Good morning. My name is David, and I'll be your conference operator today. At this time, I'd like to welcome everyone to the SilverBow Resources First Quarter 2023 Earnings Conference Call. Today's conference is being recorded. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there'll be a question and answer session. If you'd like to ask a question during this time, simply press the star key followed by one on your telephone keypad. If you would like to withdraw your question, press star one once again. I'll now turn the call over to Jeff Magids, Vice President of Finance and Investor Relations. You may begin your conference. Thank you, David. Good morning, everyone. Thank you very much for joining us for our first quarter 2023 conference call. With me on the call today are Sean Woolverton, our CEO, Steve Adam, our COO, and Chris Abundis, our CFO. Yesterday afternoon, we posted a new corporate presentation to our website, and we'll occasionally refer to it during this call. We encourage listeners to download the latest materials. Please note that we may make references to certain non-GAAP financial measures, which are reconciled to their closest GAAP measure in the earnings press release. Our discussion today may include forward-looking statements which are subject to risks and uncertainties, many of which are beyond our control. These risks and uncertainties are described more fully in our documents on file with the SEC, which are also available on our website. I will now turn the call over to Sean. Thank you, Jeff, and thank you everyone for joining our call this morning. SilverBow is off to a great start as our team continues to execute on our 2023 plan. Our development plan remains the same, with both of our drilling rigs dedicated to our oil assets through the end of the year. Our full year production and capital budget guidance also remains the same from last quarter's update. As Steve will further detail, our team continues to drive operational efficiencies and identify D&C cost savings. Costs have come down to begin the year, and we expect to see continued cost deflation as we progress throughout the year. First quarter oil production was at the high end of our guidance range and increased 140% year-over-year. Based on our full year guidance, 2023 oil production will increase by approximately 100% compared to 2022. Initial performance from our wells brought online year-to-date are producing at or above expectations and should result in sequential liquids production growth as we move through the year. The shift to more oil this year is resulting in higher revenue per unit and expansion of cash margins. As Chris will further detail, first quarter hedged revenue per Mcfe was the highest revenue per unit SilverBow has realized to date. By year-end, our production mix should be comprised of 40%-50% liquids. On the gas front, we produced near firm takeaway levels in Webb County during the quarter as expected. Pipeline capacities remain uncertain in the near term, although we expect regional takeaway to improve as new pipelines come online by year-end. SilverBow's cash flows are well-insulated from lower gas prices this year, as our gas production is over 90% hedged at a weighted average price of $3.79, assuming the floor price of our collars. Should gas prices improve, we have a Fasken DUC pad which we can complete later this year. It's worth highlighting that the acquisitions we made in 2021 and 2022 added ample runway to our oil inventory and supports our opportunistic oil pivot this year. Our strategy focuses on operational flexibility and capital allocation to our highest returns on investment. As a result of our recent acquisitions, two-thirds of our 10+ years of inventory are now oil-weighted. The ability to pivot between oil and gas development has been and will continue to be a competitive advantage for SilverBow. To wrap up my prepared remarks, our near-term focus on oil development is one piece of a multi-year strategy which remains the same. We have the roadmap and the levers to pull to grow production, EBITDA, and free cash flow while simultaneously expanding our inventory and strengthening our balance sheet. With that said, we will continue to monitor commodity prices and have the flexibility to adjust our activity levels accordingly. Our team has an established track record of delivering on our key objectives through commodity price cycles. We see a robust pipeline of opportunities ahead that will continue to unlock value for our stakeholders. With that, I will hand the call over to Steve. Thank you, Sean. In the first quarter, we drilled 13 net wells, completed 11 net wells, and brought 13 net wells online. The majority of D&C activity was focused on our central oil and western condensate areas, as expected with the 2023 budget we provided in March. While our game plan this year remains largely unchanged, our team continues to increase operational efficiencies, optimize drilling schedules, and identify cost reductions to drive greater returns on capital. On the drilling side, rig move times this year are averaging 30% faster compared to 2022. This has resulted in 10% more footage drilled per day, along with a 10% reduction in overall drilling costs. On the completion side, our team achieved an all-time record in pumping efficiency on a recent pad, besting our previous high set in 4Q of last year. First quarter non-productive time decreased by 30% and same-store stages completed per day increased by 25% compared to 2022. Furthermore, we are capitalizing on early cost deflation trends in the market. Recently, we have seen cost relief on rig day rates, tubular goods, well head equipment, and fuel. Frac services encompassing horsepower, sand, and chemicals are down 18% year- to- date. We believe key service and material costs will continue to move lower throughout the year. In our central oil and western condensate areas, well performance is in line with our expectations and supports consistent and repeatable results across our oil acreage as we move forward with full-scale development. In our eastern extension area, we are highly encouraged by initial results from a two-well pad co-developing the Eagle Ford and Austin Chalk, which we brought online early in the second quarter. One of our rigs will move to this area to drill continuously throughout the second half of the year. In our Webb County gas area, we continue to monitor regional takeaway capacity. The availability of interruptible volumes to sell into existing pipelines remains unpredictable, although we have recently seen some opportunity to sell above firm contracted volumes. This fluctuates daily and we conservatively plan for volumes to average at firm rates. The Webb County Austin Chalk wells we have brought online to date continue to exhibit some of the best results across our portfolio, and we are excited to return to this area as prices and pipeline capacities allow. As discussed on our last update, we have two four-well Austin Chalk pads in Webb County, which we deferred completion in late 2022. We continue to see long-term upside from this core area. Early in the second quarter, we added approximately 2,000 net bolt-on acres. Turning to results and outlook, our first quarter production of 304 MMcfe per day was at the midpoint of our guidance, with oil production at the high end of the range. For the second quarter, we are guiding to production of 325 per day at the midpoint, which implies a 5%-10% production increase sequentially. Full year 2023 production guidance of 325-345 per day is unchanged and implies overall production growth of 25% and oil production growth of 100% year-over-year. By year-end, as Sean noted, liquids production is expected to comprise 40%-50% of our total mix. With that, I'll turn it over to Chris. Thanks, Steve. In my comments this morning, I will highlight our first quarter financial results, as well as our price realizations, hedging program, operating costs, and capital structure. First quarter oil and gas sales were $140 million, excluding derivatives, with natural gas representing 66% of production and 38% of sales. During the quarter, our realized oil price was 96% of NYMEX WTI. Our realized gas price was 86% of NYMEX Henry Hub, and our realized NGL price was 30% of NYMEX WTI. As shown on slide 21 of the corporate presentation, we have historically realized prices close to NYMEX benchmarks. During the quarter, our realized gas price was impacted by widening basis differentials and is lower than our historical range compared to Henry Hub. This has been caused by the loosening of regional supply and demand. Risk management is a key aspect of our business. We are proactive in adding basis to further supplement our hedging strategy. For 2023, we have secured gas basis hedges on 157 MMcf per day to mitigate further risk. Our realized hedging gain on contracts for the quarter was approximately $20 million. Notably, our first quarter hedge revenue per Mcfe of $5.84 was the highest revenue per unit SilverBow has realized to date. This is impressive considering the declines in the first quarter Henry Hub benchmark pricing compared to last year. The higher revenue per unit reflects the mix shift impact of higher oil production, as well as the strength of our current hedge position. Based on our hedge book as of April 28th, for the remainder of 2023, we have 180 MMcf per day of natural gas hedged, 7,400 barrels per day of oil hedged, and 3,750 barrels per day of NGLs hedged. Using the midpoints of our production guidance, we are 91% hedged on gas and 48% hedged on oil for the remainder of this year. For 2024, we have approximately 120 MMcf per day of natural gas hedged, 3,300 barrels per day of oil hedged, and 1,400 barrels per day of NGLs hedged. The hedged amounts are inclusive of both swaps and collars. A detailed summary of our derivative contracts is contained in our presentation and Form 10-Q filing for the first quarter, which we expect to file later today. Turning to cost. Lease operating expenses were $0.78 per Mcfe. Transportation and processing costs were $0.42 per Mcfe. Production taxes were 7% of oil and gas sales. Cash G&A, which excludes stock-based compensation, was $6.5 million for the quarter, which includes one-time professional fees. For full year 2023, we are guiding for cash G&A of $19.5 million at the midpoint, which implies cash G&A on an Mcfe basis to be slightly down year-over-year, inclusive of one-time fees. We consider our lean cost structure to be a differentiator, allowing SilverBow to sustain profitability during periods of volatile commodity prices. Adjusted EBITDA for the quarter was $111 million. Capital expenditures for the quarter on an accrual basis totaled approximately $108 million. Full year 2023, our CapEx guidance is unchanged at $450 million-$475 million. Included in our guidance range is the completion of a four-well Austin Chalk gas pad in the fourth quarter and opportunistic land spend. As reconciled in our earnings materials, we recorded a free cash flow deficit for the quarter. Cash flows in the first quarter were constrained due to deferring the completion of eight Webb County gas wells drilled in the fourth quarter of last year and ongoing gas curtailments in Webb County. The timing of D&C projects and land spend creates variability in our quarterly free cash flow results. Based on our latest guidance and outlook, we expect free cash flow to run at a slight deficit in the second quarter. With strong growth in the second half, we are projecting positive free cash flow for the full year. Turning to our balance sheet, total debt was $709 million. As of March 31st, we had $216 million of availability under our credit facility and $2 million of cash on hand, resulting in $218 million of liquidity. SilverBow, in accordance with our credit facility, includes contributions from closed acquisitions for the entirety of the LTM Adjusted EBITDA period used for leverage ratio calculation. On an LTM basis, for the period ending with the first quarter of 2023, the contributions from acquired properties totaled approximately $63 million, bringing our LTM Adjusted EBITDA for covenant purposes to $493 million and our quarter-end leverage ratio to 1.4x. Consistent with our strategy the last several years, excess cash flows that are not reinvested through the drill bit will be used to pay down revolver borrowings, SilverBow continues to target a leverage ratio of less than one times. At the end of the first quarter, we were in full compliance with our financial covenants and had sufficient headroom. With that, I will turn it over to Sean to wrap up our prepared remarks. Thanks, Chris. SilverBow continues to execute on its growth strategy and is positioned for significant value creation going forward. We project continued double-digit growth over the next several years as we march towards a half a billion cubic feet equivalent per day of production. In the near term, a key catalyst for our stakeholders is our ramp in oil production. Our relentless focus on our employees' well-being and safety is paramount to our culture, as is our engagement with the community and our environment. We look forward to sharing more of our insights towards safety and clean operations with the re-release of our inaugural sustainability report in the near future. I want to thank all of our stakeholders for their continued support. We look forward to providing further updates on our next call. With that, I will turn the call back to the operator for questions. Thank you. At this time, I'd like to remind everyone, in order to ask a question, press star then number one on your telephone keypad. We'll take our first question from Donovan Schafer with Northland Capital Markets. Your line's open. Mr. Schafer, go ahead. Your line's open. Sorry about that. I muted myself. I wanna start off with interruptible capacity. I was just curious, you know, if you can give us a sense for magnitudes around, you know, what you may or may not be able to ship via interruptible capacity. I mean, I know that's, like, super hypothetical, and I think, you know, correct me if I'm wrong, but your guidance kind of assumes, you know, not having any interruptible capacity on the gas side. I'm kinda just thinking in terms of, like, error bars here, you know? Of course, you guys don't have a crystal ball, you know, just sort of in theory, is this the type of thing where when interruptible capacity is available, that can add, like, another 5%-10% of volume, but then, you know, maybe that's, like, 1 day a week, so then it ends up being de minimis? Just kinda trying to get my mind around how to just think about it more conceptually. Yeah. No, appreciate the question. You know, your question around how much availability is there and how sustainable it is kind of spot on. When we do see available capacity, it's probably, you know, 5%-10% above what we can produce. That's not a bad number. At this point, it's very inconsistent, sometimes only for a day or two. We still are guiding towards our firm capacity for the full year, and think that it's prudent that we do that guidance. Okay. I also wanna ask, you know, the efficiency gain. It sounds like, you know, D&C costs, you've got the deflation aspects, but also pretty significant efficiency improvements. I'm wondering, is it unfolding in a way, the sort of efficiency improvements, and, you know, the uptime you talked about with the frack spreads, is that, like, is that kind of a proof point or, like, an unfolding in a way that's in line with or consistent with then kind of the initial part of the strategy and the idea around being, you know, just one of a couple consolidators, like, in the Eagle Ford? Before, I think the idea what you guys talked about before was, you know, if you're one of just a couple of consolidators, it gives you the scale, to, you know, you can get some better pricing. Possibly even more importantly, you know, you can get higher quality crews. You know, I know having a crew that sticks together, that executes well, and you don't, you know, have someone not showing up to work one day or whatever, is really important. Have you been able to kinda get crews that you feel like are kind of high quality and then retain them? Is it, like, I guess, unfolding in a pattern, in the nature that you were kind of thinking back to the original consolidation strategy? Yeah. You know, we're firm believers that with scale, there's a lot of optionality that comes with it from increased purchase power, but also, it brings, you know, consistent operations over a long period of time as we're able to level load our services. We are seeing that play out. We, you know, continually work with our service providers to build stronger partnerships. We pride ourselves on being, you know, prudent schedulers, and I think we get that feedback from the service providers that, you know, we put more consistency into their schedule. As a result, we're seeing improved, you know, performance from their side of the business. I do think it's not easy to be a consolidator. It takes, you know, an operator that has a proven track record. I think our company has demonstrated that in that we continue to best our record performance quarter in and quarter out. I think it speaks to just having a larger footprint and more level loaded operations. Okay. That's helpful. I guess my last question then I'll take any others offline or maybe I'll jump back in the queue. The last question I've got for the moment is with the new pipelines you talked about coming online kinda towards the end of the year, kind of similar type of question to what I was asking with the interruptible capacity. You know, can you just give us a higher level kind of framework or conceptual way to think about, like, you know, these new pipelines, like, the magnitude of the volume they could move relative to what is the takeaway capacity existing? You know, is this a 20% increase, 30% increase of what, you know, capacity to take away from the region where you're, you know, where you're producing? If possible, you know, what does that translate into for basis or, you know, pricing improvements? Again, I know you don't have a crystal ball and like, you know, of course, benchmark prices and everything, so maybe it's something best to talk about in kind of relative terms. You know, if, you know, something along the order of, you know, well, if this is gonna increase capacity, takeaway capacity 30%, and that would tend to translate into, like, a 10-ish or 20-ish percent or even, you know, more, like it's more levered to the capacity. Again, just kinda trying to get the framework to think about what those could mean. Yeah. Yeah, definitely, the Webb County dry gas play has really, you know, boomed over the last 18 to 24 months as, you know, several large operators have come in and started to develop the high quality Eagle Ford and Austin Chalk zones. You know, takeaway capacity out of that area currently sits around 2.5 Bcf a day. With the planned expansions that are scheduled to come online by the end of the year, that probably takes it up, not quite to doubles it, but takes it to about 4.5 Bcf a day of potential- Right ....expansion. Definitely provides for more volumes to come out of the area in the years to come. Now, speaking to, you know, what's that mean from a basis differential standpoint, our view is we're still very bullish on gas, especially as you get into 2025, 2026, timeframe with a lot of new demand coming online, in the Gulf, primarily on the LNG export front. You know, I think you look at macro forecasts across the big gas basins, and there's gonna be a shortage, in our belief of gas volumes, once we get to that period of time. This, you know, expansion in Webb County, we think is gonna be critical to help meet some of the demand needs and expect that not only will absolute gas price increase going forward, and the strip reflects that, but we think basis will tighten back up to more historical levels and we'll see, you know, close to NYMEX pricing as we move forward in into the late 2024, 2025 timeframe. Okay. thinking, you know, the benchmark goes up and then you're not gonna suffer any. Penalty or getting boxed out from benefiting from that. Benchmark goes up, and you get kind of a clear translation into that. Okay. That makes sense. Yep. All right. Thanks, guys. Appreciate it, Donovan Schafer. Thank you. All right. right. Well, next we'll go to Charles Meade with Johnson Rice. Please go ahead. Good morning, Sean, to you and the whole SilverBow team there. Hey, good morning, Charles. Yeah, I wanted to ask a question about your Eastern extension, and I think Steve touched on this in a few of his prepared comments. I wondered if you can recap for me and for others listening what you've done so far in 2023 over there because I think Steve said that you brought in one Eagle Ford and one Austin Chalk and also, I think there's plans to, you know, you've moved a rig there, or maybe you're about to move a rig there, and do more of this Eagle Ford and Austin Chalk. Can you just give a recap of what you've done so far? What the plans are for the remainder of 23 and to the extent that it sounds like you do have some well results, how those are coming in versus your, you know, your risk to plan? Yeah. Yeah. You bet. You know, just to recap, this block is a result of two acquisitions that we did, one in 2021 and one in 2022, where we can, you know, put together just under a 20,000 acre block and consolidated the work just within the block and wanted to get that all in place before we went in and started drilling. Early in 2023, we drilled our first two well pad, one Eagle Ford, one Austin Chalk, like you mentioned. You know, the wells just came online, so they're still ramping. We haven't quite reached IP or are just starting to get there, we wanted to not, you know, get out in front of results on the quarter anouncement. You know, to Steve's comment in the script, we're pretty excited with what we're seeing. Can tell you that the results are coming in line or exceeding to date. you know, our comment that we're gonna move a rig in there and park it for the second half of the year should give indication of what we're thinking about the results thus far as well. Got it. The A rig was there, drilled the two well pad, sounds like it moved off, but you're going to park one there for the second half. That's the outlook? That is. Got it. Yeah. Thank you, Sean. Then, second, a follow-up to the, you know, on the whole A&D landscape. From my perspective, it looks like, you know, the A&D and the Eagle Ford kind of slowed down, and then we got a couple of, got an unusual move with a Canadian company coming in, and making a corporate deal. This morning, we have a company that's been a long time player in the Eagle Ford, you know, selling this position and concentrating in the Permian. I wonder if you could give us your thoughts about what the potential and what the landscape looks like today. Particularly, are there chances for you to, perhaps delever through some acquisitions, in the Eagle Ford? Yeah. Yeah. The Eagle Ford definitely has been an area of significant activity really over the last 9 months now. Like you mentioned, just over the last couple days, there's been a couple transactions announced as well, one public selling to a private and one private selling to a public. continues to be a range of activity, and, you know, a range of, you know, size and scale, with many of the packages being announced between, you know, prices of a half a billion dollars up to two and a half billion dollars. A lot of interest in the Eagle Ford for the reasons we've laid out in the past. you know, begs the question, how much activity remains in the Eagle Ford and can SilverBow participate in that? Yeah, we still think there's a, you know, a lot of further consolidation to occur. We think that there's two reasons to do that, and the Eagle Ford sets up well for it. First is, you know, in the gas window of the Eagle Ford, the economics are very strong and look, you know, extremely attractive moving into a contango price curve. We think there's an avenue there. We think that, you know, it's coming more into view that core inventory is starting to dry up in a lot of basins. We think that there's runway in the Eagle Ford, and folks recognize that. We think there's consolidation that can occur, especially in the Western Eagle Ford, around, you know, right now, acquisitions being done near PDP value, but exposes buyers to a lot of inventory that should look attractive in the years ahead. Yeah, we think Eagle Ford will remain active, and our plan is to be active in it. We think that through that growth, there's opportunities, like you mentioned, to delever based upon, you know, how we structure the deals. That's helpful detail on your thinking. Thanks, Sean. Yeah. Thanks, Charles. Have a good day. Okay, next we'll go to Neal Dingmann with Truist Securities. Your line's open. Morning, all. Thanks for the time. Sean, my first question is just wondering a little bit more on how you're thinking about capital discipline. Specifically, you know, you've mentioned potentially in the release about slowing gas-focused activity later in the year. I'm wondering if oil continues to go lower, creep lower like it's doing and gas remains weak, would y'all consider going more to a single rig plan in order to, you know, what we would forecast would be a nice boost in Free Cash Flow? Yeah. Yeah, no, you know, one of our guideposts is to spend within cash flow. We're gonna continue to adhere to that. You know, there's been just a lot of volatility on both commodities, but just over the last, you know, really 30 days on oil, it's done a $20 cycle in that short period of time. We'll continue to monitor both commodity prices and adjust our capital really driven by returns on investment, and staying within cash flow. What's good is we have a lot of flexibility in our operations, so no really, you know, contractual obligations on the service side, and any, you know, meaningful MVCs or land commitments that can't be handled with one rig or even less than one rig. Yeah, we're really have planned to stick with the strategy of growing, but doing it within cash flow. If commodity prices aren't there to accommodate that strategy, we'll dial back and, you know, between our hedge book and the growth that we've already generated year- to- date, to your point, you know, have a lot of free cash flow in the near term if we dial back, capital. Yes, really like that optionality. My second question is, how big a benefit do you believe, I mean, maybe even for the remainder of this year or next year, how big a benefit do you believe your operating efficiencies that you continue to see and potential software and OFS costs could have on the plan? Yeah. you know, we started to see this earlier in the first quarter. It's continued to play out both on operational efficiencies and some deflationary pressure. Didn't feel like we wanted to, you know, lower the capital guidance at this point in time. Wanted to see how it plays out for another quarter. Yeah, we think the way things are setting up, there's probably, you know, a 10 ±10% realization that we're seeing year- to- date, and we think that could potentially double in the second half of the year. Wow. Great to hear it. Thank you. Yeah. Thank you, Neal. Have a good day. Okay. Next, we'll go to Tim Rezvan with KeyBanc. Your line's open. Good morning, folks. Thanks for letting me ask a couple questions. Charles, sort of stole my topic on the eastern extension, but I thought I'd maybe pick at it a little more. Obviously you seem excited. You don't have numbers to share. Was the decision to move that rig to the second half of the year made before this pad was drilled? Or is it something that you're more confident in once early production came back at you? Our plan had us moving the rig there, wanted to, you know, just de-risk it a little bit, both on the capital side, the performance side, as well as the reservoir performance side since we hadn't drilled in that area before. you know, had a good feel for what the, you know, both CapEx and well performance would be, you know, going in through the acquisitions. just wanted to, you know, make sure we felt comfortable and felt it was prudent to get two wells under our belt versus getting in there and drilling, you know, a half dozen before we saw some results. really it's the two wells to date are confirmation of our expectations, and it's really a sticking with our plan. Okay. Okay. I guess we'll maybe next quarter get some numbers around that. Yeah, definitely. Okay. I know it's early. Can you talk about the oil cuts there relative to kind of the western liquids area? Yeah. Our position really spans the windows, with some of it within the volatile window, some of it within the condensate. Our two wells drilled to date, oil is probably in that 70% range. More oil rich than the western condensate area. Our plan in the second half of the year is actually to drill in both windows. The condensate window is more in that probably 40% oil, 30% liquids, 30% gas ballpark. Kind of a mix there. We'll probably, if I was to ballpark it, the second half of the year is half drilling in the volatile oil window of the eastern extension and half in the condensate window. Okay. Okay. Yes. We'll look forward to results there. Somewhat related to that, I'm just trying to reconcile a little bit of housekeeping, you know, on the modeling front. The press release talks about oil. I think it was 40% to 50% of production by the fourth quarter. The slide deck says liquids are 40% to 50% in the second half of the year. Oil was 22% of production in the first quarter. Can we just think about that as sort of a steady ramp to kind of a mid-40s level by the fourth quarter? Just trying to understand. Yeah. How to sort of model the transformation, so. Good question, probably we need to look and make sure we're consistent on the nomenclature. The 40%-50% is a reflection of total liquids percentage, not oil percentage. Think of it, yeah, 40%-50% liquids. Of the liquids, two-thirds is oil, one-third is NGLs. Okay. Okay. We'll look to make sure we clarify that if we have a mix of nomenclature, scattered across press release corporate presentation. Okay. Yeah. Thank you. Just, okay, just to clarify, should we think about oil being 30%, mid-30s% of production in the fourth quarter? Kind of... You know, just trying to get our arms around. Is that what you're sort of saying? Yeah, trying to do the math in my head. Yeah, I think we'll be, you know, into the 30%, probably low 30s. Okay. Okay. I can. I'll nag Jeff offline about this just to make sure we're thinking about it correctly. Appreciate the comments. Thanks. Yeah. Yeah. Thanks, Tim. Have a good day. Okay. All right. Next, we'll go to, Noel Parks with Tuohy Brothers. Your line's open. Hi. Good morning. Hey. Morning, Noel. Just a couple things. Wondering about the co-development of the Eagle Ford and Austin Chalk, are there any particular technical challenges on the completion side or the drilling side, or is it more a matter at this point sort of, you know, site selection, sort of pre-drill analysis? There is some operational differences between the two zones. In terms of, you know, planning for and taking, you know, in advance of the co-development, taking that all into account, we're fully aware of it. Probably, and Steve could chime in on this, the biggest difference is in certain parts of the play, we can drill Austin Chalk with two string, but need to set an intermediate string going into the Eagle Ford. That's probably the biggest technical difference. We see that the Austin Chalk drills is a little bit harder rock, so drills a little slower, but again, not anything different. From a frack completion side, our recipe's kind of the same, and we see similar type treating pressure. No, like, on-the-fly adjustments needed as we simul-frac between Eagle Ford and Austin Chalk. You know, we're not having to, like, adjust prop or chemical makeups or anything like that. Steve, I don't know if I missed anything that you might want to add. I think he covered it excellently. Then, we've just done a little more fine-tuning on mud weights for both of them, for both well bore stability as well as well control. Okay, great on those. Okay. I was wondering, you know, as we continue a few more months on this sort of tough near-term nat gas environment. Thanks for the reminder that you do have the pad that you could move up and complete if prices, you know, rebounded. I was thinking about other opportunities if we do see sort of a return to volatility that takes us up. In your gas areas out west, are you at the point that there is significant potential re-completion activity out there? I was thinking about things that could be maybe mobilized relatively quickly and, you know, have a good return in the event gas does pop up near term. Yeah, you know, much of our Webb County development is over the last five, six years, so, you know, much of the completion was, you know, at optimized levels as far as we're concerned. We don't see that area as like a high workover, high re-completion area. We've been spending more dollars doing that on the oil front as we've gotten some of these, you know, assets that were kind of under loved over the last couple years. We've been having some success- Sure ... on that front. On the gas front, it's really. We've got two four-well pads that we could, you know, complete if prices justified it and there was availability in the pipeline any time through the year. The other thing is that we're just so efficient, we, you know, over a two day period, we can move a rig back in there, drill a, you know, a three well pad in a month's timeframe and, you know, have it fracked another 30 days out. We can ramp drilling activity up in 60 days there from, you know, moving the rig in to getting first production. That's probably our best leverage, is just the flexibility of the rig. Okay. Okay, great. Thanks a lot. Yeah. Appreciate it, Noel. Have a good day. You too. Next we'll go to Geoff Jay with Daniel Energy Partners. Your line is now open. Thank you. Hey, I just wanted to circle back to the drilling and frack savings. You talked about the 10% and 18%. I was curious if that's, you know, sort of absolute pricing, if there's efficiencies kind of baked into that, and if you can help us kind of disaggregate, the pricing and the efficiency components of that? Yeah. It's definitely a combination. Would tell you that we're seeing, for the most part, prices come down across the majority of services and materials. Some at different levels, but seeing it, you know, both service costs and material costs, and on the, you know, drilling completion and even on the operating expense side, you know, on our production side, seeing chemical costs come down, trucking costs come down, as you might expect with lower fuel prices relative to last year. Breaking it out, don't have those numbers in front of us, but, you know, definitely a combination of deflation and efficiency. Steve, I don't know if you have any thoughts or comments that you could add to that. Yeah. A lot of the process efficiencies we've incurred already, experienced from essentially November to where we are right now and looking perhaps for a few more, but yet for that to taper down. Most of it at this point forward now, we're seeing in unit cost currently unit cost. If you kind of weighed that out over the course of the year, they're kind of split equally, as we look for about an overall 17%-20% reduction in both drilling and completion through the end of the year. Awesome. That's really great detail. Thanks a lot. Yeah. You bet, Geoff. Thanks. Yeah. Okay. There are no further questions at this time. I'll now turn the call back over to our presenters for any additional closing remarks. No, I'll just close by thanking everyone for joining our call today. We always appreciate the questions and the interest in the company. Look forward to further updates at the next quarter call. Everyone, have a nice day. This concludes today's conference call. You may now disconnect.