and stuff like that. Mm-hmm. Even in a flat environment in the Permian, we think there are opportunities to put these rigs in. I would point out that, you know, since the beginning of the year, the Permian has added almost 12 rigs. It may feel choppier, but we're pretty confident that we'll be able to move these rigs from the Haynesville and put them to work in the Permian. Your other question regarding day rate. It's interesting. The lower spec rig that is facing the threat of being displaced, you know, in many cases, that's the only way he can compete is on that lower day rate. As we get, you know, deeper into this, especially as we begin to deploy technology across the industry's super-spec rig fleet, customers are seeing the value that those rigs can provide, and that value can be, you know, reduced days versus depth. It could be in better hole geometry. But those are things that it's gonna be really, really tough for that lower spec rig to compete against even at a much lower day rate. We feel pretty confident that the market will be able to absorb the equipment coming in. We think that, you know, yeah, there'll be some pressure on day rates, but nothing extreme. I just close with, you know, we're not aware of a lot of rigs moving into the basin. you know, we've said what we're gonna do, and we're in the process of doing that. I think, there's been a couple that have come out of the Eagle Ford as well, but certainly not aware of a bunch of rigs heading out to the Permian Basin from these other plays today. Helpful. Right. It's helpful. I guess the biggest question mark on 2Q will really be the timing of the three rigs you've moved, when they might begin drilling again. Can you provide any color on that? I think what we've said is we have a goal of getting back to 21 rigs operating by the end of the year. Steve, obviously, that's gonna require a supportive oil market, which we believe is gonna be out there. You know, a lot of just balls in the air right now. The first step was getting the rigs out there with minimal financial impact to ICD, and I think we've done a great job at getting that done. Now it's, you know, finding the right contracting opportunity for them. We've been pretty vocal, and told people expect to see a, you know, a rig or 2 idle any given quarter for the next 2 quarters, which was Q2 and Q3. We're pretty optimistic that, you know, during the Q4, we're able to get back to the 21 rigs operating, you know, assuming that, you know, WTI and Brent, you know, reacts the way that we expect it to. The assumption for us should be it would be safer to assume those three rigs are not drilling this quarter. Well, they'll be in and out. There's a lot of. Okay. Steve, there's a lot of churn within the fleet. At any given point in time when you think about So some of those rigs have drilled in the 2Q, and then we relocated them and are looking for their next opportunity. The timing of those opportunities, you know, are late May, you know, mid-June type opportunities. If they move to the left, for whatever reason, then obviously those rigs wouldn't be working the last part of June. We talked about the 60 days. If you think about moving into the 3Q, there's really 19 rigs that we think could operate during the quarter. They're not all gonna operate every single day as we have to reposition the fleet. That'll kind of give you a little bit of an idea of what we might be dealing with in the Q3. We think the Q4 we've really got, all the rigs have a chance to operate during the quarter. Whether they all operate the full quarter, that's a different question. Of course. Of course. That's helpful. Thanks. If I get one last in. You did mention the potential for some of the, remaining Haynesville rigs Going out to standby terms at different t-points in the second half. How do you weigh moving them versus what you can get staying there? I know things change, so. Yeah. Some of that's gonna be decided by our customer, whether they choose to pay, you know, standby rate and have us stay on location. You know, a couple of those rigs are once contracted into the Q4 of this year, for example. You know, as long as they're willing to continue to pay the standby rate, obviously we wouldn't be able to market that rig. They would drive that. I guess where I was trying to go with my comments is for the balance of the fleet where we have optionality and can make a decision, if we see strengthening in the Permian market in the back part of this year rolling to next year the way that we expect, obviously, you know, that contracting opportunity is probably gonna pull that rig west, is how we're thinking about things. That's helpful. Thanks, Anthony. Thanks, Philip. Pleasure. Thanks, Dave. Our next question comes from Dave Storms with Stonegate Capital Markets. Please go ahead. Morning. Morning. Just wanted to touch on the backlog a bit. I saw it came down quarter-over-quarter. Was this by design as you're signing contracts, new contracts, or is there another story here? I'll start. I think it's really just a function of the market, Dave, and maybe some of the pressure that we've seen around day rates. Again, our outlook is for a, you know, much stronger contracting environment in the back part of this year. You know, most of the fleet, except for the term contracts we signed in the back half of last year is, you know, working pad to pad right now. You know, for us, something won't show up in our backlog unless it's six months or longer. Most, you know, a lot of the contracts that we've signed recently have been shorter than that. Yeah. We had five rigs move, you know, already moved from the, from the Haynesville to the Permian. They were all rolling off term contracts. When they renewed and obviously there's a couple of them we just talked about, we're actually trying to renegotiate, enter into new contracts with those now. Those are all contracts pad to pad that won't actually hit our backlog numbers. I think our backlog could decline a little bit more, reported backlog, as we move from Q1 to Q2, for the same reason. I think most of the contracts we're looking to sign are gonna be pad to pad. There could be some six-month contracts or longer, but that just remains to be seen. Understood. Very helpful. Then I know you mentioned in your prepared remarks that you're still on pace for the $3 million-$4 million worth of relocation costs, but you're still in the early stages of that. What factors are you looking at that might, you know, maybe lead that to be more in the $3 million range as opposed to the $4 million range? The bucket of costs that you're talking about are transportation costs to move the rig from the Haynesville to the Permian. We've done very well on that, and for the most part, we've had our customers absorb the lion's share of all of those costs. The other portion of it is because we're in a very choppy situation when you're moving rigs. We work really hard to maintain our crews and our people, and so there's some inefficiencies there that are part of that number. What'll help that go lower than the other will be just how quickly these rigs get recontracted. If we're able to execute upon what we just talked about and hit our Q2 kinda goals as far as these couple rigs coming up here at the end of May and June, then that's gonna be very helpful on having a more positive impact on the on those costs. The big variable is going to be just how quickly the rigs get recontracted and the kinda the cost of maintaining the crews during that period of time. That's very helpful. Thank you. Thank you, Dave. The next question comes from David Marsh with Singular. Please go ahead. Hi, thanks for taking the questions. Phil, I'm just trying to work through the comments with regard to margin projections for the Q2. I mean, is it an implication that day rates are going to be sequentially flattish in that, or is it more of a cost side that's driving the more conservative outlook on margin? Well, when you compare, Q1 margins to our guidance, the guidance is slightly lower. There was some capital equipment revenue in the Q1 that we don't have in the Q2, which really has nothing to do with day rate. It had to do with customers paying for certain upgrades to the rigs. I don't think we aren't forecasting that as much in the Q2. As Anthony mentioned, there is some pressure on day rates. When you think about margin going forward, it's not gonna grow above that number, we think for, you know, Q3 either. I think it's gonna be flat. Could there be pressure on it potentially? There could be around the cost line. It's probably where I'd be most concerned about it. It really just depends on the cost line, really depends on how quickly we get the rigs back to work so that our overhead and things like that get fully absorbed. Okay, that's helpful. Then, just on the commodity side, I mean, could you guys talk about just generally at a high level, you know, what types of price levels for nat gas and what types of price levels for oil do you believe that you need to have, you know, kind of a stabilized fleet and, you know, with the ability to make good day rates and good margins for kind of everybody involved? Yeah. again, we're drillers, David, as you know, so we don't make our living, calculating that, but we've been in the business long enough to get a feel for how our customers might react in different environments. To me, when you think about the gas business, I think gas needs to be above $3. I think oil needs to be, you know, above $70, right? I think what's also as important is trajectory. You know, $70-$75 with, you know, a bias going lower is gonna feel different than a stable environment where everybody feels like oil's gonna stay in the $70-$75 dollar range. The issue you've got now is gas, as you know, net gas is very, very low. I think most people expect it's gonna stay in that sub $3 dollar range. You think about where we are in the year, you think about the build-out of infrastructure to export LNG, take away constraints in the basin, all that just signals to me that, like I said in my remarks, that Haynesville's gonna be challenging for the rest of this year, and I think a good part of next year as well. Oil, on the other hand, you know, as you know, is a global commodity. You know, there's been a. You know, you just look at this year and what we've dealt with. I mean, you know, a couple of times we thought the banking situation was gonna get much worse. You know, are we going into a recession or not? You've seen oil dip into the 60s twice since the beginning of the year. There's been a lot of headwinds here. You know, as you look out in the back part of the year, whether the U.S. is in a recession officially or not, I mean, the expectation is, like it does every year, is global demand for oil is gonna increase by at least a% on a year-over-year basis. China, and the, you know, the real reopening of the economy and getting the industrial machine going, all of that's gonna be very, very positive for the oil markets. These are the reasons why, you know, we're so optimistic about the back part of this year in 2024, is we think it's a really strong setup for the commodity in terms of WTI and Brent, and that's what's gonna drive our customers' activity, especially out in the Permian. That's really helpful. Really appreciate the comments, guys. Thanks. Congrats on the quarter and best luck going forward here. Thank you, David. The next question comes from Dick Lyon with Oak Ridge Financial. Please go ahead. Thank you. Anthony, just from a marketing perspective, you know, as you look at recontracting, you know, How's your marketing team doing when you look at absorbing your rigs coming back to the Permian? Are you seeing that with existing customers, or are they making headway into new customers? Yeah. First, Dick, they do a fantastic job. Of course, they're only as good as the service and the equipment that we put into the market. It's just a really good effort on the part of the whole company. To answer your question, it's really both of those. You look at, for example, the twenty-first rig that came out, at beginning of April, that went to work for our biggest customer. We've slid another rig in with that same customer here, since the beginning of the year as well. We've gone to work for, some E&Ps that, we either worked for in the past or, you know, we've never had a chance to work for. It really is a mixture of both of those. They do a really good job. The company has a, I believe, a really strong reputation out there for having great people, very good equipment and a heavy focus on high levels of customer satisfaction. It's all of that together that's what's allowed ICD to bring these rigs over. There's a lot of recontracting that goes on too, within the basin that we don't talk a lot about on these kinda calls. Hopefully that answers your question. Sure. With the transitioning of these rigs, are you keeping labor levels constant during this pause period or? Yes. So far we've been able to do that. you know, That's some of the inefficiencies that you hear Philip talk about when we talk about our cost per day and margin per day expectations over the next couple of quarters. It's just, it's choppy. you know, look, if we felt like the market was gonna be tough for, you know, a longer period of time, then, maybe we would've taken some actions we haven't taken up until now. Given that we see this as a transitory situation where a rebalancing should occur over a couple of quarters, and the fact that we've been able to recontract rigs on a relatively quick basis, those are the reasons why, you know, we've made the decisions that we've made. I think, you know, our company and our stockholders in the long run are gonna get benefit because of that. Great. Thank you. Congratulations. Thank you. This concludes our question and answer session. I would like to turn the conference back over to Anthony Gallegos for any closing remarks. Okay. Well, we, just wanna say thank you to everybody for making time to hear our Q1 2023, earnings call. I do wish you all safety and prosperity, and look forward to talking to you again soon. Thank you. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.