SilverBow Resources, Inc. (NYSE:SBOW) Q1 2023 Earnings Call Transcript May 7, 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 First Quarter 2023 Earnings Conference Call. Today’s conference is being recorded. I will now turn the call over to 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 first quarter 2023 conference call. With me on the call today are Sean Woolverton, our CEO; Steve Adam, our COO; and Chris Abundis, our CFO. Yesterday afternoon, we posted a new corporate presentation to our website and 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 is off to a great start as our team continues to execute on our 2023 plan. Our development plan remains the same with both of our drilling rigs dedicated to our oil assets through the end of the year. Our full year production and capital budget guidance also remains the same from last quarter’s update. As Steve will further detail, our team continues to drive operational efficiencies and identify D&C cost savings. Costs have come down to begin the year, and we expect to see continued cost deflation as we progress throughout the year. First quarter oil production was at the high end of our guidance range and increased 140% year-over-year.

Based on our full year guidance, ‘23 oil production will increase by approximately 100% compared to ‘22. Initial performance from our wells brought online year-to-date, are producing at or above expectations and should result in sequential liquids production growth as we move through the year. The shift to more oil this year is resulting in higher revenue per unit and expansion of cash margins. As Chris will further detail, first quarter hedged revenue per Mcfe was the highest revenue per unit SilverBow has realized to date. By year end, our production mix should be comprised of 40% to 50% liquids. On the gas front, we produced near firm takeaway levels in Webb County during the quarter as expected. Pipeline capacities remain uncertain in the near term, although we expect regional takeaway to improve as new pipelines come online by year-end.

SilverBow’s cash flows are well insulated from lower gas prices this year as our gas production is over 90% hedged at a weighted average price of $3.79 assuming the floor price of our callers. Should gas prices improve, we have a Fasken DUC pad which we can complete later this year. It’s worth highlighting that the acquisitions we made in ‘21 and ‘22 added ample runway to our oil inventory and supports our opportunistic oil pivot this year. Our strategy focuses on operational flexibility and capital allocation to our highest returns on investment. As a result of our recent acquisitions, two-thirds of our 10 plus years of inventory are now oil-weighted. The ability to pivot between oil and gas development has been and will continue to be a competitive advantage for SilverBow.

To wrap up my prepared remarks, our near-term focus on oil development is one piece of a multiyear strategy, which remains the same. We have the road map and the levers to pull to grow production, EBITDA and free cash flow while simultaneously expanding our inventory and strengthening our balance sheet. With that said, we will continue to monitor commodity prices and have the flexibility to adjust our activity levels accordingly. Our team has an established track record of delivering on our key objectives through commodity price cycles. We see a robust pipeline of opportunities ahead that will continue to unlock value for our stakeholders. With that, I will hand the call over to Steve.

Steve Adam: Thank you, Sean. In the first quarter, we drilled 13 net wells, completed 11 net wells and brought 13 net wells online. The majority of D&C activity was focused on our central oil and Western condensate areas as expected with the ‘23 budget we provided in March. While our game plan this year remains largely unchanged, our team continues to increase operational efficiencies, optimize drilling schedules and identify cost reductions to drive greater returns on capital. On the drilling side, rig move times this year are averaging 30% faster compared to ‘22. This has resulted in 10% more footage drilled per day, along with a 10% reduction in overall drilling costs. On the completion side, our team achieved an all-time record in pumping efficiency on a record path – on a recent path.

– investing our previous high set in 4Q of last year. First quarter nonproductive time decreased by 30% and same-store stages completed per day increased by 25% compared to ‘22. Furthermore, we are capitalizing on early cost deflation trends in the market. Recently, we have seen cost relief on rig day rates, tubular goods, wellhead equipment and fuel. Frac services encompassing horsepower, sand and chemicals are down 18% year-to-date. We believe key service and material costs will continue to move lower throughout the year. In our central oil and Western condensate areas, well performance is in line with our expectations and supports consistent and repeatable results across our oil acreage as we move forward with full-scale development.

In our Eastern extension area, we are highly encouraged by initial results from a two-well pad co-developing the Eagle Ford and Austin Chalk, which we brought online early in the second quarter. One of our rigs will move to this area to drill continuously throughout the second half of the year. In our web County gas area, we continue to monitor regional takeaway capacity. The availability of interruptible volumes to sell into existing pipelines remains unpredictable, although we have recently seen some opportunity to sell above firm contracted volumes. However, this fluctuates daily, and we conservatively plan for volumes to average at firm rates. The Web County Austin Chalk wells we have brought online to date continue to exhibit some of the best results across our portfolio, and we are excited to return to this area as prices and pipeline capacities allow.

As discussed on our last update, we have two 4-well Austin Chalk pads in Webb County, which we deferred completion in late ‘22. We continue to see long-term upside from this core area. And early in the second quarter, we added approximately 2,000 net bolt-on acres. Turning to results and outlook, our first quarter production of 304 MMcfe per day was at the midpoint of our guidance, with oil production at the high end of the range. For the second quarter, we are guiding to production of $3.25 per day at the midpoint, which implies a 5% to 10% production increase sequentially. Full year ‘23 production guidance of $3.25 to $3.45 per day is unchanged and implies overall production growth of 25% and oil production growth of 100% year-over-year.

By year end, as Sean noted, liquids production is expected to comprise 40% to 50% of our total mix. With that, I will turn it over to Chris.

Chris Abundis: Thanks, Steve. In my comments this morning, I will highlight our first quarter financial results as well as our price realizations, hedging program, operating costs and capital structure. First quarter oil and gas sales were $140 million, excluding derivatives, with natural gas representing 66% of production and 38% of sales. During the quarter, our realized oil price was 96% of NYMEX WTI, our realized gas price was 86% of NYMEX Henry Hub and our realized NGL price was 30% of NYMEX WTI. As shown on Slide 21 of the corporate presentation, we have historically realized prices close to NYMEX benchmarks. During the quarter, our realized gas price was impacted by widening basis differentials and is lower than our historical range compared to Henry Hub.

This has been caused by the loosening of regional supply and demand. Risk management is a key aspect of our business, and we are proactive in adding basis to further supplement our hedging strategy. For 2023, we have secured gas basis hedges on 157 MMcf per day to mitigate further risk. Our realized hedging gain on contracts for the quarter was approximately $20 million. Notably, our first quarter hedge revenue per Mcfe of $5.84 was the highest revenue per unit SilverBow has realized to date. This is impressive considering the declines in the first quarter, Henry Hub benchmark pricing compared to last year. The higher revenue per unit reflects the mix shift impact of higher oil production as well as the strength of our current hedge position.

Based on our hedge book as of April 28 for the remainder of 2023, we have 180 MMcf per day of natural gas hedge, 7,400 barrels per day of oil hedged and 3,750 barrels per day of NGLs hedged. Using the midpoints of our production guidance, we are 91% hedged on gas and 48% hedged on oil for the remainder of this year. For 2024, we have approximately 120 MMcf per day of natural gas hedged 3,300 barrels per day of oil hedged and 1,400 barrels per day of NGL hedged. The hedged amounts are inclusive of both swaps and collars. A detailed summary of our derivative contracts contained in our presentation and 10-Q filing for the first quarter, which we expect to file later today. Turning to costs. Lease operating expenses were $0.78 per Mcfe. Transportation and processing costs were $0.42 per Mcfe.

Production taxes were 7% of oil and gas sales. Cash G&A, which excludes stock-based compensation, was $6.5 million for the quarter, which includes onetime professional fees. For full year 2023, we are guiding for cash G&A of $19.5 million at the midpoint, which implies cash G&A on an Mcfe basis to be slightly down year-over-year, inclusive of one-time fees. We consider our lean cost structure to be a differentiator, allowing SilverBow to sustain profitability during periods of volatile commodity prices. Adjusted EBITDA for the quarter was $111 million. Capital expenditures for the quarter on an accrual basis totaled approximately $108 million. Full year 2023, our CapEx guidance is unchanged at $450 million to $475 million. Included in our guidance range is the completion of a 4-well Austin Chalk gas pad in the fourth quarter and opportunistic land spend.

As reconciled in our earnings materials, we recorded a free cash flow deficit for the quarter. Cash flows in the first quarter were constrained due to deferring the completion of Web County gas wells drilled in the fourth quarter of last year and ongoing gas curtailments in web count. The timing of D&C projects and land spend creates variability in our quarterly free cash flow results. Based on our latest guidance and outlook, we expect free cash flow to run at a slight deficit in the second quarter. However, with strong growth in the second half, we are projecting positive free cash flow for the full year. Turning to our balance sheet. Total debt was $709 million. As of March 31, we had $216 million of availability under our credit facility and $2 million of cash on hand, resulting in $218 million of liquidity.

Silver Bow in accordance with our credit facility includes contributions from closed acquisitions for the entirety of the LTM adjusted EBITDA period used for leverage ratio calculation. On an LTM basis, for the period ending with the first quarter of 2023, the contributions from acquired properties totaled approximately $63 million. Bringing our LTM adjusted EBITDA for covenant purposes to $493 million and our quarter-end leverage ratio to 1.4x. Consistent with our strategy for the last several years, excess cash flows that are 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 1x. At the end of the first quarter, we were in full compliance with our financial covenants and had sufficient heavies.

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 growth strategy and is positioned for significant value creation going forward. We project continued double-digit growth over the next several years as we march towards 0.5 billion cubic feet equivalent per day of production. In the near term, a key catalyst for our stakeholders is our ramp in oil production. Our relentless focus on our employees’ well-being and safety is paramount to our culture as is our engagement with the community and our environment. We look forward to sharing more of our insights towards safety and clean operations with the release of our inaugural sustainability report in the near future. I want to thank all of our stakeholders for their continued support. We look forward to providing further updates on our next call. And with that, I will turn the call back to the operator for questions.

Q&A Session

Operator: Thank you. We will take our first question from Donovan Schafer with Northland Capital Markets. Your line is open. Mr. Schafer, go ahead. Your line is open.

Donovan Schafer: Sorry about that. I was on – I muted myself. So I want to start off with interruptible capacity. I was just curious if you can give us a sense for magnitude around what are – what you may or may not be able to ship for interruptible capacity. I mean I know that’s like super hypothetical, and I think correct me if I’m wrong, but your guidance kind of assumes no not having any interruptible capacity on the gas side. But so I’m kind of just thinking in terms of like error bars here, of course, you guys don’t have a crystal ball. But just sort of in theory, is this the type of thing where when interruptible capacity is available, that can add like another 5% to 10% of volume, but then maybe that’s like 1 day a week, so then it ends up being de minimis, just kind of trying to get my mind around how to just think about it more conceptually?

Sean Woolverton: Yes. No, I appreciate the question. And your question around how much availability is there and how sustainable it is, is kind of spot on. When we do see available capacity, it’s probably 5% to 10% above what we can produce. So, that’s not a bad number. But at this point, it’s very inconsistent sometimes only for a day or two. So, we still are guiding towards our firm capacity for the full year and think that it’s prudent that we do that guidance.

Donovan Schafer: Okay. And then I also want to ask the efficiency gain, it sounds like D&C costs, you’ve got the deflation aspects but also pretty significant efficiency improvements. And so I’m wondering, does this – is it unfolding in a way the sort of efficiency improvements and the uptime you talked about with the frac spreads. Is that – like is that kind of a proof point or like an unfolding in a way that’s in line with or consistent with I think kind of the initial part of the strategy and the idea around being just one of a couple of consolidators like in the Eagle Ford before I think the idea what you guys talked about before was if you are one of just a couple of consolidators, it gives you the scale to – you can get some better pricing, but then possibly even more importantly, you can get higher quality crews.

I know having a crew that sticks together that executes well and you don’t have someone not showing up to work one day or whatever. It’s really important. So have you been able to kind of get crews that you feel like are kind of high quality and then retain them? Is it like, I guess, unfolding in a pattern in the nature that you were kind of thinking back to the original consolidation strategy?

Sean Woolverton: Yes. We are firm believers that with scale, there is a lot of optionality that comes with it from increased purchase power, but also it brings consistent operations over a long period of time as we are able to level load our services. And we are seeing that play out. We continually work with our service providers to build stronger partnerships. We pride ourselves on being prudent schedulers. And I think we get that feedback from the service providers that we put more consistency into their schedule. And as a result, we are seeing improved performance from their side of the business. So, I do think it’s not easy to be a consolidator. It takes an operator that has a proven track record. And I think our company has demonstrated that and that we continue to invest our record performance quarter-in and quarter-out. And I think it speaks to just having a larger footprint and more level-loaded operations.

Donovan Schafer: Okay. That’s helpful. And then, I guess my last question and I will take any others offline or – and maybe I will jump back in the queue. But the last question I have got for the moment is with the new pipelines you talked about coming online kind of towards the end of the year, kind of similar type of question to what I was asking with the interruptible capacity. Can you just give us a higher level of kind of framework or conceptual way to think about like these new pipelines like the magnitude of the volume they could move relative to what is the takeaway capacity existing? Is this a 20% increase, 30% increase of what capacity to take away from the region where you are producing and then if possible, what does that translate into for basis or net pricing improvement.

Again, I know you don’t have a crystal ball like – of course, benchmark prices and everything. So, maybe it’s something best to talk about in kind of relative terms. But if something along the order of, well, if this is going to increase capacity, take like 30% and that would tend to translate into like a 10%-ish or 20%-ish or even more like it’s more levered to the capacity. Again, just kind of trying to get the framework to think about what those could mean?

Sean Woolverton: Yes. Definitely, the Webb County dry gas play has really boomed over the last 18 months to 24 months as several large operators have come in and started to develop the high-quality Eagle Ford and Austin Chalk zones. Takeaway capacity out of that area currently sits around 2.5 Bcf a day with the planned expansions that are scheduled to come online by the end of the year, that probably takes it up, not quite double it, but takes it to about 4.5 Bcf a day of potential expansion. So, definitely provides for more volumes to come out of the area in the years to come. Now, speaking to what’s that mean from a basis differential standpoint, our view is we are still very bullish on gas, especially as you get into ‘25, ‘26 timeframe with a lot of new demand coming online in the Gulf, primarily on the LNG export front.

And so I think you look at macro forecast across the big gas basins. And there is going to be a shortage in our belief of gas volumes once we get to that period of time. And so this expansion in Webb County, we think is going to be critical to help meet some of the demand needs and expect that not only will absolute gas price increase going forward and the strip reflects that, but we think basis will tighten back up to more historical levels, and we will see close to NYMEX pricing as we move forward into the late ‘24/25 timeframe.

Chris Abundis: Okay. So, thinking the benchmark goes up and then you are not going to suffer any penalty or getting boxed out from benefiting from that. So, benchmark goes up and you get kind of a clear translation into that.

Donovan Schafer: Okay. That makes sense. Alright. Thank you, guys.

Sean Woolverton: Appreciate it, Donovan. Thank you.

Operator: Next, we will go to Charles Meade with Johnson Rice. Please go ahead.

Charles Meade: Good morning, Sean to you and the whole SilverBow team there.

Sean Woolverton: Thank you. Good morning, Charles.

Charles Meade: I wanted to ask a question about your Eastern extension. And I think Steve touched on this in a few of the prepared comments, but I wonder if you can recap for me and for others listening what you have done so far in 2023 over there because I think Steve said that you brought in on one Eagle Ford and one Austin Chalk. And also, I think there is plans to – you have moved a rig there or maybe you are about to move a rig there and do more of this Eagle Ford in Austin Jock. So, can you just give a recap of what you have done so far, what you – what the plans are for the remainder of ‘23? And to the extent that it sounds like you do have some well results, how those are coming in versus your risk to plan?

Sean Woolverton: Yes. You bet. Just to recap, this block is a result of two acquisitions that we did one in ‘21 and one in ‘22, where we can put together just under a 20,000-acre block and consolidated the working interest within the block and wanted to get that all in place before we went in and started drilling. So, early in ‘23, we drilled our first two-well pad, one Eagle Ford, one Austin Chalk like you mentioned. The wells just came online, they are still ramping. We haven’t quite reached IP or just starting to get there. So, we wanted to not get out in front of results on the quarter announcement. But to Steve’s comment in the script, we are pretty excited with what we are seeing. I can tell you that the results are coming in line or exceeding to-date. And our comment that we are going to move a rig in there and parking for the second half of the year should give an indication of what we are thinking about the results thus far as well.

Charles Meade: Got it. And so rig was there till the two-well pad. It sounds like it moved off, but you are going to park on there for the second half. That’s the outlook.

Sean Woolverton: That is.

Charles Meade: Got it. Thank you, Sean. And then second, a follow-up on the whole A&D landscape. We have seen some – from my perspective, it looks like the A&D and the Eagle Ford have slowed down, and then we got a couple of – got an unusual move with a Canadian company coming in and making a corporate deal. And then this morning, we have a company that’s been a longtime player in the Eagle Ford, selling this position and concentrated in the permits. So, I wonder if you could give us your thoughts about what the potential and what the landscape looks like today. And particularly, are there chances for you to perhaps de-lever through some acquisitions in the Eagle Ford?

Sean Woolverton: Yes. The Eagle Ford definitely has been an area of significant activity really over the last nine months now. And like you mentioned, just over the last couple of days, there has been a couple of transactions announced as well, one public selling to a private and one private selling to a public. So, continues to be a range of activity and a range of size and scale with many of the packages being announced between prices of $0.5 billion up to $2.5 billion. So, a lot of interest in the Eagle Ford for the reasons we have laid out in the past. Begs the question, how much activity remains in the Eagle Ford and can SilverBow participate in that. Yes, we still think there is a lot of further consolidation to occur.

We think that there is two reasons to do that and the Eagle Ford sets up well for it. First is the – in the gas window of the Eagle Ford, the economics are very strong and look extremely attractive moving into a Contango price curve. So, we think there is an avenue there. And then we think that it’s becoming more – coming more into view that poor inventory starting to dry up in a lot of basins. And we think that there is runway in the Eagle Ford and folks recognize that. So, we think there is consolidation that can occur, especially in the Western Eagle Ford around right now, acquisitions being done near PDP value, but exposes buyers to a lot of inventory that should look attractive in the years ahead. So, yes, we think Eagle Ford will remain active, and our plan is to be active in it.

And we think that through that growth, there is opportunities, like you mentioned, to de-lever based upon how we structure the deals.

Charles Meade: That’s helpful detail on your thinking. Thanks Sean.

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

Operator: And next we will go to Neal Dingmann with Truist Securities. Your line is open.

Neal Dingmann: Good morning all. Thanks for the time. Sean, my first question is just wondering a little bit more on how you are thinking about capital discipline. Specifically, you have mentioned potentially in the release about slowing gas-focused activity later in the year. But I am wondering if oil continues to go lower, creep lower like it’s doing and gas remains weak, would you all consider going more to a single rig plan in order to – we would forecast would be a nice boost in free cash flow?

Sean Woolverton: Yes. No. One of our guidepost is to spend within cash flow. And so we are going to continue to adhere to that. And there has been just a lot of volatility on both commodities, but just over the last really, 30 days on oil, it’s done a $20 cycle in that short period of time. So, we will continue to monitor both commodity prices and adjust our capital really driven by returns on investment and staying within cash flow. What’s good is we have a lot of flexibility in our operations, so no really contractual obligations on the service side and any meaningful MBCs or land commitments that can’t be handled with one rig or even less than one rig. So yes, we are really plan to stick with the strategy of growing, but doing it within cash flow.

And if commodity prices aren’t there to accommodate that strategy, we will dial back and between our hedge book and the growth that we have already generated year-to-date to your point, to have a lot of free cash flow in the near-term if we dial back capital.

Neal Dingmann: Yes. Really like that optionality. And then my second question is, how big a benefit do you believe, I mean maybe even for the remainder of this year or next year, how big a benefit do you believe your operating efficiencies that you continue to see and potential softening OFS costs could have on the plan?

Sean Woolverton: Yes. We have started to see this earlier in the first quarter. It’s continued to play out both on operational efficiencies and some deflationary pressure. I didn’t feel like we wanted to lower the capital guidance at this point in time. I wanted to see how it plays out for another quarter. But yes, we think the way things are setting up, there is probably a 10% – plus or minus 10% realization that we are seeing year-to-date, and we think that could potentially double in the second half of the year.

Neal Dingmann: Well, great to hear. Thank you.

Sean Woolverton: Yes. Thank you, Neal. Have a good day.

Operator: Next we will go to Tim Rezvan with KeyBanc. Your line is open.

Tim Rezvan: Good morning folks. Thanks for letting me ask a couple of questions. Charles, sort of stole my topic on the Eastern extension, but I thought I would maybe pick at it a little more. So, obviously, you seem excited, you don’t have numbers to share. Was the decision to move that rig for the second half of the year made before this pad was drilled, or is it something that you are more confident in what’s early production came back at you?

Sean Woolverton: Yes. We had had – our plan had us moving the rig there, but wanted to just de-risk it a little bit, both on the capital side, the performance side as well as the reservoir performance side since we hadn’t drilled in that area before, but had a good feel for what both CapEx and well performance would be going in through the acquisitions. But just wanted to make sure we felt comfortable and felt it was prudent to get two wells under our belt versus getting in there and drilling a half dozen before we saw some results. So, really, it’s – the two wells to-date are confirmation of our expectations and it’s really are sticking with our plan.

Tim Rezvan: Okay. So, I guess we will in the next quarter get some numbers around that. I know it’s early, but can you talk about the oil cuts there relative to kind of the Western liquids area?

Sean Woolverton: Yes. So, our position really spans the windows with some of it within the volatile window, some of it within the condensate. Our two wells drilled to-date, oil is probably in that 70% range, so more oil-rich than the Western condensate area. Our plan in the second half of the year is actually to drill in both windows. The condensate windows more in that probably 40% oil, 30% liquids, 30% gas ballpark, so kind of a mix there. So, we will probably – if I was the ballpark at the second half of the year is the half drilling in the volatile oil window of the Eastern extension and half in the condensate window.

Tim Rezvan: Okay. We will look forward to results there. And then somewhat related to that, I am just trying to reconcile a little bit of housekeeping on the modeling front. The press release talks about oil, I think it was 40% to 50% of production by the fourth quarter. Slide deck said liquids of 40% to 50% in the second half of the year. Oil was 22% of production in the first quarter. Should we just think about that as sort of a steady ramp to kind of a mid-40s level by the fourth quarter? Just trying to sort of model the transformation…

Sean Woolverton: Good question and probably we need to look at it and make sure we are consistent on the nomenclature. The 40% to 50% is a reflection of total oil for – excuse me, total liquids percentage, not oil percentage. So, think of it, yes, 40% to 50% liquids. Of the liquids, two-thirds is oil, one-third is NGLs. And we will look to make sure we clarify that if we have a mix of nomenclature scattered across press release, corporate presentation. Yes. Thank you.

Tim Rezvan: So, just – okay, just to clarify then, should we think about oil being mid-30%s of production in the fourth quarter, or kind of just trying to get our arms around, is that what you are sort of saying?

Sean Woolverton: Yes. Trying to do the math in my head, but yes, I think we will be into the 30%, probably low-30s.

Tim Rezvan: Okay. I will meet Jeff offline just to make sure we are thinking about it correctly. But appreciate the comments. Thanks.

Sean Woolverton: Yes. Thanks Tim. Have a good day.

Operator: Okay. Alright. Next we will go to Noel Parks with Tuohy Brothers. Your line is open.

Noel Parks: Hi. Good morning.

Sean Woolverton: Good morning Noel.

Noel Parks: Just a couple of things, wondering about the co-development of the Eagle Ford and Austin Chalk, are there any particular technical challenges on the completion side or the drilling side or is it more a matter at this point in terms of selection sort of pre-drill analysis?

Sean Woolverton: No, there is some operational differences between the two zones. But in terms of planning for and taking in advance of the co-development, taking that all into account, we are fully aware of it. And probably – and Steve could chime in on this. The biggest difference is in certain parts of the play. We can drill Austin Chalk with two string, but need to set an intermediate string going into the Eagle Ford. So, that’s probably the biggest technical difference. We see that the Austin Chalk drills is a little bit harder rock, so drill is a little slower, but again, not anything different. And from a frac completion side, our recipe is kind of the same, and we see similar type treating pressures. So, no like on-the-fly adjustments needed as we simul-frac between Eagle Ford and Austin Chalk. We are not having to like adjust proper chemical makeups or anything like that. Steve, I don’t know if I missed anything that you might want to add.

Steve Adam: I think you covered it excellently. And then we have just in a little more fine-tuning on mud weights for both of them from both wellbore stability as well as well control.

Noel Parks: Okay, great. On those, okay. And I was wondering, as we continue a few more months on this sort of tough middle-term nat-gas environment. Thanks for the reminder that you do have the pad that you could move up and complete if prices rebounded. I was thinking about other opportunities if we do see sort of a return to volatility that takes us up. In your gas area out West, are you at the point that there is a significant potential recompletion activity out there, just thinking about things that could be maybe mobilized relatively quickly and have a good return in the event gas those pop up near-term?

Sean Woolverton: Yes. Much of our Webb County development is over the last 5 years, 6 years. So, much of the completion was at optimized levels as far as we are concerned. So, we don’t see that area as like a high work-over, high recompletion area. We have been spending more dollars doing that on the oil front as we have gotten some of these assets that were kind of under-loved over the last couple of years. So, we have been having some success from that front. But yes, on the gas front, it’s really – we have got two four-well pads that we could complete if prices justified it, and there was availability in the pipeline anytime through the year. But the other thing is that we are just so efficient. Over a two-day period, we can move a rig back in there.

Drill a three-well pad in a month’s timeframe and have it fracked another 30 days out. So, we can ramp drilling activity up in 60 days there from moving the rig into getting first production. So, that’s probably our best leverage is just the flexibility of the rig.

Noel Parks: Okay, great. Thanks a lot.

Sean Woolverton: Yes. Appreciate it Noel. Have a good day.

Operator: Next we will go to Geoff Jay with Daniel Energy Partners. Your line is now open.

Geoff Jay: Thank you. Hey. I just wanted to circle back to the drilling and frac savings. You talked about the 10% and 18%. And I was curious if that’s sort of absolute pricing, if there is efficiencies kind of baked into that? And if you can help us kind of disaggregate the pricing and the efficiency components of that.

Sean Woolverton: Yes. It’s definitely a combination. I would tell you that we are seeing, for the most part, prices come down across the majority of services and materials, some at different levels, but seeing it both service cost and material costs and on the drilling completion and even on the operating expense side on our production side seeing chemical costs come down, trucking costs come down, as you might expect, with lower fuel prices relative to last year. Breaking it out, don’t have those numbers in front of us, but definitely a combination of deflation and efficiency. And Steve, I don’t know if you have any thoughts or comments that you could add to that.

Steve Adam: Yes. A lot of the process efficiencies we have incurred already experienced from essentially November to where we are right now and looking perhaps for a few more, but yet for that to taper down. Most of it, at this point forward now, we are seeing in unit cost currently in the cost. So, if you kind of weigh that out over the course of the year, they are kind of split equally as we look for about an overall 17% to 20% reduction in both drilling and completion through the end of the year.

Geoff Jay: Awesome. That’s really great detail. Thanks a lot.

Sean Woolverton: Yes. You bet Geoff. Thanks.

Operator: Okay. And there are no further questions at this time. I will now turn the call back over to our presenters for any additional or closing remarks.

Sean Woolverton: No, I will just close by thanking everyone for joining our call today. We always appreciate the questions and the interest in the company and look forward to further updates at the next quarter call. Everyone, have a nice day.

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