Thank you for standing by. At this time, I would like to welcome everyone to the SilverBow Resources Third Quarter 2023 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you'd like to ask a question during this time, simply press star followed by the number one. Once again, star one on your telephone keypad. And if you'd like to withdraw your question, just press star one again. Thank you. And at this time, I would like to turn the call over to Jeff Magids, Vice President of Finance and Investor Relations. Jeff, please go ahead. Thank you, Greg, and good morning, everyone. Thank you very much for joining us for Our Third 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. With that, I will now turn the call over to Sean. Thank you, Jeff, and thank you everyone for joining our call this morning. Third quarter results highlight the success of SilverBow's growth strategy. Production increased approximately 20% compared to a year ago and exceeded the high end of guidance. Our oil-focused development program has resulted in a year-over-year increase of 80% in oil and a 25% increase in NGL production. Driven by the increase in our liquids production, adjusted EBITDA of $141 million was the highest quarterly EBITDA in SilverBow's history. At the same time, we generated $18 million of free cash flow and reduced debt by $78 million during the quarter. Finally, our operational performance year to date is allowing us to further increase our full year free cash flow guidance to a range of $20 million-$40 million, while at the same time maintaining our full year CapEx guide. Our results in 3Q provide us with an attractive outlook. Guidance for our base assets, excluding any contribution from the Chesapeake acquisition, implies a 10% increase in fourth quarter oil production, and we anticipate significant free cash generation through year-end. With prices now above $3 and with takeaway constraints from Webb County being alleviated, we are once again investing capital in our gas assets. We are currently flowing back a recently completed four well DUC pad in Webb County, and we recently moved one of our two drilling rigs to this gas area. Our fourth quarter investment will set up well for uplift to our gas production in early 2024. Overall, our strong operating platform positions SilverBow to continue to grow through multiple avenues. We have championed the need for consolidation within the Eagle Ford, and recent M&A announcements around the industry have supported this thesis. In August, we announced an agreement to acquire certain oil and gas assets in South Texas from Chesapeake for $700 million. This marks our eighth and largest acquisition over the last two years. The Chesapeake transaction checks all the boxes we look for in an accretive acquisition. First, it enhances scale within our core focus area in the Western Eagle Ford, and upon close, SilverBow will become the largest pure-play public Eagle Ford operator by production. The growth from these assets positions SilverBow to exceed a 25% annual growth target in the coming years. Second, we are acquiring the assets at a discounted PDP valuation while adding roughly 300 high-confidence locations at essentially no cost. This maintains our decade-plus inventory life and adds locations that will immediately compete for capital in 2024. Third, the production base further expands our commodity exposure with a mix of assets that are spread evenly across oil, gas, and NGLs. Finally, we are financing the transaction accretively through an upsize to our revolver and second lien notes as well as our September equity offering, which will add to our cash funding sources. We see a clear path towards delevering below 1x by year-end 2024. To wrap up my prepared remarks, SilverBow continues to execute on its differentiated growth strategy while generating significant cash flow. Our liquids production growth this year, combined with plans to ramp gas production into next year, positions SilverBow as a leading Gulf Coast operating platform with the ability to further consolidate and benefit from the pending LNG expansion projects. Our team has an established track record of delivering on our key objectives through commodity cycles, and I'm very excited about both the near and long-term prospects for the company. With that said, I will hand the call over to Steve. Thank you, Sean. In the third quarter, we drilled 10 net wells, completed nine net wells, and brought nine net wells online. DNC activity was focused on our Eastern Extension and Central Oil areas. The team continues to execute on our 2023 development program, and our operational efficiency gains are driving improvements in downtime, footage per day, and overall well costs. On the drilling side, we continue to see ongoing cost deflation. Casing prices are down approximately 25%-30% year-to-date, and rig rates have dropped by roughly 20%. As for year-to-date drilling efficiencies, costs per foot are down 13% or $22 per foot compared to 2022. On the completion side, year-to-date pumping efficiencies are averaging 20% higher compared to 2022, and in the third quarter, we achieved the highest quarterly pumping efficiency so far for 2023. These gains have been driven by reductions in equipment downtime and other non-productive events. As a result, we are completing approximately 10% more stages per day on a same-store basis and completing 10% more lateral feet per day as compared to 2022. In aggregate, our total DNC costs in 2023 have been delivered 2% below AFE. We estimate that realized DNC savings are roughly 10%-15% to date, with leading-edge market rates continuing to indicate further reductions through year-end. Specific to oil, which has been the focus of our development program this year, strong well performance continues to drive oil production to new highs. Third quarter oil production increased 24% compared to last quarter and 80% compared to a year ago. Much of our oil development has focused on properties we acquired over the last two years, and well performance on these assets is exceeding expectations. Furthermore, ongoing Austin Chalk delineation across our oily acreage adds to inventory upside and possible co-development opportunities with the Eagle Ford formation. In our Webb County gas area, we were able to sell into some interruptible capacity during the third quarter. We believe gas capacity constraints are currently being alleviated and expect new pipeline capacity to come online in November. The multi-year takeaway agreements we secured earlier this year set up for continued development in this core area. We remain bullish on longer-term natural gas prices and LNG demand growth. As such, we view our Webb County gas area as a cornerstone and continue to expand our inventory through Austin Chalk delineation and organic leasing. We have now assembled nearly 20,000 net acres with 200 identified drilling locations in one of the most profitable natural gas plays in the nation. Turning to results and outlook, our third quarter production of 357 MMcfe per day was above the high end of guidance and represents a 19% increase in production year-over-year. For the fourth quarter, we are guiding to production of 364 MMcfe per day at the midpoint, a 2% increase quarter-over-quarter. We tightened our full year 2023 production guidance to a range of 336-342 MMcfe per day, which implies overall production growth of 20%-26% and oil production growth of 94% year-over-year. All forward-looking estimates exclude any contribution from Chesapeake assets. Specific to our capital budget, our previously lowered guidance of $400 million-$425 million remains unchanged. Given the efficiencies realized to date, we will be able to accelerate the completion of timing of several pads we had scheduled for early 2024, and therefore able to absorb that DNC spend in 2023. As discussed on prior calls, we allocated 100% of our DNC capital to oil development through the third quarter. Currently, we have moved one of the two rigs back to our Webb County gas area, where we are further testing the Austin Chalk formation. We expect our two-rig program to remain split between oil and gas drilling through year-end. As always, we remain flexible on our capital allocation as we optimize our drill schedule and completion activity accordingly. With that, I'll turn it over to Chris. Thanks, Steve. In my comments this morning, I will highlight our third quarter financial results, as well as our price realizations, hedging program, operating costs, and capital structure. I will then also provide a brief update on our announced Chesapeake transaction and our pro forma capital structure. Third quarter oil and gas sales were $174 million, excluding derivatives, with oil representing 26% of production and 65% of sales. Of note, oil represented just 30% of third quarter sales one year ago. During the quarter, our realized oil price was 97% of NYMEX WTI. Our realized gas price was 90% of NYMEX Henry Hub, and our realized NGL price was 26% of NYMEX WTI. Year to date, our realized gas price has been impacted by widening basis differentials and is lower than our historical range compared to Henry Hub. More recently, we have observed differentials that are closer to historical averages as the regional market has become more balanced. Risk management is a key aspect of our business, and we are proactive in adding basis to further supplement our hedging strategy. For 2023 and 2024, we have secured gas basis hedges on 150 and 180 MMcf per day, respectively, to mitigate further risks. Our realized hedging gain on contracts for the quarter was approximately $18 million. Based on our hedge book as of October 27th, for the remainder of 2023, we have approximately 200 MMcf per day of natural gas hedged, 11,100 barrels per day of oil hedged, and 3,750 barrels per day of NGLs hedged. Using the midpoint of our production guidance, we are 92% hedged on gas and 66% hedged on oil for the remainder of this year. For 2024, we have approximately 211 MMcf per day of natural gas hedged, 11,800 Mbpd of oil hedged, and 5,400 Mbpd of NGLs hedged. The hedged amounts are inclusive of both swaps and collars. A detailed summary of our derivatives contracts is contained in our presentation and our 10-Q filing, which we expect to file later today. Our third quarter costs were within or favorable to our third quarter guidance ranges across all categories. Lease operating expenses were $0.71 per Mcfe. Transportation and processing costs were $0.42 per Mcfe. Production taxes were 6% of oil and gas sales. Cash G&A, which excludes stock-based compensation, was $3 million for the quarter. For the full year, 2023, we are guiding for cash G&A of $17.7 million at the midpoint, which implies cash G&A on an Mcfe basis to continue to trend below 22 levels. We consider our lean cost structure to be a differentiator when compared to our peers. SilverBow reported a net loss of $5 million for the third quarter, excluding unrealized losses on commodity derivatives. Net of the tax impact, SilverBow reported adjusted net income of $56 million, or approximately $2.42 per diluted share for the third quarter. As reconciled in our earnings materials, we recorded free cash flow of $18 million for the quarter. For the full year, we are increasing our free cash flow guidance to a range of $20 million-$40 million. Turning to our balance sheet, total debt was $648 million. This is a decrease of $78 million from the prior quarter as we generated free cash flow and completed an equity raise in the quarter, offset by a $50 million deposit for the Chesapeake transaction. As of September thirtieth, we had $279 million of liquidity. Our LTM adjusted EBITDA for covenant purpose was $485 million, and our quarter-end leverage ratio was 1.3x. Consistent with our strategy, excess cash flow that is not reinvested through the drill bit will be used to pay down revolver borrowings, and SilverBow continues to target a long-term leverage ratio of less than 1x. At the end of the third quarter, we were in full compliance with our financial covenants and had sufficient headroom. As Sean previously mentioned, SilverBow announced the acquisition of certain oil and gas assets in South Texas from Chesapeake for a purchase price of $700 million. Chesapeake may also receive up to $50 million in contingent cash consideration based on future WTI prices. In conjunction with the closing of the transaction, which is expected to be in the fourth quarter, SilverBow has secured a borrowing base upsize commitment of $425 million, which will increase our borrowing base from $775 million to $1.2 billion. Also, upon close, we will upsize our second lien notes by $350 million, which will increase our total facility size to $500 million and extend the maturity date by two years to December 2028. In addition to customary purchase price adjustments, the $50 million deposit further reduces the cash payment at close. As a closing condition, SilverBow is required to have 75% of oil and gas PDP volumes hedged for the first 24 months following closing, and 60% of volumes hedged for months 25 through 36 following closing. We have been proactively adding hedges to meet these requirements over the last several months at or above our underwriting. Lastly, in September, we completed a $148 million follow-on equity offering, consisting of 4 million shares. Approximately 70%, or 2.8 million shares, were primary shares issued by SilverBow. Net of the secondary shares issued, the underwriting spread and offering fees, the net cash proceeds received by SilverBow was approximately $97 million. These proceeds were used to reduce credit facility borrowings ahead of closing the Chesapeake transaction. With that, I will turn it over to Sean to wrap up our presentation. Thanks, Chris. SilverBow continues to execute on its strategy and is positioned for significant value creation. The transformational growth we have achieved over the last two years has been underpinned by a low cost and highly efficient operating platform that is able to expand through accretive acquisitions. We expect M&A to remain a central theme across the sector in the near term. As always, our strategy emphasizes operational flexibility and real-time capital allocation to our highest returns on investment. The ability to pivot between oil and gas development has been, and will continue to be, a competitive advantage for us. I want to thank our stakeholders for their continued support. We look forward to closing the Chesapeake transaction in the fourth quarter and providing further updates on our next call. With that, I will turn the call back to the operator for questions. Thank you so much. At this time, I would like to remind everyone, in order to ask a question, again, press star one on your touch tone keypad, excuse me, and we'll pause just a moment to compile the Q&A roster. Okay, looks like our first caller is Tim Rezvan from KeyBanc Capital Markets. Tim, go ahead. Hey, good morning, everybody, and thank you for taking my question. I guess first, just wanted to, you know, pick at the, you know, the Chesapeake acquisition. The timing is sliding a bit here. Just to ask the big question, is there any concerns that this deal doesn't close? I guess I'll start there. And then related to that, are you having—if that's not the case, are there discussions underway on gas takeaway terms with Williams, kind of given the unique structure that Chesapeake had? Thanks. Hey, good morning, Tim, and thanks for the question. In terms of your first question, we, you know, continue to work closely with Chesapeake, and, you know, when we first announced the transaction, felt like, and disclosed to the market that we would close the transaction in the fourth quarter. We remain on track to do that and are confident that the deal gets closed here in the near future. In terms of activity on the asset, I will tell you that we're, you know, working closely with Chesapeake's team, as well with our—within our company, our teams, to be ready to take control of the asset. So we're confident that we'll be able to integrate the acquisition very successfully, just like we've done with previous deals. And then lastly, in terms of trying to optimize the asset going forward, you raised the question around pipeline agreements that the asset has. You know, I think as we dig in and really start to you know really put our focus on the asset and grow volumes, there may be opportunities to revisit contracts that improve the efficiency of the asset. So, it's definitely something that's on our radar, and you know, we'll see if there's opportunities to address something there in the future. Okay, thanks. We'll, we'll stay tuned in that. Yeah And then, I thought it was interesting, Sean, your closing comments, you talked about M&A as a central theme for the sector. So if I could, you know, redirect that to you, is M&A still? Like, how high on your radar screen is that as you get to the finish line with Chesapeake? And then given that you put a 1x leverage target at the end of year-end 2024, if we think about future M&A, and you've been active, how sort of fungible is that target if you find the right deal? Just trying to understand that as you balance deleveraging versus growth. Yeah. Yeah, you know, obviously, we've been very successful on doing transactions, and I think, we, you know, are very efficient at integrating them into the business once we identify them and close them. But we'll continue to use our criteria that we have all along, right? First, it has to be, you know, makes a lot of industrial sense in or around our existing asset base, brings inventory in that competes for capital. And to your point, most importantly, it's an accretive transaction from all the share metrics, as well as it doesn't put any stress on the balance sheet. So we'll continue to look for all those. For now, our focus is on getting the Chesapeake transaction closed and integrated, but our BD team is always looking at other opportunities, and we'll be very thoughtful on any other future transactions that we do. Okay, thank you. Our next question comes from Charles Meade with Johnson Rice. Charles, go ahead. Good morning, Sean and Steve, and the rest of the SilverBow team. Sean, I recognize you don't, you know, you guys don't have the Chesapeake assets yet, but I really appreciate that you share with us on slide 15, the well results that I guess Chesapeake has shared with you. And so I wonder if you could talk about about how these wells kind of came in with your what you expected or what you underwrote on the acquisition? And maybe in particular, it looks like that Faith Sandy pad looks the most attractive to me, not just because of the overall BOE/day rate, but also the 70% oil cut. Does it look that way to you? Yeah. Yeah, kind of big picture, you know, when we announced the deal, we discussed that, you know, the asset was going to see a ramping of production from 2Q into 3Q as many new wells were brought online. I think Chesapeake recently announced in their call that the asset did 32,000 BOE a day for the third quarter, and that was right in line with what we felt like it was gonna do. So overall, the asset is, you know, performing up to what we had underwrote the deal for for the third quarter. Now, specific to the wells, you know, we've been continuing to monitor the performance, the performance of the new wells brought online, would tell you that overall, the program is performing at what we expected it to. You know, a few wells performing above type curve, a few wells below, but right in line overall. In terms of your call-out of the Faith property, you know, those wells being all Eagle Ford wells, that's a really good area, and performed slightly above where we thought. So, encouraging to continue to see strong Eagle Ford wells in that part of the property. Got it. And then, my, my second question is really about trying to get a sense of SilverBow standalone going into 1Q 2024. And I, I recognize you, you guys, you haven't, you haven't given 2024 guidance, and that'll come. But, but I'm wondering if you can just help me kinda put some of the pieces on the table, because it looks to me that particularly with you guys accelerating that, that 4-well gas pad and also the, the 3-well oil pad into 4Q, it looks to me like you're setting up for actually a big, a, a big step up in organic growth in 1Q 2024. So I guess maybe the context. Steve, you mentioned that you, you brought nine wells online, y ou turned nine wells to sales in Q3. Can you tell us what you think that number will be for Q4? And do you, does it also look to you like you're gonna have a big step up organically for 1Q 2024? Yes. Thank you, Charles, for the question. Yes, we're looking for Q4, we're looking for one of the four-well pads, oil pads that we're currently completing right now to come online. And then additive to that, we're looking to at our discretion to accelerate maybe another three-well pad, another oil well pad over in the eastern extension to come online, along with if we have some optionality for some additional gas in Webb County. So that's kinda how it sets up right now today forward to the end of the year. And then with that, we're looking at Q3. In terms of our oil production per day, we are looking at about, oh, say better than, you know, like we were guiding to before, we're looking at better than 15,000 per day, and about probably better than, you know, better than 16,500 or so, roughly in that range for the fourth quarter. Yeah, yeah, Charles, so the way it's lining up, right, is we expect we'll see strong oil growth, like we mentioned in the call, about 10% growth, 3Q to 4Q on oil. And anticipate with the acceleration of that three-well oil pad, that we'll have strong exit rates. Then the gas starts to kick in, and so we'll have continued growth on an equivalent basis, from fourth quarter to first quarter, with much of the growth in the first quarter being driven by the high gas rate wells that are coming on. So yeah, I think on the base assets, continued strong organic growth, you know, really driving the growth on oil through end of year, and then starting to see the ramp of gas into the first quarter. Okay, great. Thank you. And our next caller is going to be Donovan Schafer from Northland Capital Markets. Donovan, please go ahead. Hey, guys. Congratulations on the quarter, and thanks for taking the questions. I wanna start, you know, kind of dovetailing with the questions, prior questions. You know, of course, you don't have 2024 guidance, and that's not something, you know, we're really here to talk about in any sort of formal way or official way today. But what I wanna, the way I try to think about things or frame things is when you announced the Chesapeake transaction, you know, middle of August, based on the slide deck you shared at the time, it looks like you must have gone through a pretty thorough, you know, internal set of projections around everything. You know, given, you know, you showed your path to getting down to a 1x leverage ratio in 2024. You kinda put out some numbers and the relative% increase that you'd get in 2024, free cash flow per share, and some other things like that. So, my question is, between—you know, in the last sort of two and a half months between putting that deck together or going through that exercise and where we stand today, your own kind of internal sense for 2024, has that directional—is it fair to say that that's directionally improved? As you know, with the capital budget, you've been able to pull forward some of that into this quarter and get some wells done more quickly. Like, it seems like there's, you know, and the takeaway capacity improving. It seems like there have been more positive developments. So would you expect things to come out more favorably today if you re-ran that exercise for, you know, for the whole company, in comparing the, you know, before and after of the acquisition? Yeah. I would tell you that the base assets for SilverBow are performing well. Came in a little slightly ahead for third quarter, kind of in line, you know, for 4Q guide in full year. So the base assets are, you know, performing well, probably a little less CapEx with the cost reductions that Steve outlined. And then, had mentioned earlier, the Chesapeake assets are kind of performing in line with what we can see on a read-through with the information we're receiving from a production standpoint. So I think what we disclosed at the time of the transaction, kind of laying out that, you know, over the next 12 months, we see EBITDA in that $825 million-$925 million range, and production, you know, in the mid-90,000, you know, 93,000-95,000 MBOE a day. Those numbers we still think are at, you know, kind of where we're at, and you know, think that we'll be able to deliver those once we take control of the asset and get into next year. Okay. And then, as a follow-up, just, you know, since you're not including the Chesapeake acquisition, and the PDP production that would come with that in the Q4 guidance, and then, you know, but you also do still expect it to close in the fourth quarter. Is it, y ou know, I guess, it feels like this kind of almost automatically follows by logic, but I'm just trying to be thorough and double-check things here. Does that mean it's, in your view, it's sort of safe to say the actual Q4 results should come in above guidance, and maybe, you know, the extent to which it's above guidance, it'd be, you know, more so above or only slightly above, kind of depending on how—whether it closes sooner or later? And I'm asking partly just because, you know, optically, it would look like your Q4 guidance is below consensus, but my sense here is that that's probably kind of because of the difference here. I'm guessing analysts are maybe factoring in those additional assets. I just want to make sure I'm thinking about all this correctly. No, no, great question, and, and, you're spot on with the observation. You know, I think as we've given a guide of sometime in the fourth quarter, analysts have done the best with the information we've provided to you know, model when that might occur, and, you know, somewhere you know, several of them probably projecting a mid-quarter call or a mid-quarter close, with others maybe projecting a December close. So, the guide that we put out yesterday was for standalone SilverBow only. Once we do close the deal, and give an update to the market on the 4Q estimate and guide, you'll see, I think, a true up with a lot of the projections that are out there. So yeah, just to be clear, right now, we're out in the market with just SilverBow standalone numbers, where many of the analysts covering the company have a, you know, combination of SilverBow standalone plus a partial quarter of Chesapeake contribution. But yeah, and like I said, once we do close, we'll plan to give an updated guide for the adjustment for the the So- the Chesapeake assets coming into the SilverBow numbers. Okay, thank you. Our next question comes from Noel Parks with Tuohy Brothers. Noel, go ahead. Hi, good morning. Hey, morning, Noel. You know, one thing that you talked a little bit about in the prepared remarks, and I also saw in the release, you were talking about Austin Chalk co-development, I think, in the Central Oil Area, and I recall more past discussion about the Austin Chalk, particularly in Webb County. So, what's the current thinking about the Chalk that you offered in the oily areas now? Yeah, you know, our team over the last several years has really dug in on the Austin Chalk, started in their work in Webb County, and we've, you know, shared a lot of that information and it's, you know, in a lot of our materials. But coming into this year, we had identified a couple areas that had Chalk potential, primarily in our Central Oil Area, but also in our Eastern Extension Area. So we've, you know, in combination with drilling Eagle Ford, have slotted in some chalk tests at the same time. And so I think it's on slide 15 of our presentation, we outline in that Central Oil Area a number of pads where we drilled chalk wells on. So, we've brought on, I think three chalk wells in that area thus far. In all, we're meeting or slightly above our expectations, so pretty excited about that. In the Eastern Extension Area, we brought on three chalk wells to date, and those wells are kind of early on in their performance, so we're still assessing those results. But, I think it just points to that, hey, there's stack pay opportunity within the basin. You know, we have a large footprint with, you know, post the Chesapeake close of nearly 250,000 acres. And what's great about it is, you know, we'll continue to scour not just the Eagle Ford, but also other zones across that acreage block. ... Great, thanks. Well, with the Eagle Ford, of course, like with any development process, you're always learning and gathering data. And, you know, the Austin Chalk has had so many different lives across so many different basins over the years. So, is there anything in particular incrementally that your experience in Webb County has sort of brought to the table that you know that clarified that you did have some decent potential in parts of Central Oil and Eastern Extension? And could you give a shot at sort of what that might mean in terms of you know how many locations you might have incrementally, or just portion of the overall acreage where the chalk might work? I guess if you can talk about what, you know, what characteristics make it look better some places than others, that'd be great. Yeah. Yeah, really the fundamental change, right, from historical chalk development both up in Giddings and through like the Karnes, the Austin Chalk Trend that saw quite a bit of activity, you know, through 2017, 2018, 2019 timeframe. What emerged with the Webb County Chalk was development, not necessarily chasing fractured chalk, but more porosity driven chalk. And so when we really started to, you know, understand that better in Webb, we took that mindset and thought elsewhere. Obviously, we identified in conjunction with the SM play in Northern Webb, the potential that it had, and, you know, that's why we were patient and pursued the Chesapeake transaction because we're really excited about the chalk there. But then, you know, took that same model elsewhere, and it, it's starting to replicate itself. The chalk doesn't have good porosity and doesn't have, you know, enough thickness across the good portions of the basin, but we've found pockets where it does. So that's kind of the difference in the models from historical to what we're pursuing, I would say is less of a fracture play and more of a porosity, thickness-driven play. So a little bit of conventional reservoir development using, you know, horizontal drilling and fracturing to unlock the resource. In terms of quantifying the inventory, obviously, you know, Webb County is where we have a lot of it. You know, we have a couple of 100 well, probably [2,500] and m aybe probably 125 gas chalk locations off the top of my head, and similar numbers in the Chesapeake, if not a little bit higher. Across the other ones, we're still in the process of kinda quantifying that, so haven't added that to our materials yet. Our footprint there is smaller than our Webb County, so it's not gonna be to those extent, but we're gonna, you know, it's gonna be additive to our inventory for sure. Okay, thank you. And our next caller comes from Jeff Robertson with Water Tower Research. One more time, if you'd like to ask a question, it is star one on your touch tone keypad. And Jeff, with that, go ahead. Thank you. Good morning. Question on the Chesapeake assets. With the new wells that you highlighted that are being brought on, can you talk about the natural decline on that asset base when you fold it into SilverBow, and how that impacts the overall, corporate natural decline rate? Yeah. Yeah, Yeah, the, you know, the Eagle Ford, Chesapeake had developed that asset base, you know, going back as far as, what, 2008, 2009 timeframe. So, overall, it has a lower, that asset base is- has a lower decline rate than SilverBow standalone. So we're expecting that it'll, you know, flatten our, our decline, the, the base decline on our combined asset, here moving forward. So brought it down probably a couple, couple percent, you know, high- 20s, low- 30s on a standalone basis, down, you know, the exist- the Chesapeake assets were probably in the mid-20s, a little bit higher than that. So, you know, dropping it to combined, probably, a 1% or 2%. If you think about co-developing the chalk in the Eagle Ford in some of your areas, does that have any issues with respect to infrastructure that needs to be addressed? No, actually, it's a benefit, you know, especially in our Webb County area, both on the SilverBow existing assets and then on the Chesapeake assets, is we're able to leverage the existing Eagle Ford infrastructure and put the chalk into it. So, most of those assets were put in place to capture peak Eagle Ford development and have declined off a little bit since the Eagle Ford has. So, bringing on the chalk, we're actually taking advantage of existing infrastructure. Thanks for taking my questions. Yeah, appreciate it. Okay, we have another question from Noel Parks with Tuohy Brothers. Noel, go ahead. Hi. Did just wanna get your thoughts on one other topic. So, the gassy E&Ps, a number of them were the earliest ones to report. And as we listen to those companies talk about their outlook, they're, of course, extremely focused on LNG capacity coming online starting next year, and what that does to the overall demand picture, and hopefully to commodity prices. I just wondered, can you just talk a bit about your general thoughts on the gassy Eagle Ford's role in LNG? And I guess I'm wondering in particular, out in Webb County area, whether you are maybe seeing new players coming in, kicking the tires because of course, everyone, the Appalachia room is large, the Haynesville room is large. I'm just wondering about, you know, maybe what we should be looking for, in either, you know, new capital coming in for development or maybe even new purchasing or consolidation in the area. Yeah. Yeah, I think that, you know, as you look at the amount of LNG build-out slated over the next several years, you start to kinda look at the imbalance of the demand of that LNG build-out versus the supply and where is it gonna come from? And, you know, kind of the acknowledgment that getting more out of the Appalachia is somewhat challenged just from pipelines being able to get to the Gulf Coast. Obviously, you've got strong growth in the Haynesville, but there's still a gap to fill that LNG build-out. So yeah, we're seeing that the Eagle Ford and, you know, just the strong performance of Webb County over the last few years, us plus, you know, others, see that, as, you know, probably one of the first places to look at to help fill that forthcoming LNG demand. So, yeah, I think it's existing players plus, you know, new entrants that are looking to, you know, find gas to fill some of the LNG expansion that they're, you know, contracting into. So sets us up well. We're long-term players in the area, understand the reservoir well, have a lot of, you know, great existing relationships and infrastructure there. So we're excited about the opportunity it exposes us to much stronger gas prices in the coming years. Great. Thanks a lot. Yeah. Appreciate it, Noel. Okay. Thank you all for your questions. With that, I will turn the call back over to CEO Sean Woolverton for closing remarks. Hey, appreciate that, Greg. Well, we'll wrap up. I'll say, I look forward to giving an update, hopefully here in the near future, on the close of Chesapeake and giving everyone an early preliminary view, look into our plans for 2024. And with that, we'll conclude our call. Thank you. Thanks, Sean. Ladies and gentlemen, that does conclude today's call, as he mentioned. Thank you all for joining, and you may now disconnect. Have a great day, everyone.