SilverBow Resources, Inc. (NYSE:SBOW) Q3 2023 Earnings Call Transcript

SilverBow Resources, Inc. (NYSE:SBOW) Q3 2023 Earnings Call Transcript November 2, 2023

Operator: 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 speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] 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.

Jeff Magids: 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 will 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 SEC which are also available on our website. With that, I will now turn the call over to Sean.

Sean Woolverton: 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 with 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 to $40 million, while at the same time maintaining our full year CapEx guidance.

An overhead view of an oil rig from an offshore drilling platform.

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 key 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 ’24. Overall, our strong operating platform position SilverBow to continue to grow through multiple avenues.

We have championed the need for validation 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 checked 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 position SilverBow to exceed a 25% annual growth target in the coming years. Second, we’re acquiring the assets at a discounted PDP valuation, while adding roughly 300 high confidence locations at essentially no cost.

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Q&A Session

This contains our decade plus inventory life, and as 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’re 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 one times 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, position 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.

SteveAdam: Thank you, Sean. In the third quarter, we drilled 10 net wells completed nine net wells and brought nine net wells online. D&C activity was focused on our eastern extension and central oil areas. The team continues to execute on our 23 development programs. 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% to 30% year-to-date, and rig rates have dropped by roughly 20%. As for year-to-date, drilling efficiencies, cost per foot are down 13% or $22 per foot compared to ’22. On the completion side, year-to-date pumping efficiencies are averaging 20% higher compared to ’22 and in the third quarter, we achieved the highest quarterly pumping efficiency so far for ’23.

These gains have been driven by reductions in equipment downtime and other non-productive events. As a result, we’re completing approximately 10% more stages per day on a same-store basis and completing 10% more lateral feet per day as compared to ’22. In aggregate, our total D&C cost in ’23 have been delivered 2% below AFE. We estimate that realized D&C savings are roughly 10% to 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 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 setup 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 ’23 production guidance to a range of 336 to 342 MMcfe per day, which implies overall production growth of 26% and oil production growth of 94% year-over-year. All forward-looking estimates exclude any contribution from specific assets. Specific to our capital budget, our previously lowered guidance of $400 million to $425 million remains unchanged.

Given the efficiencies realized today, we will be able to accelerate the completion of timing of several pads we had scheduled for early ’24 and therefore, able to absorb that D&C spend in ’23. As discussed on prior calls, we allocated 100% of our D&C 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. And 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.

Chris Abundis: 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 bases 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 edge book as of October 27, for the remainder of 2023, we have approximately 200 MMcf per day of natural gas hedged, 11,100 barrels per day of oil hedged, 3750 barrels per day of NGL hedged. Using the midpoint of our production guidance, we are 92% hedged on gas and 66% edged on oil for the remainder of this year.

For 2024, we have approximately 211 MMcf per day of natural gas edged, 11,800 barrels per day of oil edged and 5400 barrels per day of NGL edged. The edged math are inclusive of 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, the 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 lien 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 to $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 30, 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 one times. 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 upside 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. And with that, I will turn it over to Sean to wrap up our prepared remarks.

Sean Woolverton: Thanks, Chris. SilverBow continues to execute on its strategy 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. And with that, I will turn the call back to the operator for questions.

Operator: Thank you so much. [Operator Instructions] Looks like our first call questioner is Tim Rezvan from KeyBanc Capital Markets. Tim, go ahead.

Tim Rezvan: I guess first just wanted to pick up the Chesapeake acquisition. The timing is sliding a bit here. Just to ask the big question, is there any concern 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.

Sean Woolverton: Hey, good morning, Tim, and thanks for the question. In terms of your first question, we continue to work closely with Chesapeake and when we first announced the transaction felt like and disclosed to the market that we would close the transaction in the fourth quarter. So 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 working closely with Chesapeake’s team as well within our company — our teams to be ready to take control the assets. 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.

I think, as we dig in, and really start to 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 we’ll see if there’s opportunities to address something there in the future.

Tim Rezvan: Okay. Thanks. We’ll stay on that. And then, I thought was interesting, Sean, on your closing comments, you talked about M&A as a central theme for the sector. So if I could redirect that to you, is M&A still, like how high your radar screen is that as you get to the finish line with Chesapeake, and then given that you put a one times leverage target at the end of the year in 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? Sean, understand that as you balance deleveraging versus growth?

Sean Woolverton: Yes. Obviously, we’ve been very successful on doing transactions. And I think we 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 — 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.

Operator: Okay. Thank you. And our next question comes from Charles Meade with Johnson Rice. Charles, go ahead.

Charles Meade: Sean, I recognized you 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 wondered if you could talk about how these wells can come 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 rate but also the 70% oil cut, does it look that way to you?

Sean Woolverton: Yes, kind of big picture. When we announced the deal, we discussed that, the asset was going to see a ramping up production, from 2Q and into 3Q as many new wells were brought online. I think Chesapeake recently announced in their call that the asset was doing — did 32,000 BOE a day for the third quarter, and that was right in line with what we felt like it was going to do. So overall the asset is, performing up to what we had underwrote the deal for the third quarter. Now specific to the wells. We’ve been continuing to monitor the performance of the new wells brought online, would tell you that overall, the program is performing at what we expected it to, 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, those wells being all Eagle Ford wells, that’s a really good area and perform slightly above where we thought so encouraging to continue to see strong Eagle Ford wells in that part of the property.

Charles Meade: Got it. And then my second question is really about trying to get a sense of SilverBow standalone going into 1Q ’24. And I recognize you guys, you haven’t given ’24 guidance, and that’ll come. But I wonder if you can just help me kind of 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 3-well oily pad into 4Q. It looks to me, like you’re setting up for actually a big step up in organic growth in 1Q ’24. So I guess maybe the context, Steve, you mentioned that you brought nine wells online, you said nine wells to sales in Q3, can you tell us what you think that number will be for Q4? Does it also look to you like you’re going to have a big step up organically for 1Q ’24?

Steve Adam: Yes. Thank you, Charles, for the question. Yes, we’re looking for Q4. We’re looking for one of the 4-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 and other 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 kind of 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, like we were guiding to you before, we’re looking at it better than 15,000 per day. And in about probably better than 16, 5 or so roughly in that range for the fourth quarter.

Sean Woolverton: Yes. Charles, so the way it’s lining up, right is we expect we’ll see the strong oil growth, like we mentioned in the call about 10% growth, 3Q to 4Q on oil. And anticipate with the acceleration of that 3-well oil pad that will have strong exit rates. Then the gas starts to kick in, and so we’ll have continued growth on an equivalence 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 yes, I think on the base assets, continued strong organic growth, really driving the growth on oil through end of year and then starting to see the ramp of gas into the first quarter.

Operator: And our next caller is going to be Donovan Schafer from Northland Capital Markets. Donovan, please go ahead.

Donovan Schafer: Hey, guys, congratulations on the quarter. And thanks for taking the questions. I want to start, kind of dovetailing with the prior questions. Of course, you don’t have 2024 guidance and that’s not something we’re really here to talk about in any sort of formal or official way today. But what I want to — the way I try to think about things or frame things is, when you announced the Chesapeake transaction, in middle of August, based on the slide deck, you shared at the time, it looks like you must have gone through a pretty thorough, internal set of projections around everything given you showed your path to getting down to 1x leverage ratio in ’24. You kind of put out some numbers and the relative percent increase that you’d get in ’24, free cash flow per share, and some other things like that.

So my question is, between — 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 ’24, has that directional, is it fair to say that that’s directionally improved 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 — 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 reran that exercise for the whole company in comparing before and after the acquisition?

Sean Woolverton: Yes, I would tell you that the base assets for SilverBow are performing well came in slightly ahead for third quarter, kind of in line for 4Q guide in full year. So the base assets are 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 the over the next 12 months, we see EBITDA in that 825 million to 925 million range, and production in the mid 93,000 to 95,000 Mboe a day. Those numbers we still think are at — kind of where we’re at. And think that we’ll be able to deliver those once we take control of the asset and get into next year.

Donovan Schafer: Okay. And then, as a follow up, just since you’re not including the Chesapeake acquisition, and the PDP production that would come with that in the Q4 guidance. And then, but you also do still expect it to close in the fourth quarter. Is it, 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 to come in above guidance. And maybe, the extent to which it’s above guidance, it’d be more so above or only slightly above kind of depending on whether it closes sooner or later. And I’m asking partly just because, 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. Just want to make sure I’m thinking about all those correctly.

Sean Woolverton: No, no. Great question and your spot on with the observation. I think as we’ve given a guide of sometime in the fourth quarter, analysts have done the best with the information we provided the model when that might occur. And probably several of them probably projecting mid quarter call, or 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 yes, just to be clear, right now we’re out in market with just SilverBow standalone numbers, where many of the analysts covering the company have a combination of SilverBow standalone plus a partial quarter Chesapeake contribution.

But yes, and like said, once we do close, we’ll plan to give an updated guide for the adjustment for the Chesapeake assets coming into the SilverBow numbers.

Operator: And our next question comes from Noel Parks with Tuohy Brothers. Noel, go ahead.

Noel Parks: One thing that you talked a little bit about in the prepared remarks and I also saw in the release. You’re 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 the Eagle Ford done in the oily areas now?

Sean Woolverton: Yes. Our team, over the last several years has really dug in on the Austin Chalk started in Webb County and we’ve shared a lot of that information and 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 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 outlined in that central oil area, a number of pads where we drilled the chalk wells on. So we brought on, I think three chalk wells in that area thus far, in all our 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, they’re stack pay opportunity within the basin. We have a large footprint post the Chesapeake close of nearly a quarter million acres. And what’s great about it is, we’ll continue to scour not just the Eagle Ford, but also other zones across that acreage block.

Noel Parks: Great, thanks. And well, with Eagle Ford, of course, like with a development process, you’re always learning and gathering data. There’s Austin Chalk has had so many different lives across so many different, different basins over the years. So is there anything in particular, incrementally that you’re experiencing in Webb County has sort of brought to the table that clarify that you did have some decent potential in parts of central oil and Eastern extension. And could you ever give a shout out sort of what that might mean, in terms of how many locations you might have incrementally or just a portion of the overall acreage where the chalk might work? I guess, if you can talk about what characteristics make it look better in some places than others particularly?

Sean Woolverton: Yes. Really the fundamental change right from historical chalk development, both up in Giddings and through the Karnes, Austin chalk trend that saw quite a bit of activity through ’17, ’18, ’19 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 understand that better, and where we took that mindset and thought elsewhere, obviously, we identified in conjunction with SM play in northern Webb, the potential that it had. And that’s why we were patient and pursued the Chesapeake transaction because we’re really excited about the chalk there. But then, took that same model elsewhere. And it’s starting to replicate itself.

The chalk doesn’t have good porosity and doesn’t have 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 fractured play and more of a porosity, thickness driven play. So a little bit of conventional reservoir development using horizontal drilling and fracturing to unlock the resource. In terms of quantifying the inventory, obviously, Webb County is where we have a lot of it. We have a couple of 100 — probably 2500 — probably 125 gas chalk locations up 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 kind of quantifying that.

So haven’t added that to our materials yet. Our footprint, they’re smaller than our Webb County, so it’s not going to be to those extent but we’re going to — it’s going to be additive to our inventory for sure.

Operator: And our next caller comes from Jeff Robertson with Water Tower Research. [Operator Instructions] And Jeff, with that, go ahead.

Jeff Robertson: 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?

Sean Woolverton: Yes. The Eagle Ford, Chesapeake had developed that asset base going back as far as, what, ’08, ’09 timeframe. So overall, that asset basis has a lower decline rate than SilverBow standalone. So we’re expecting that it’ll flatten our decline — the base decline on our combined asset here moving forward. So brought it down probably a couple of percent, high-20s, low-30s on a standalone basis down, the Chesapeake assets were probably in the mid-20s a little bit higher than that. So dropping it combined probably 1% or 2%.

Jeff Robertson: And then, 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?

Sean Woolverton: No, actually it’s a benefit, especially in our Webb County area, both on the SilverBow existing assets and then on the Chesapeake assets, as 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.

Operator: We have another question from Noel Parks with Tuohy Brothers. Noel, go ahead.

Noel Parks: Just want to get your thoughts on one other topic. So the gassy E&Ps, a number of them were the earliest ones to report. 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, Appalachia looms large, the Haynesville looms large. I’m just wondering about maybe what we should be looking for in either new capital coming in for development or maybe even new purchasing or consolidation in the area.

Sean Woolverton: Yes. I think, as you look at the amount of LNG buildout slated over the next several years, you start to look at the imbalance of the demand of that LNG buildout versus the supply and where is it going to come from, and the acknowledgement 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 buildout. So, yes, we’re seeing that the Eagle Ford and just the strong performance of Webb County over the last few years, us plus others see that as probably one of the first places to look at to help fill that forthcoming LNG demand. So, yes, I think it’s existing players plus new entrants that are looking to find gas to fill some of the LNG expansion that they’re contracting into.

So sets us up well. We’re long-term players in the area, understand the reservoir well, have a lot of great existing relationships and infrastructure there. So we’re excited about the opportunity this exposes us to much stronger gas prices in the coming years.

Operator: Okay. Thank you all for your questions. And with that, I will turn the call back over to CEO, Sean Woolverton, for closing remarks.

Sean Woolverton: Hey, appreciate that, Greg. Well, we’ll wrap up. I’ll say, 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.

Operator: Thanks, Sean. And, ladies and gentlemen, that does conclude today’s call. As he mentioned, thank you all for joining and you may now disconnect.