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spk03: 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 silver bow resources first quarter 2023 earnings conference call today's conference is being recorded all lines have been placed on me 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 the number 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 Magid, Vice President of Finance and Investor Relations. You may begin your conference.
spk04: Thank you, David, and 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 Wolverton, our CEO, Steve Adam, our COO, and Chris Abundas, 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 risk 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. With that, I will now turn the call over to Sean.
spk11: Thank you Jeff and thank you everyone for joining our call this morning. Silver Bow 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 DNC 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, Twenty-three oil production will increase by approximately 100 percent compared to 22. 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 Silver Bow has realized to date. By year end, our production mix should be comprised of 40 to 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. Silver Bow'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 callers. Should gas prices improve, we have a Fasken duct pad which we can complete later this year. It's worth highlighting that the acquisitions we made in 21 and 22 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-plus 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 Silverboat. 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.
spk08: 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 BNC activity was focused on our central oil and western condensate areas, as expected with the 23 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 22. 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 path, 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 22%. Furthermore, we are capitalizing on early cost deflation trends in the market. Recently, we have seen cost relief on rigged day rates, tubular goods, wellhead equipment, and fuel. Fract 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 Eagleford 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. However, 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, and 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 mm CFE per day was at the midpoint of our guidance, with oil production at the high end of the range. For the second quarter, we were guiding to production of 325 per day at the midpoint, which implies a 5% to 10% production increase sequentially. Full year 23 production guidance of 325 to 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 to 50% of our total mix. With that, I'll turn it over to Chris.
spk07: 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. and 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 contract for the quarter was approximately $20 million. Notably, our first quarter hedge revenue per MCFE of $5.84 was the highest revenue per unit Silver Bow 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 mixed 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 hedge, 7,400 barrels per day of oil hedge, 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 mm CF 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 10Q filing for the first quarter, which we expect to file later today. Turning to cost, lease operating expenses were 78 cents per MCFE. Transportation and processing costs were 42 cents 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 Silver Bow 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 to $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 a Webb County gas wells drilled in the fourth quarter of last year and ongoing gas curtailments in Webb County. The timing of DNC projects and land span 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. However, 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. Silver Bow, 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 in leverage ratio to 1.4 times. The system 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. And Silver Bow 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. And with that, I will turn it over to Sean to wrap up our prepared remarks.
spk11: Thanks, Chris. Silver Bow 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 release of our inaugural sustainability report in the near future. I want to thank all of our stakeholders for the continued support. We look forward to providing further updates on our next call. And with that, I will turn the call back to the operator for questions.
spk03: Thank you. At this time, I'd like to remind everyone, in order to ask a question, press star number one on your telephone keypad. We'll take our first question from Donovan Schaefer with Northland Capital Markets.
spk09: Your line's open. Mr. Schaefer, go ahead. Your line's open.
spk06: Sorry about that. I muted myself. So I want to start off with interruptible capacity markets. I was just curious if you can give us a sense for magnitudes around what you may or may not be able to ship via interruptible capacity. I mean, I know that's super hypothetical, and I think, correct me if I'm wrong, but your guidance kind of assumes not having any interruptible capacity on the gas side. So I'm kind of just thinking in terms of error bars here. Of course, you guys don't have a crystal ball, but just sort of in theory, is this the type of thing where when interruptible capacity is available, that can add like another 5% to 10% of volume, but then maybe that's like one day a week, so then it ends up being de minimis? Just kind of trying to get my mind around how to just think about it more conceptually.
spk11: Yes, I appreciate the question. And, you know, your question around how much availability is there and how sustainable it is is kind of spot on. When we do see available capacity, it's probably, you know, 5 to 10 percent above what we can produce. So that's not a bad number. But 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.
spk06: Okay, and then I also want to ask, you know, the efficiency gain. It sounds like, you know, DNC costs, you've got the deflation aspects, but also pretty significant efficiency improvements. And so I'm wondering, is this is it unfolding in a way, the sort of efficiency improvements and the uptime you talked about with the frack spreads, is that kind of a proof point or unfolding in a way that's in line with or consistent with the initial part of the strategy and the idea around being just one of a couple consolidators in the Eagleford? I think the idea 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, but then 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. So have you been able to kind of get crews that you feel like are kind of high quality and then retain them? Is it, I guess, unfolding in a pattern in the nature that you were kind of thinking back to the original consolidation strategy?
spk11: Yeah. 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 consistent operations over a long period of time as we're able to level load our services. And we are seeing that play out. We continually work with our service providers to build stronger partnerships. We pride ourselves on being prudent schedulers. And I think we get that feedback from the service providers that we put more consistency into their schedule. And as a result, we're seeing improved performance from their side of the business. So I do think it's not easy to be a consolidator. It takes an operator that has a proven track record. And I think our company has demonstrated that and that we continue to best our record performance quarter in and quarter out. And I think it speaks to just having a larger footprint and more level-loaded operations.
spk06: Okay, that's helpful. And then I guess my last question and I'll take any others offline or maybe I'll jump back in the queue. But the last question I've got for the moment is with the new pipelines you talked about coming online kind of towards the end of the year, kind of similar type of question to what I was asking with the interruptible capacity. Can you just give us a higher level kind of framework or conceptual way to think about these new pipelines, the magnitude of the volume they could move relative to what is the takeaway capacity existing? Is this a 20% increase, 30% increase of what capacity to take away from the region where you're producing? And then if possible, what does that translate into for basis or pricing improvements Again, I need to have a crystal ball and like Ben, you know, of course benchmark prices and everything. So maybe it's something best to talk about in kind of relative terms. But you know, if you have something along the order of, you know, well, if the, this is going to increase capacity, take away capacity 30%, and that would tend to translate into like a 10 ish or 20 ish percent or even more, like it's more levered to the capacity. Again, just kind of trying to get the framework to think about what those could mean.
spk11: Yeah. Yeah, definitely the Webb County dry gas play has really boomed over the last 18 to 24 months as several large operators have come in and started to develop the high-quality Eagle Fern and Austin Chalk Zones. 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 doubles it, but takes it to about four and a half BCF a day of potential expansion. So definitely provides for more volumes to come out of the area in the years to come. Now speaking to what's that mean from a basis differential standpoint, Our view is we're still very bullish on gas, especially as you get into 25, 26 timeframe with a lot of new demand coming online in the Gulf, primarily on the LNG export front. And so, you know, I think you look at macro forecast across the big gas basins and there's going to be a shortage in our belief of gas volumes once we get to that period of time. This expansion in Webb County we think is going to 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 close to 9x pricing as we move forward into the late 24-25 timeframe.
spk06: Okay, so thinking, you know, the benchmark goes up and then you're not going to suffer any penalty or getting boxed out from benefiting from that. So benchmark goes up and you get kind of a clear translation into that. Okay, that makes sense. All right, thanks, guys. Appreciate it, Donovan. Thank you.
spk03: Next we'll go to Charles Mead with Johnson Rice. Please go ahead.
spk01: Good morning, Sean, to you and the whole Super Bowl team there. Thank you. Good morning, Charles. I wanted to ask a question about your eastern extension, and I think Steve touched on this in a few of his prepared comments, but 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 Eagleford and one Austin Chalk, and also I think there's plans to – you've moved a rig there, or maybe you're about to move a rig there, and do more of this Eagleford and Austin talk. So 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 risk to plan?
spk11: Yeah, you bet. Just to recap, This block is a result of two acquisitions that we did, one in 21 and one in 22, where we put together just under a 20,000 acre block and consolidated the working interest within the block and wanted to get that all in place before we went in and started drilling. So early in 23, we drilled our first two-well pad, one Eagleford, one Austin Chalk, like you mentioned. The wells just came online. They're still ramping. We haven't quite reached IP or just starting to get there. We wanted to not get out in front of results on the quarter announcement, but to Steve's comment in the script, we're pretty excited with what we're seeing. I can tell you that the results are coming in line or exceeding to date.
spk01: comment that we're going to 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 and so so the rig rig was there jill the two well pad sounds like it moved off but you're gonna you're gonna park one there for the second half that that's the outlook that is got it thank you sean and and then um second uh a follow-up to the uh you know on the the whole a d landscape We've seen some, from my perspective, it looks like the A&D and the Eagleford 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. And then this morning, we have a company that's been a longtime player in the Eagleford, selling its position and concentrating in the in the Permian, so I wonder if you could give us your thoughts about what the potential and what the landscape looks like today, and particularly, are there chances for you to perhaps de-lever through some acquisitions in the Eagleford?
spk11: Yeah, the Eagleford definitely has been an area of significant activity really over the last nine months now. And like you mentioned, just over the last couple of days, there's been a couple of transactions announced as well. One public selling to a private and one private selling to a public. So continues to be a range of activity and a range of size and scale with many of the packages being announced between prices of a half a billion up to two and a half billion. A lot of interest in the Eagleford for the reasons we've laid out in the past. Begs the question, how much activity remains in the Eagleford and can Silver Bow participate in that? Yeah, we still think there's a lot of further consolidation to occur. We think that there's two reasons to do that and the Eagleford sets up well for it. First is the gas window of the Eagleford. The economics are very strong and look, you know, extremely attractive moving into a contango price curve. So we think there's an avenue there. And then we think that, you know, it's becoming more in the view that core inventory is starting to dry up in a lot of basins. And we think that there's runway in the Eagleford and folks recognize that. So we think there's consolidation that can occur, especially in the western Eagleford area. 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. So, yeah, we think Eagleford will remain active, and our plan is to be active in it. And we think that through that growth, there's opportunities, like you mentioned, to deliver based upon, you know, how we structure the deals. That's helpful detail on your thinking. Thanks, Sean. Yeah.
spk01: Thanks, Charles. Have a good day.
spk03: Okay, next we'll go to Neil Dingman with Truist Securities. Your line's open.
spk13: 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've mentioned potentially in the release about slowing gas-focused activity later in the year, but I'm wondering if oil continues to go lower, creep lower like it's doing, and gas remains weak, would you 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.
spk11: Yeah, yeah, no, you know, one of our guideposts is to spend within cash flow. And so we're going to continue to adhere to that. And, 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. So, 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 contractual obligations on the service side, any meaningful MVCs or land commitments that can't be handled with with one rig or even less than one rig. So, yeah, we're really, hey, plan to stick with the strategy of growing, but doing it within cash flow. And 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.
spk13: Yes, really like that optionality. And then my second question is, how big a benefit do you believe, I mean, maybe even for the remainder of this year, next year, how big a benefit do you believe your operating efficiencies that you continue to see and potential softening OFS costs could have on the plan?
spk11: 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. It 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. But yeah, we think the way things are setting up, there's probably, you know, a 10 plus or minus 10%
spk05: 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 neil have a good day okay next we'll go to uh tim resvin with key bank your lines open good morning folks thanks for uh uh letting me ask a couple questions um charles uh sort of stole my topic on the eastern extension but i thought i'd um maybe pick at it a little a little more um So obviously you seem excited. You don't have numbers to share. Was the decision to move that rig for 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?
spk11: Yeah, we had had our plan, had us moving the rig there, but 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, but, 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, but just wanted to, you know, make sure we felt comfortable and felt it was prudent to to get two wells under our belt versus getting in there and drilling, you know, a half dozen before we saw some results. So, really, it's the two wells to date are confirmation of our expectations, and it's really a sticking with our plan. Okay.
spk05: Okay. So, I guess we'll, in the next quarter, get some numbers around that. Yeah, definitely. Okay. I know it's early, but can you talk about the the oil cuts there relative to kind of the western liquids area?
spk11: Yeah, so our position really spans, you know, the windows, you know, 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, so 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. So kind of a mix there. So 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.
spk05: Okay. Okay. We'll look forward to results there. And then somewhat related to that, I'm just trying to reconcile a little bit of housekeeping, you know, on the modeling front. Press release talks about oil. I think it was 40% to 50% of production by the fourth quarter. Slide deck said liquids are 40% to 50% in the second half of the year. Oil was 22% of production in the first quarter. Should we just think about that as sort of a steady ramp to kind of a mid-40s level by the fourth quarter? I'm just trying to understand how to sort of model this transformation.
spk11: Good question, and probably we need to look and make sure we're consistent on the nomenclature. The 40% to 50% is a reflection of total liquids percentage, not oil percentage. Think of it, yeah, 40% to 50% liquids. Of the liquids, two-thirds is oil, one-third is NGLs.
spk05: Okay.
spk11: We'll look to make sure we clarify that if we have a mix of nomenclature scattered across press release, corporate presentation. Yeah, thank you.
spk05: So just, okay, just to clarify then, should we think about oil being 30, mid-30s percent of production in the fourth quarter or kind of, you know, just trying to get our arms around. Is that what you're sort of saying?
spk11: Yeah, trying to do the math in my head. But yeah, I think we'll be, you know, into the 30%, probably low 30s.
spk05: Okay. Okay. I can, I'll nag Jeff offline about this, just to make sure we're thinking about it correctly. But appreciate the comments. Thanks.
spk10: Yeah. Yeah. Thanks, Tim. Have a good day. Okay.
spk03: All right.
spk09: Next, we'll go to Noel Parks with Tuohy Brothers. Your line's open. Good morning. Good morning, Noel. Just a couple things.
spk12: Wondering about the co-development of the Eagleford 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 of site selection, sort of pre-drill analysis?
spk11: Yeah, no, there is some operational differences between the two zones, but 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, and 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 stream going into the Eagle Fert. So 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. And from a frac completion side, our recipe is kind of the same and we see similar type treating pressures. no on-the-fly adjustments needed as we cymofract between Eagleford and Austin Shock. We're not having to adjust prop or chemical makeups or anything like that. Steve, I don't know if I missed anything that you might want to add.
spk08: I think you covered it excellently. And then we've just done a little more fine-tuning on mud weights for both of them, for both wellbore stability as well as well control.
spk09: OK, great. On those, OK.
spk12: And I was wondering, you know, as we continue a few more months on this sort of tough meter term net gas environment, thanks for the reminder that you do have the pad that you could move up and complete if prices rebounded. I was thinking about other opportunities if we do see sort of a return to volatility that takes us up. In your gas area out west, are you at the point that there is significant potential re-completion activity out there? I'm thinking about things that could be maybe mobilized relatively quickly and have a good return in the event gas does pop up near term.
spk11: Yeah, 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. So, we don't see that area as, like, a high workover, high recompletion 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 underloved over the last couple years. So, we've been having some success on that front. Sure. Yeah, 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. But the other thing is that we're just so efficient, you know, over a two-day period, we can move a rig back in there, drill a, you know, three-well pad in a month's time frame and, you know, have it fracked another 30 days out. So we can ramp uh drilling activity up in 60 days there from you know moving the rig into getting first production so that's probably our best leverage is just the flexibility of the rig okay okay great thanks a lot yeah appreciate it no have a good day next we'll go next we'll go to jeff j with daniel energy partners your line is now open
spk02: Thank you. Hey, I just wanted to circle back to the drilling and frac savings. You talked about the 10% and 18%. And I was curious if that's 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.
spk11: Yeah, it's definitely a combination. I 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 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 definitely a combination of deflation and efficiency. And Steve, I don't know if you have any thoughts or comments that you could add to that.
spk08: Yeah, a lot of the process efficiencies we've incurred already experienced from essentially November through 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. So if you kind of weigh that out over the course of the year, they're kind of split equally as we look for about an overall 17% to 20% reduction in both drilling and completion through the end of the year.
spk02: Awesome. No, that's really great detail. Thanks a lot.
spk10: Yeah, you bet, Jeff. Thanks.
spk03: Okay. And there are no further questions at this time. I'll now turn the call back over to our presenters for any additional closing remarks.
spk11: No, I'll just close by thanking everyone for joining our call today. We always appreciate the questions and the interest in the company and look forward to further updates at the next quarter call. Everyone have a nice day.
spk03: This concludes today's conference call. You may now disconnect.
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