SilverBow Resources, Inc. (NYSE:SBOW) Q2 2023 Earnings Call Transcript

SilverBow Resources, Inc. (NYSE:SBOW) Q2 2023 Earnings Call Transcript August 3, 2023

Operator: Good morning. My name is David, and I’ll be your conference operator today. At this time, I’d like to welcome everyone to the SilverBow Resources Second Quarter 2023 Earnings Conference Call. Today’s conference is being recorded. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there’ll be a question-and-answer session. [Operator Instructions] Thank you. Jeff Magids, Vice President of Finance and Investor Relations. You may begin your conference.

Jeff Magids: Thank you, David and good morning everyone. Thank you very much for joining us for our second 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 the 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. SilverBow’s second quarter results demonstrated the impact of our oil focused development program and the team’s ability to meet and exceed our objectives. Our differentiated strategy is delivering growth while living within cash flow this year and we are well-positioned to generate significant free cash flow over the next 18 months. I’m pleased to report that during the quarter, we published our Inaugural Sustainability Report. With this report, we now have the standardized framework in place for investors and other key stakeholders to fully appreciate our ESG stewardship. Turning to results. Second quarter production came in at the high end of guidance and increased 40% year-over-year.

Our production growth was driven by strong performance from our oil assets, as our oil production exceeded the high end of guidance and has nearly tripled year-over-year. As Chris will further detail, the rapid shift of our production mix resulted in 75% of revenue derived from liquids, compared to less than 33% a year ago. On the cost front, our operating expenses came in below guidance across the board. For the full year, we are lowering our CapEx guidance by approximately 10% to a range of $400 million to $425 million. Our efficiency gains and cost savings year-to-date along with several optimizations to the D&C schedule by Steve’s team are allowing us to reduce our capital spend, while still delivering our full year production guidance.

We also introduced full year 2023 free cash flow guidance of $10 million to $30 million. Higher liquids production, lower CapEx spend and a ramp in our gas volumes at year end is expected to drive positive free cash flow on a full year basis. The ability to self-fund our differentiated growth profile is a core tenant (ph) of our strategy. While 2023 represents a significant increase in oil production, we remain focused on a balanced commodity approach. During the quarter, we made several strategic advancements in our long term gas development plans. In Webb County, we leased additional acreage near our Dorado dry gas position, where we have seen some of the best returns in our portfolio. Importantly, we also entered into pipeline gathering agreements on new infrastructure coming online by year-end, which will support our multi-year development plans in this area.

We are planning to allocate capital to our gas assets over the second half of the year where we plan to complete a DUC 4-well Austin Chalk pad and move in a drilling rig in the fourth quarter. These actions will ramp up our gas volumes at year end and into 2024 alongside higher anticipated natural gas prices. Turning to our portfolio. We currently have 10 plus years of inventory identified consisting of approximately 650 locations. With roughly two-third liquids (ph) locations and one-third gas locations. We have flexibility to adjust development to prevailing commodity prices. A key objective of the company is to continue to expand our inventory through unlocking incremental opportunities on our existing assets, leasing of additional acreage and making accretive acquisitions.

To wrap up my prepared remarks, our near-term focus is on oil development. Our exit rate liquids production at year end combined with plans to ramp gas production next year positions SilverBow to generate significant free cash flow in 2024. This free cash flow will be used to drive our leverage ratio towards our stated target of less than one times. Our team has an established track record of delivering on our key objectives through commodity cycles. With that said, I’ll turn the call over to Steve.

Steve Adam: Thank you, Sean. In the second quarter, we drilled 13 net wells, completed 15 net wells, and brought 15 net wells online. Our D&C activity during the quarter was focused on our Central Oil, Western Condensate and Eastern Extension areas. Our team is executing on our oil focused strategy this year with results outperforming expectations. Year-to-date, our operational efficiencies continue to increase. On the drilling side, our rig cycle times are 10% better than ‘22 with footage drilled per day 14% higher. On the completion side, we have increased our pumping efficiencies by 18% compared to last year, driving a 17% increase in stages completed per day, on a same-store basis and a 7% increase in proppant pump per day.

The efficiency gains in cost reductions have resulted in D&C costs per lateral foot averaging 11% lower this year compared to ‘22 and our total D&C costs this year were delivered below planned AFE targets. We are also seeing ongoing cost deflation in the market including casing, frac services, and drilling rigs among others. We estimate that realized D&C savings are roughly 5% to 10% to date with leading edge market rates continuing to indicate further reductions through year end. Specific to oil, strong well performance drove second quarter production above our guidance range. The performance to-date supports consistent and repeatable development results. Additionally, we are encouraged by the early ongoing tests of Austin Chalk and co-development with the Eagle Ford on our oil assets.

In our Webb County gas area, the availability of interruptible volumes to sell into existing pipelines remains unpredictable. We continue to conservatively plan for volumes to average at firm rates for the remainder of 2023. That said, we see Webb County gas as a cornerstone to our future development. We continue to expand our inventory in this area leasing 2,200 net acres during the quarter, and we have now assembled nearly a 20,000 net acre position with 175 identified drilling locations in one of the most profitable gas plays in the country. As we remain bullish on long term gas prices, and to ensure efficient development of this inventory, we have also secured multi-year takeaway agreements on incremental pipe that will be coming online towards year end.

Turning to results and outlook. Our second quarter production of 330 MMcfe per day was at the high end of guidance with oil production exceeding our guidance range. For the third quarter, we are guiding to production of 341 MMcfe per day at the midpoint, a 3% increase quarter-over-quarter. 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. In regards to our capital budget, we plan to continue to allocate 100% of our drilling capital and both of our rigs to oil projects through Q3. And then as previously mentioned, our plan is to have one drilling, one rig drilling oil and the other drilling gas starting in Q4. Of course, we will remain flexible on our capital allocation as we optimize our drilling schedule in completion dates accordingly.

With that, I’ll turn it over to Chris.

Chris Abundis: Thanks, Steve. In my comments this morning, I will highlight our second quarter financial results, as well as our price realizations, hedging program, operating costs and capital structure. Second quarter oil and gas sales were $126 million, excluding derivatives with natural gas representing 64% of production and 27% of sales. Of note, oil represented 63% of second quarter sales compared to 24% a year ago. During the quarter, our realized oil price was 96% of NYMEX WTI. Our realized gas price was 84% of NYMEX Henry Hub, and our realized NGL price was 25% of NYMEX WTI. As shown on Slide 22 of the Corporate Presentation, we have historically realized prices closer to NYMEX benchmarks. 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.

This was a result of loosening of regional supply and demand. More recently, we are observing differentials that are closer to historical averages, as the regional market has reverted to a more balanced market. 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 155 and 140 MMcf per day, respectively, to mitigate further risk. Our realized hedging gain on contracts for the quarter was approximately $30 million. Based on our hedge book as of July 31, for the remainder of 2023, we have approximately 180 MMcf per day of natural gas hedged, 8,900 barrels of oil hedged and 3,750 barrels per day of NGL hedged. Using the midpoint of our production guidance, we are 93% hedged on gas and 53% hedged on oil for the remainder of this year.

For 2024, we have approximately 135 MMcf per day of natural gas hedged, 8,400 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 10-Q filing, which we expect to file later today. Turning to cost. Leased operating expenses were $0.67 per Mcfe. Transportation and processing costs were $0.39 per Mcfe. Production taxes were 7% of oil and gas sales. Cash G&A, which excludes stock-based compensation was $3.9 million for the quarter. Our second quarter cost compared favorably to guidance across all categories. Full year 2023, we are guiding for cash G&A of $19 million at the midpoint, which implies cash G&A on an Mcfe basis to continue to trend at lower levels compared to 2022.

We consider our lean cost structure to be a differentiator allowing SilverBow to sustain profitability during periods of volatile commodity prices. Adjusted EBITDA for the second quarter was $112 million. Capital expenditures for the quarter on an accrual basis totaled approximately $117 million. Full year 2023, we have lowered our CapEx guidance range to $400 million to $425 million, an 11% decrease at the midpoint. Our guidance update captures the optimizations to scheduling that Steve mentioned as well as cost savings and efficiencies realized to date. As reconciled in our earnings materials, we recorded a free cash flow deficit for the quarter. Cash flows have been constrained due to ongoing gas curtailments in Webb County over the first half of the year.

As oil production continues to ramp in the second half of the year, and gas volumes come online at year-end, we expect to be free cash flow positive in the third and fourth quarter. For the full year, we are guiding to free cash flow of $10 million to $30 million. Turning to our balance sheet. Total debt was $726 million. As of June 30, we had $199 million of availability under our credit facility and $1 million of cash on hand, resulting in $200 million of liquidity. SilverBow in accordance with our credit facility includes contributions from closed acquisitions for the entirety of the LTM adjusted EBITDA period used for leverage ratio calculations. On an LTM basis for the period ending with the second quarter of 2023, the contributions from acquired properties totaled approximately $10 million, bringing our LTM adjusted EBITDA for covenant purposes to $467 million and our quarter end leverage ratio to 1.6 times.

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 leverage ratio of less than 1 times. At the end of the 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.

Sean Woolverton: Thanks Chris. SilverBow continues to execute on its strategy in its position for significant value creation going forward. We project continued double-digit growth over the next several years, as we get closer to 0.5 billion cubic feet equivalent per day of production. In the near term, key catalyst for our stakeholders are continued ramp in oil production and increased gas takeaway capacity at year end. 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 providing further updates on our next call. And with that, I’ll turn the call back to the operator for questions.

Q&A Session

Operator: Thank you. [Operator Instructions] We’ll take our first question from Neil Dingman with Truist Securities. Your line is now open.

Neal Dingmann: Good morning, guys. Sorry about that. So my first question is just on your oil development. It sounds like you’re really making some strong progress there with the program. And I’m just wondering, given the suggestion, I think you’ve mentioned 100% year-over-year growth. Can you speak to the number of locations you all are identifying or I believe you have left there? And then secondly, what type of efficiencies you all are continuing to see in this program.

Sean Woolverton: Yeah. Hey. Good morning, Neal and thanks for the question. Yeah. So the rigs this year have been focused on our central oil area and our Eastern Extension, both areas really that were built out of acquisitions over the last couple of years. So very proud of the team’s integration of those assets and successful pivot into those areas really since the end of last year. As of today, we continue to look to further expand our inventory there. We quantified that we have about 400 liquids locations going forward, and that includes the Central Oil Area, Eastern Extension as well as our historical Central Condensate. Of those 400, about 100 are in the Western Condensate area and the other 300 plus remain in those other two areas, so plenty of runway there.

One of the things that we are doing, we’ve drilled a couple of Austin Chalk wells in – one, in the central area, another one in the Eastern Extension. We’re kind of monitoring those early results. So that zone, we really didn’t even underwrite any value to in our acquisitions. So we’re making efforts to try to unlock incremental values from those transactions.

Neal Dingmann: Great. And then just secondly, on the Webb County pipeline gathering agreements you highlighted, just sounds quite positive. I just want to make sure I understand what are the benefits around bringing that on?

Sean Woolverton: Yeah. Really, over the last couple of years, just as Webb County gas growth really took off by end of ’22 takeaway out of Webb was capped, probably about 2.5 Bcf a day. So incremental pipe that’s coming on, we’ll expand that capacity. There’s two projects, one, that we’ve contracted with, but another project that will increase takeaway out of Webb by another 2 Bcf a day. So really increasing takeaway capacity for the area and will allow us and other drillers to start expanding our drilling programs once again. And what we really like about it, it’s kind of lining up with improved gas prices. Yeah. So for us, it was securing some firm capacity on the projects to ensure that we’re able to develop our plan over the next several years and have capacity to take that gas away from the county over more into South Texas markets.

Neal Dingmann: Yes, I like that. I’ve said it rig. Thanks, Sean.

Sean Woolverton: Yeah. Thanks, Neal.

Operator: [Operator Instructions] Next, we’ll go to Charles Meade with Johnson Rice. Your line is open.

Charles Meade: Good morning, Sean, you and whole SilverBow team there. I’d like to ask another question here to drill down a bit more on your oil results from these recent pads. And it looks like you put a lot of good information in your updated presentation, I’m looking particularly at Slide 13. And it looks like that those two — the two pads, the Koerth and the James Keith that you have in Northern Live Oak, looks like those are the ones that are really contributing most of the outperformance that I guess powered your 2Q results and are hopefully going to continue to benefit you in 3Q. Is that the right read? Are those the two pads that are really the drivers? And can you talk about what maybe you did differently or you’re seeing differently with the early production results there?

Sean Woolverton: Yeah. Appreciate the question. The type curve right is kind of a conglomeration of this area, but would tell you that there’s definitely variance across this area in reservoir quality, reservoir pressures, moving kind of out of a little bit deeper area where the Koerth and the James Keith exists as you move north, like to the Edmund Tom. So we’ve got an average type curve. You would look and say, hey, it looks like the Edmund Tom is underperforming. Actually, those wells relative to their specific type curve are exceeding expectations. So we’re really pleased across all of them. Some of the things that we’re doing differently. I think we’re really focused on in-zone drilling that the previous operator as we went through and redrilled their wells, historic wells.

It didn’t feel like they did as strong of job there and then just a very concentrated frac design that we’ve optimized in other parts of the basin over the last several years. So that’s really the driving mechanisms of the outperformance. And now with that said, on the Edmund Tom area being a lower pressure area, one of the things that we’ve done is quickly converted to artificial lift and we’re just seeing production optimization there flattening decline. So some of the outperformance for the quarter is — that we’re seeing is just flatter production out of the new wells for a longer period of time. So we’re really excited to operationally what we’ve done thus far.

Charles Meade: Got it. That’s helpful incremental detail that you have those, I guess, region or asset-specific type curves. Sean, the other thing I want to explore is the, you referenced in your prepared remarks, you and Steve both, that you guys can flex back and forth between natural gas and oil and that you’re planning to go back to having one rig — one gas-directed rig in 4Q. What I’m curious about is how — what’s the timeline between when you make that decision and when you actually are drilling a different location because of it. So kind of the elapsed time from when you decide to when you actually – when you start to alter course. And then the second piece is — not that there’s just one price that — I recognize there’s not just one price that’s going to be a threshold and that we’re binary on either side of it. But in general, can you give us a sense for what kind of natural gas price you’re looking at for when you decide to make that decision?

Sean Woolverton: Yeah. No, good question. I’ll maybe break it down, first, operationally, the flexibility we have and then address the price question. Operationally, you know and we did this late last year, early part of this year, it takes us less than 30 days to make that decision, right? So we’ll have gas pads ready to go permitted, build that gives us the flexibility to move the rig. So we’re ahead of schedule. So essentially, within a month, it usually takes a month to drill a pad, we’ll make that decision. Hey, next pad up is going to be gas. But we’ll have an oil pad ready that, hey, prices moved in the wrong direction over the next 24 months, so let’s go ahead and move to the oil. So it’s really, I would say, a month-to-month decision.

One of the things that we’ve done to really help grow into the incremental pipeline capacity that’s coming online in the fourth quarter is, we have DUCs that have been sitting as DUCs since early this year. So the first action is we’re going to take is to complete the DUCs and ramp into the incremental pipeline capacity. And then as of now and supported by gas prices, we’ll move the drilling rig starting probably early fourth quarter into the area. That decision, the point really — the economics down there, we’d like at 350 plus and next year is right below 350 has been hanging in that ballpark for the last couple of months and 25s at $4. So we like that setup and it supports the decision to move the rig. You get down below three over the first 18 months of development, like what we saw this year and we would not drill those projects.

So probably just a rough rule of thumb for us would be that $3 gas price, we’d look to stay in the oil windows.

Charles Meade: Got it. That is helpful detail. Thank you, Sean.

Sean Woolverton: Thanks, Charles. Have a good day.

Operator: Next, we’ll go to Donovan Schafer with Northland Capital Markets. Your line is open.

Donovan Schafer: Hey, guys. Thanks for taking my questions. So I like the details on the improvements in cost. There was cost, there was also — cost reductions and also efficiency improvements, and you gave the specifics of even efficiency and number of stages pumped per day and everything, and so that was great. I checked — just this morning, I checked the EIA’s monthly drilling productivity report and in the Eagle Ford, it actually showed for August, I mean it’s kind of a wonky esoteric way that they do these calculations. But they actually showed the Eagle Ford among the kind of shale basins showing the largest year-over-year declines in new well productivity per well. And you know that’s based on a well counts somewhere in the kind of 40 to 50 rigs in the basin and you guys are operating two.

So obviously, there’s plenty of room for you to deviate from that. But I’m just curious, is this kind of corroborates with what you’re seeing on the ground? Are you seeing or hearing operators also in the Eagle Ford that maybe are not getting the kinds of improvements that you guys are getting? Is that delta coming more from operational improvements or maybe a testament to differences in acreage quality? And lastly, the other potential explanation for the delta would be if you get a lot of improvements operationally, where you’re kind of talking about stimulation volume, kind of what it boils down to stimulation volume per day percent. But that doesn’t necessarily mean production volume per rig. So you could have a case where the operational efficiency is really improving, but maybe that is not as good.

Are you moving into spots where the acreage isn’t quite as good. And so that would explain the difference in these EIA numbers of production volumes per rig being on a year-over-year decline. But you guys are seeing these fantastic efficiency and operational improvements. So if you can just speak to that, that would be great.

Sean Woolverton: Yeah. I appreciate the question. What we believe you’re seeing is and we believe this is occurring in multiple basins, where the core of the core of the basins in the Eagle Ford’s example, as you look at the Karnes trough, the inventory is just diminishing in overall count as well as more infill drillings occurring. Contrast SilverBow to that, as we’ve acquired a number of properties, the properties that we’re drilling on this year, they were really from operators that were not very active over the last several years. And in fact, several of the pads that we’ve drilled were in areas that had not had drilling on them for probably three to five years. So it didn’t have as dense drilling. So we really like the acquisitions we’ve made and that we were buying area — we were acquiring inventory based upon dated type curves, but felt confident that with even just a five-year improvement in drilling and completion practices, we could significantly enhance those type curves and that’s what we’re seeing.

So I think as I think through your question, it’s — hey, we’re just in a little bit different parts of the basin and our areas that we’ve acquired weren’t as heavily and densely drilled as some of the other operators in the basin.

Donovan Schafer: Okay, and that’s helpful. And then my next question pertains hedging. So your current position being sort of 90% hedged on the natural gas volumes. That’s a great position to be in right now. It’s where natural gas prices are presently. But if we look towards the end of this year, I’m kind of trying to orient myself because as I understand it, and correct me if I’m wrong, historically, your hedging philosophy more or less, has been to kind of hedge about 50% of gas volumes and 50% of oil volumes. And then because you’re in the Eagle Ford and you have this flexibility to move rigs around, you were able to move to a much more — heavier oil focus this year. And so it ends up being a kind of incidental or historical fact that we find ourselves now at 90% hedged on natural gas.

But so going forward, as we look to 2024, as we approach through the end of this year, is idea or strategy kind of still intact where the idea is you would position your hedges and be content with the hedge portfolio kind of entering 2024, where it’s half of your anticipated gas volumes hedged, half of your oil volumes hedged for ’24 and then that can kind of unfold in whatever way it unfolds based on what you do opportunistically during the year with your rigs. Is that kind of the right way to think about it or are you actually looking at either commodities differently based on where you kind of think there might be in commodity pricing cycles.

Sean Woolverton: Yeah. Good characterization. As you look at ‘24 and based upon — if we held volumes flat year-over-year, which we don’t expect to, we expect continued growth probably in the double-digit range, so you can kind of do that math. But we’ll just go off flat volumes year-over-year. As we sit today for both oil and gas, we’re about 50% hedged. And that’s kind of laid out on Slide 24 of the corporate deck, plus or minus some percentages there, but pretty close. As we get into the fourth quarter and start firming up our budget for 2024, get more confidence around the strip. We’ll hedge into more of our wedge production as we get closer to year-end. And typically, what we’ll find as we get towards year-end, we’ll be close to 70% of total production hedged coming into the current budget year.

So our strategy is going to — has been and will continue to be that as we get towards the end of this year. And as you described it, some of it is that as you get into the fourth quarter and you get more certainty of your plan and what product prices look like, we’ll hedge into it. But we have flexibility at least for another quarter to adjust our plan and not have impacts due to the hedging strategy.

Operator: Next, we’ll go to Noel Parks with Tuohy Brothers. Your line is open.

Noel Parks: Hi. Good morning.

Sean Woolverton: Hey. Good morning, Noel.

Noel Parks: Just had a couple of things. I was thinking about the service cost environment, we certainly have seen a good bit of variability just basin to basin as far as how the vendors are behaving. And I’m just curious, at this point, are you getting a lot of inbound inquiries on services from other vendors or are your current guys pretty proactive to the point where you’re pretty confident that sticking with them, you’ll get pricing that you’re satisfied with?

Sean Woolverton: Yes, I’ll let Steve take that question.

Steve Adam: Yeah, Noel. Like we mentioned, we’ve got a firm 5% to 10% already in the bank for this year from both the CapEx side and the OpEx side. And we’re looking for further gains both in unit cost as well as our own process efficiencies between now and year-end. Again, also on both the CapEx and the OpEx side. CapEx seems to be more driven by vendors coming into us with different proposals and different offers, many of them being discount related on a regional basis. And then the OpEx side is kind of a mix of less regional and more local, but pretty much the same genre of offerings coming to us in terms of competitiveness, different changes in unit costs and different structure in terms of opportunities, in terms of how people perform and/or incentives. So all said, we’re looking for continued improvement in unit cost reductions through the balance of the year.

Noel Parks: Great. Terrific. And I wonder, could you maybe sort of refresh my memory on the status of — you touched on a bit of the infrastructure projects out west and what sort of capacity is coming online and with the weaker prices, how are things looking relative to the existing capacity?

Sean Woolverton: Yeah. Just kind of macro numbers, kind of rough overall numbers, think about Webb County dry gas takeaway in that 2.5 Bcf a day range existing infrastructure. Two projects coming online that will move gas out of Webb east to a central point. Both projects ultimately have a Bcf a day each of capacity that could ramp up over at startup and incremental compression. So take that capacity from 2.5 to 4.5. The area has really kind of stayed at that 2.5 Bcf a day range throughout the year. And that’s why we’re kind of seeing not a lot of interruptible capacity available to produce into. But drilling has dropped off because of that as well as low gas prices. So I think the combination of contango in the gas curve as well as new pipe coming on, you’re going to see activity most likely pick up.

We were the first one to really drop both of our gas rigs in December of last year and move out. The others followed suit throughout the year. We’ll probably be the first ones in with our DUCs to get it back up and going. I anticipate that as well that excess pipe and $3 plus gas will incentivize folks to start drilling down there again. Now in addition to that, there is a larger pipe that’s about 2.5 Bcf a day that’s going to take gas further — the two projects I mentioned get at about halfway to Agua Dulce. The other project gets it all the way there. And all of those, the projects are underway. We’re relying on two of the three and are contracted on two of the three. And really feel strongly just with continued communication with both companies that they’re going to be ready to go in fourth quarter.

Noel Parks: Great. Thanks a lot. That’s all for me.

Operator: Next, we’ll go to Geoff Jay with Daniel Energy Partners. Your line is open.

Geoff Jay: Hey, guys. I had a question about CapEx. It looks like fourth quarter CapEx is going to be significantly lower than 3Q. And I guess I was just kind of wondering if that’s just what we used to call Hurricane hunting and holiday season impacts or if there is like a hidden message, I guess, about further deflation or efficiency expectations in that number?

Sean Woolverton: Yeah. It’s kind of a combination of efficiencies as well as scheduling of completions as we get towards the end of the year. We’ll have the throttle dependent upon our production prices and cash flow. We’re committed to having positive cash flow for the year. So getting ahead early in the year on cycle times as well as well performance, we feel like, hey, we can optimize completions, potentially DUC on wells late in the year and still deliver on the full year guidance. So some of that CapEx drop is based upon DUCing a little bit later in the year as well as what Steve mentioned, what we think is going to be another 5% to 10% of just overall price improvements over the second half of the year.

Geoff Jay: Okay. Good. And then lastly, the Austin Chalk well that’s moving in Q4, that is one of your existing rigs, correct? Not a new third rig?

Sean Woolverton: Correct. Yeah. I’d say continuing to stay with two rigs. We’ll continue to look to test the market for best rig pricing and best-performing rigs. Right now, we’re not in any long-term contracts on the rig side. So we’ll continue to test the market as well. But – two rigs is the plan.

Geoff Jay: Great. Thank you.

Sean Woolverton: Yeah. Thanks, Geoff.

Operator: Okay. And those are all the questions that we have at this time. I’ll now turn the call back over to Sean Wolverton for any additional or closing remarks.

Sean Woolverton: Yeah. I’ll close by again thanking everyone for their interest in SilverBow. Appreciate that interest, and we look forward to speaking to you on our third quarter call.

Operator: This concludes today’s conference call. You may now disconnect.