SilverBow Resources, Inc. (NYSE:SBOW) Q4 2022 Earnings Call Transcript

SilverBow Resources, Inc. (NYSE:SBOW) Q4 2022 Earnings Call Transcript March 2, 2023

Operator: Ladies and gentlemen, thank you for standing by. My name is Brent, and I will be your operator today. At this time, I would like to welcome everyone to the SilverBow Resources Fourth Quarter and Year-End 2022 Conference Call. It is now my pleasure to turn today’s call over to Jeff Magids with SilverBow Resources. Sir, please go ahead.

Jeff Magids: Thank you, Brent, and good morning, everyone. Thank you very much for joining us for our fourth quarter and full year 2022 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. 2022 was truly an exceptional year for SilverBow with strong execution on our business plan. We grew production and EBITDA by double digits, established new 8 bridge blocks providing for additional inventory, completed 4 accretive acquisitions and realized a 25% increase to our share price. Furthermore, SilverBow was named as one of Houston’s top workplaces for the third year in a row. The 4 acquisitions we completed in 2022 added a deep bench of premium inventory across our portfolio. As of year-end, SilverBow has over a decade of high rate of return drilling locations, 2/3 of which are oil locations. Using SEC pricing, our proved reserves increased nearly 60% year-over-year to 2.2 Tcfe, and our proved PV-10 increased to $5 billion.

At recent strip pricing, we estimate our proved PV-10 is just under $3 billion. As of our earnings update in November, we shifted both of our drilling rigs to Webb County to develop Austin Chalk wells in our prolific Fasken area during a $5 per Mcf gas price environment. As gas prices fell at the end of the year, both of our drilling rigs were shifted to our central oil area to capture better returns associated with higher oil prices. Remaining flexible in our operations and capital allocation has been and will continue to be a defining part of our business strategy and success. As we laid out in our 2023 budget yesterday, we are targeting a 2-rig drilling program this year focused entirely on oil development. In recent months, oil prices have shown relative strength compared to the gas strip.

As a result, we see the highest returns this year through acceleration of our oil development. Much of our focus will be on assets we have acquired over the last 24 months. Additionally, there are several short-term factors occurring in South Texas today. First, regional supply in Webb County increased roughly 50% year-over-year or approximately a half a Bcf per day in response to increased drilling and completion activity and strong wealth performance. For reference, the Webb County rig count increased from a low of 2 rigs in late 2020 to a high of 17 rigs in late 2022. Regional supply is now pushing up against available pipeline capacity. Second, on the demand side, Mexico exports have trended below 2022 levels. Regional demand has further — was further impacted by outages at a key LNG export facility and a warm winter season.

The net effect is a governor on growth in Webb County Gas in 2023, which should improve with multiple new pipeline projects expected to come online at the end of the year. This is where SilverBow’s balanced strategy stands out. We are well positioned to optimize our drilling schedule and accelerate development of our oil assets, thanks to the actions we took over the last several years. SilverBow has previously discussed achieving a longer-term 50-50 balance between oil and gas. With this year’s budget, we can accelerate that time line, and we expect liquids to comprise roughly 45% of our total production by year-end 2023. Our key focus areas include our Central oil area, our Western condensate area and our Eastern extension area. We also plan to target the Austin Chalk formation across these oily positions where we are seeing strong performance to date and the potential for future drilling inventory upside.

Furthermore, in addition to shifting both drilling rigs to our oily assets, we have elected to DUC 8 Webb County Chalk wells, pending higher gas prices. As Chris will further detail, 90% of our gas volumes are hedged in 2023, leaving little downside exposure to gas prices. At the same time, we are 50% hedged on oil for the year. So as we ramp our oil production, we will benefit from any uplift in the oil price curve. To wrap up my prepared remarks, I would like to note that our capital budget is one piece of a multiyear strategy, which is unchanged. 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. Our team has an established track record of delivering on our key objectives through commodity cycles.

We see a robust pipeline of opportunities ahead that will continue to unlock value for all of our stakeholders. With that, I will hand the call over to Steve.

Steven Adam: Thank you, Sean. SilverBow was proud of our operational and safety accomplishments over the past year. They were the result of cross-functional teams working in unison to deliver some of our best results to date. First, core to the SBOW way, we exemplified our safety strong tenant by achieving a 0.09 TRIR for 2022. Additionally, our production operations team recently celebrated its 6-year anniversary with 0 OSHA recordable accidents. Our team accomplished this while doubling the pace of our drilling activity to 2 rigs mid-year and managing a much larger asset base after the integration of numerous acquisitions. Moving to well performance. We are excited about the results we are achieving from recent wells and the quality of rock we are developing.

A key focus area for SilverBow in 2022 was the development of the Austin Chalk formation primarily in Webb County. These wells continue to outperform expectations. Today, our Austin Chalk wells have achieved IP30 rates, 25% higher on average, compared to our historically prolific Lower Eagle Ford wells. Furthermore, Austin Chalk EURs normalized for lateral foot are averaging nearly 50% higher than combined Upper and Lower Eagle Ford offsets. As of year-end, we had over 80 Austin Chalk locations in Webb County. And given the thickness of prospective intervals and stagger development, we see further inventory upside across our acreage. Specifically in our Dorado area, we are seeing some of the highest performing Chalk gas wells in our portfolio.

Towards the end of 2022, we brought several Chalk wells online in our Fasken area, with individual peak production above 20 MMcf per day. These wells are exhibiting lower decline rates more akin to conventional reservoirs when compared to Eagle Ford wells. Given the limitations on incremental growth in Webb County that Sean discussed, we are expecting to return to developing this area next year. Competitively speaking, our team assembled and consolidated high-return acreage positions across our liquids areas in 2022. These actions significantly increased our inventory count and economics due to optimized spacing and lateral lengths. Year-over-year, we increased our location count by 85% with over 15 rig years of inventory life. Of the wells we are drilling in 2023, most will come from our acquired assets.

On Slide 11 of our corporate presentation, we show the key focus areas of our 2023 budget and our inventory runway. We also see promising Austin Chalk potential in many of these areas. Based on the initial petrophysical assessments and well results from SilverBow, we see additional inventory upside in the Chalk formation. Moving to operations. Our team continues to deliver faster cycle times, further improving capital efficiencies across all major areas. On an accrual basis, our 2022 CapEx of $328 million was just below the midpoint of guidance. Our full year 2022 D&C costs were within 1% of AFE, a major accomplishment considering the commercial pressures from industry-wide cost inflation. If efficiencies further increased throughout the year as we stepped up to a 2-rig drilling pace and took control of operations on acquired assets midyear.

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In the fourth quarter, our D&C costs were 11% below AFE. During this time, we averaged 13 stages per day with our frac crew while exceeding 85% pumping efficiency on numerous pads. Compared to the first half of last year, this is an increase of 4 stages per day and efficiency gains of 10% to 20%. Although efficiencies were already high in recent years running 1 rig, our 2-rig cadence has provided another pronounced lead cycle times and frac utilization. With regards to our current inflationary pressures, we are seeing a plateauing cost creep and believe we should see some selective cost deflation in the second half of this year. For 2023, our capital budget guidance of $450 million to $475 million reflects a level-loaded 2-rig program throughout the year and provides for 52 net wells drilled and 57 net wells completed.

Half of our D&C CapEx is allocated to our Central oil area, with the remainder equally split between our Western condensate and Eastern extension areas. Additional non-D&C CapEx is also being deployed towards various ESG improvements and related activities. Late last year, SilverBow published ESG metrics as aligned with SASB and GRI reporting standards and is currently working towards releasing its inaugural sustainability report in the first half of 2023. To wrap up, our first quarter production guidance of 295 to 316 MMcfe/d reflects the deferral of 8 wellbores in our Webb County Gas area until early ’24 and ongoing dry gas curtailments at firm capacity levels. November of ’22, we were running 2 rigs on our gas acreage. And by the end of December, we had moved both rigs to our oil acreage.

As Sean mentioned, this flexibility is core to our commercial strategy. First quarter oil production does not reflect the full benefit of a dedicated 2-rig development program given the aforementioned fourth quarter rig movements. On a full-year basis, our 2023 oil production is expected to increase by 100% year-over-year, and our total production is expected to increase by approximately 25% at the midpoint. Our dry gas production guidance assumes we are only able to produce at contractual firm pipeline capacity levels through year-end. In January, dry gas production averaged in line with these firm pipeline capacity levels. In February, we were able to sell into some interruptible capacity, and thus, average volumes were slightly above firm pipeline capacity.

However, as mentioned, our guidance conservatively assumes we are limited to firm pipeline capacity. Near-term visibility on takeaway capacity remains opaque, and we will continue to monitor and assess as the year progresses. Consistent with our long-term business plan, we remain flexible in our development program and opportunistic in maximizing returns for 2023 and beyond. The pivot point to oil this year plays right into our multiyear playbook and is a direct reflection of the strategic action SilverBow has made over the past several years. With that, I will turn the call over to Chris.

Christopher Abundis: Thanks, Steve. In my comments this morning, I will highlight our fourth quarter and full year financial results as well as our operating costs, hedging program and capital structure. Fourth quarter oil and gas sales were $199 million, excluding derivatives, with natural gas representing 66% of production and 50% of sales. During the quarter, our realized oil price was 99% of NYMEX WTI. Our realized gas price was 84% of NYMEX Henry Hub, and our realized NGL price was 29% of NYMEX WTI. As shown on Slide 22 of the corporate presentation, we have historically realized close to NYMEX benchmarks. During the fourth 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, the impact of which could extend until additional pipeline projects come into service towards the end of 2023. Furthermore, 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 over 150 MMcf/d to mitigate further risk. Our realized hedging loss on derivative contracts was $34 million for the fourth quarter and $212 million for the full year. Based on the midpoint of our guidance and our hedge book as of February 24, SilverBow has 73% of total estimated production volumes hedged for 2023. Broken down by commodity, the company has 89% of natural gas production hedged, 51% of oil hedged and 46% of NGLs hedged for 2023.

Assuming our production guidance is held flat in 2024, our total production is approximately 40% hedged. The hedged amounts are a combination of swaps and collars. A detailed summary of our derivative contracts is contained in our presentation and Form 10-K filing, which we expect to file later. Specific to our gas hedges in 2023, as we are 90% hedged, our revenue is very insulated to any downward movement from the current strip. While commodity prices have been volatile in the last several years, we remain judicious in locking in favorable returns on our capital investments. Turning to cost and expenses. Fourth quarter LOE was $0.63. Transportation and processing costs were $0.35, and production tax is 5.8% of sales or $0.40 per Mcfe. Adding our LOE, T&P and production taxes together, our total production expenses were $1.38 per Mcfe.

Cash G&A, which excludes stock compensation, was $5.4 million for the fourth quarter, which was slightly higher than our guidance range due to professional fees. For 2023, we are guiding for cash G&A of $17.5 million at the midpoint, a 7% increase from 2022. Notably, our cash G&A is lower year-over-year, inclusive of our recent acquisitions. This will drive meaningful G&A reduction on a per unit basis. We consider our lean cost structure to be a competitive advantage, which allows us to sustain profitability during periods of volatile commodity prices. Additionally, we expect to continue identifying synergies within our cost structure as we accelerate our liquids development across our recently acquired assets. Adjusted EBITDA for the fourth quarter was $119 million, exclusive of pro forma contributions from acquisitions.

As reconciled in our earnings materials, we generated $2 million of free cash flow in the fourth quarter and $22 million of free cash flow for the year. Consistent with prior years, whichever amount of free cash flow that was not reinvested in the drill bit was used to pay down debt. While we ended the year at a leverage ratio of 1.35x, we remain on track to achieve a leverage ratio below 1x. As previously mentioned, we closed 4 accretive acquisitions in 2022, in line with our disciplined M&A strategy and added additional acreage through leasing activity. Total consideration for property acquisitions was $593 million. This reflects a combination of stock and cash used for the acquisitions and transaction-related fees valued at the time of close and net of purchase price adjustments.

Cash consideration for these deals after giving effect to purchase price adjustments totaled approximately $370 million. CapEx on an accrual basis totaled $103 million for the quarter and $328 million for the full year, excluding payments for acquisitions. Our 2023 CapEx guidance of $450 million to $475 million, which Steve detailed in his comments, is based on a steady 2-rig drilling pace throughout the year. Year-end proved reserves using SEC pricing were 2.2 Tcfe, 77% of which were natural gas and 43% of which were proved developed producing. Our proved PV-10 was $5 billion, and our PV-10 was $2.6 billion, an increase of 173% and 150%, respectively. Turning to our balance sheet. We executed several initiatives in 2022, which allowed us to upsize and extend our credit facility maturity, increased liquidity and self-fund acquisitions.

In June, we initiated a wildcard redetermination in conjunction with the Sundance acquisition. With the full support of our bank group, we increased our borrowing base from $460 million to $775 million and extended the maturity date of our credit facility by 2 years out to 2026. Related bank fees for the upsize and extension were approximately $7 million, which we do not back out from our free cash flow calculation. Our year-end total debt was $692 million, and liquidity was $234 million. SilverBow, in accordance with our credit facility, includes contributions from closed acquisitions for the entirety of the LTM adjusted EBITDA period used for the leverage ratio calculation. Full year 2022, the contributions from acquired properties totaled approximately $118 million, bringing our LTM adjusted EBITDA for leverage ratio to $511 million and our year-end leverage ratio to 1.35x.

It is worth highlighting that we remain relatively leverage-neutral while funding $370 million of cash acquisition costs. At year-end 2022, we were in full compliance with our financial covenants and had sufficient headroom to execute our business strategy. And with that, I’ll 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 a half a billion cubic feet equivalent per day of production. In the near term, a key catalyst for our stakeholders is our ramp in oil production. Our relentless focus on our employees, well-being and safety is paramount to our culture as is our engagement with the community and our environment. We look forward to sharing more of our insights towards safety and clean operations with the release of our inaugural sustainability report in the first half of this year. On a final note, the Eagle Ford has seen a flurry of M&A activity over the last 12 months.

In our view, this is a strong signal by the market is being driven by several factors. One, the Eagle Ford is one of the best understood and well-defined shale plays, which translates to consistency and execution in development. Second, acreage ownership across the basin remains fragmented, with dozen of private operators running small scale drilling programs, which creates accretive consolidation opportunities. Third, the proximity of the Eagle Ford to industrial demand centers, international exports and Gulf Coast LNG, combined with existing midstream infrastructure capacity, results in higher realized pricing compared to other U.S. gas basins. SilverBow has been a key consolidator within the Eagle Ford and Austin Chalk, and recent announcements by other large operators points to a strong buyer’s market for M&A.

I want to thank all 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.

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Q&A Session

Operator:  Your first question is from Neal Dingmann with Truist Securities.

Neal Dingmann: Sean, my question for you and the team — understand you guys laid out a nice math as far as the 2 rigs going to be going more after oil. I guess my question on that — the plan and kind of looking at, what is it, Slide 14 or — I guess, it’s Slide 15. How much the plan — looks like — are you going to do more — is it more developmental activity in the front half, and then the second half would be more delineation or will the — maybe just give me a little bit more color, I mean, or will be kind of a mix throughout the year. I know there’s certainly some exciting opportunities in the Lower Eagle Ford and Chalk. So I’m just wondering when you — when I think about those 2 rigs, is one going to be more pure developmental and the other is more delineation? Or how should we think about those for the year?

Sean Woolverton: Thanks for the question. Yes, as we think about where we’re drilling in ’23, it’s across 3 areas. Really, the Western Condensate and Central oil area are 2 areas where we’ve drilled extensively over the last several years. So feel very comfortable that our drilling in those areas is more along the lines of a development type risk profile. The third area where we’re drilling is in our Eastern extension area, and that’s an area where built a — just under 15,000 acre block over a couple of acquisitions, one in ’21 and one in ’22. We’ve been patient in drilling up there waiting to put those 2 deals together. We’re really excited to be out there in drilling. It’s in a very proven area. Many of the top operators offset us.

But we’re going to drill both Austin Chalk and Eagle Ford on that position. And so we’ve got a rig on that area right now as we speak. And so to your question, yes, I see this area is a little bit more of a step out and proving up area for us in the first half of the year. But with early success, our plan is to actually park a rig there going forward. So we have high confidence in the area. But as always, we want to be patient in our development pace. And so that’s probably the one area that has a little more of a step out into it.

Neal Dingmann: Is there a threshold you need to return back to Webb? I mean is it $3, $4? I mean is there a number or the plan pretty much this year will still stay in that liquids area?

Sean Woolverton: Yes, yes. We always are looking at returns and thinking about our views on commodity prices. We always go through a very systematic approach. First, it’s always around operational execution. Does it make sense from a timing of service availability where our rigs currently sit, and then obviously, the takeaway capacity. So that will kind of be the first check. And then it’s — do the returns compete with our oil inventory? Really a rule of thumb for us is when oil to gas is about a 15:1 ratio. Our returns are very similar between gas and oil. If it’s above 15 and where it currently sits more in that 20 to 25 range, we will drill oil every day. If it’s below 15, we’d actually, like we did late last year, moved both rigs into the gas area.

So it’s really, for our — from our view — financial view, we want to — we’ll drill the best returns. And that ratio is kind of a loose guideline for us and maybe a signal to the market when we might shift to gas versus just a flat gas price as a signal.

Neal Dingmann: No, I’d like to hit it. And 2 more, if I could. Just on hedging. You guys continue to be in a better financial spot. Just thoughts on the — future curve is quite still quite good for gas. Are you looking out to ’24, even ’25 to put more gas hedges on?

Sean Woolverton: Yes, yes. No. Yes, definitely, as we think about ’23 and concerns on ’23’s volatility on gas, we feel very good about being essentially — totally insulated to lower prices, but still exposed to — if gas prices move higher because we have a lot of collars. So right now, the strips below our floors on our collars, so we are asymmetrically exposed to the upside. Longer term — and we kind of like to think about our reserve report from 2022. If you look at the ’22 prices being very high, $6, $90 oil, but more specific to $6 in the — 75% of our reserves being gas, it demonstrates really the underlying value of SilverBow with a value of close to 5 billion. So as we think about upside, we’re very bullish on oil long term, that being end of ’24 into ’25 — or excuse me, very bullish on gas in that period.

So to your question, will we be hedging out? It’s in contango, but we think there’s more upside. And so similar to what we’ve done this year, we made a call on oil and have left ourselves some exposure to oil. Probably, we’ll look to continue to bolster ’24 hedging on gas, but we’ll be — we’ll stay open on ’25 plus just because we’re very bullish on gas starting in ’25.

Neal Dingmann: Okay. And sorry, but not just one last one just on M&A. I know — look, I know you guys are always looking for creative deals, but is there opportunities just for little bolt-ons or just some trades as you continue to do that? I’m wondering how active you are on that these days.

Sean Woolverton: Yes. No, good question. I think we’ve seen a flurry of larger-scale deals in the Eagle Ford over the last 6 months. We were an early mover more on probably some smaller-scale deals and feel like that still is a niche for us. And what we’ve seen — and we kind of have a longer-term view and really worked the map hard. But as our footprint has grown, the opportunity set to do more bolt-on deals, do JVs to drill longer laterals, to do small offsetting acquisitions, that opportunity sets just continued to grow just with a larger footprint. So that’s really where our focus is in the near term, and we think it adds a ton of value kind of being strategic from an industrial logic standpoint to build on the position that we already have.

Operator: Your next question is from the line of Charles Meade with Johnson Rice.

Charles Meade: I wanted to push a little bit more on some of the same topics that Neal was asking about. The 15:1 ratio you cited was — is really helpful, I guess, coordinate. But to elaborate a little bit more around that. So we’re looking at a strip of oil, which is, call it, 75. So that would suggest that at $5 Henry Hub, your oil assets would be about the same — equally attractive as your natural gas assets. But does that mean that we shouldn’t expect you to took back to natural gas until 5? Or does it mean that some of your best natural gas stuff may start to work back into the picture at, I don’t know, How should we think about the — how the curve is going to look in that regard?

Sean Woolverton: Yes. No, no. Appreciate the follow-up on it. Yes, the 15:1 is kind of the probably lose 13 to 17, the returns become pretty similar. So in a 4 and 60, 65 dollar environment, we have one rig running in gas, one rig running in oil. And that’s our current kind of view once you get into mid-’24 going into mid-’25 with the contango and the gas curve and the oil curve being backwardated. So that’s kind of how we’re modeling things out, one rig in both areas by mid-’24. And then if our view on gas plays out in ’25, probably might anticipate 2 rigs running in the gas window in ’25. But what’s great is we have an inventory that can go either way. And what we’ve always said and love about the Eagle Ford, and we demonstrated it at the end of ’22, is we can turn on a dime.

I mean within 2 weeks, we were pulling rigs out into oil, and a lot of our peers just can’t do that, right? They’re in only gas and, unfortunately, continue to drill into a low price curve, which isn’t helpful to pricing dynamics. But we think our strategy of being able to shift is really demonstrating itself here.

Charles Meade: Got it. And yes, it’s certainly an advantage to be able to do that. I want to push a little bit further on natural gas activity. So you guys have these 8 DUCs in Webb County and makes all the sense in the world that you’d wait to complete those given the contango in the natural gas curve. But right now — I guess what I’m asking, is it a fair inference that you’re going to wait for something close to $4, like a $4 12-month average to complete those? Because they’re not in your ’23 CapEx plans as far as I understand. And let’s, call it, like a $3.50 kind of look as we look forward. So is it — should we be thinking about like $3.75 or $4 for you guys to go back and finish the work there in ?

Sean Woolverton: Yes, that’s kind of in that ballpark with — that we’ve had in the back of our minds. And we’d also look at operationally, if a window — if we see gas prices starting to get more stable late in the year, and window opening up on our frac spread that primarily serves the 2 rigs, but sometimes it’s so efficient that windows present themselves. We might slide down and kick those 2 pads out, which would really our volumes end of year. And maybe we see a strong winter next year, pickup in the LNG exports as Freeport comes back online, and hopefully, more response from gas players as a whole to delve back on supply. So we’re going to be nimble, but I think $3.50, $4 and the earliest probably would be late in the year that we would do something.

Operator: Your next question is from Donovan Schafer with Northland Capital Markets.

Donovan Schafer: I have — the first one I want to ask — I thought it was interesting idea about taking the 2022 pricing reserve report as sort of a data point for what things could look like in 2024 or 2025 pricing environment. So my question would be, if we kind of go through that thought experience, what other kinds of adjustments maybe would there need to be gives us a useful data point for pricing? But clearly, based on guidance, your expectations, you have growth and — production growth in 2023, there could be some changes in production mix versus oil versus gas. So just curious what the big things are. Maybe would need to adjust for or account for if we did take something like this as a rough approximation for what kind of valuation could be appropriate in the 2024, 2025 time frame?

Sean Woolverton: Yes. No, great question. Our reserve report at year-end, as we were starting to already pivot towards more oil does reflect the activity that’s lined out in ’23, but that report then shifts back to a 50-50 split on capital. So one rig in oil and one rig and gas starting in ’24. So it’s more back to our traditional mix of capital allocation. Now where is there upside? It still would be driven by price, but it would be probably in ’24 as a lot of people are forecasting potential strong moves in gas north of 5, 6 and probably oil coming down a little bit. That reserve report could have even more upside if we convert it to 2 rigs of gas going into a higher gas price curve. So again, as we’ve thought through it, under — we feel the stock is very undervalued and that it’s very just near term looking by investors.

We’re really trying to help investors understand that the upside potential here is higher gas prices, which just a pretty consistent view across a lot of forecasters that said it’s only 24 months out. And we really, to your point, feel like ’22 reserve report demonstrates the underlying value of the company quite well.

Donovan Schafer: Okay. That’s helpful. And then kind of related, and I don’t know there’s potential upside or whether there’s potential upside here, but kind of getting at the question of decline rates. So what is your current corporate average or blended decline rates with sort of if you hit the pause button and weren’t doing any more drilling? I know that can be sensitive to wells that have recently come online, but also, like you guys said in the prepared remarks, some of the Austin Chalk wells are starting out with lower-than-expected decline rates. I mean the production level itself is great, but they’re declining actually slower. So you’re getting a more mature kind of base over time. So just kind of curious to where that puts us at kind of current decline rate and maybe where that would be in like 2024. And if that’s reflected, if it’s a trend towards a lower decline rate at all, if that’s reflected in the reserve report or not.

Sean Woolverton: Yes, yes. The reserve report reflects our best estimates — our reserve engineers best estimates as well as our auditor on what wells are declining off at. But in general, we’re seeing coming out of ’22 into ’23 about a 30% decline on our base PDP assets. That will remain a little flat over ’23 because we have curtailment occurring down in our high-rate gas areas. And so we’ve been choking back some of our large Austin Chalk wells, which, to your point, exhibit a different decline rate than the Eagle Ford. We’re seeing initial declines out of the Austin Chalk in that 55% to 65% range, where Eagle Ford is more 75% to 85% range. So yes, that shift to Austin Chalk, we’re seeing some benefits to that on the base decline.

Now counter to that, going from 1 rig to 2 rigs in ’22 and then maintaining that 2 rigs, we are shifting more of our production to more recent wells. So as more of our production comes from newer wells, we’ll be fighting an increasing decline rate. So probably seeing more of a move up in decline over the next year or 2, but that’s being driven by the large capital program.

Donovan Schafer: Sure. Sure. Okay. And then just one last question. For the 8 DUCs that you added in Webb County, could you tell us what the capital spending was to drill those and then what incremental CapEx would be needed to complete them? I’m just — what — I’m asking because I’m trying to get the sense or the idea of — I call this embedded growth in some other context. But it’s the idea of like where you’ve already spent the money, so the CapEx and impact in cash flow and other stuff that’s already been there, but we’re not going to really see any benefit from that until 2024 or 2025. So just how much of that capital has been laid out already that won’t need to be incurred later? And then what would be required later?

Sean Woolverton: Yes. No. We’re seeing wells down in the Fasken area. As they’re low back in late 2021, we had pushed them down below 5 million. More recently — that’s all in, drill and complete. More recently, that’s pushed upwards of 7.5. So drilling mix of probably 40% — 35%, 40% of the spend. So across those 8 wells, total investment would be close to $60 million, $65 million. We’ve already probably sunk about $25 million to $30 million in those wells. So definitely, that’s a little bit of a stranded capital for us right now. But again, we think economics and the contango on the gas curve just makes sense to kind of hold ground on those. But going forward, we’ve got another $35 million, $40 million to spend to bring that all online, and we can bring it on quickly being that they’re drilled.

Operator: Your next question is from the line of Noel Parks with Tuohy Brothers.

Noel Parks: Just had a couple of things. I was wondering, with the shift towards the oilier areas in your holdings, between sort of the budget you were envisioning when you were probably going to leaning — be leaning gas here and the current budget, any significant delta in the infrastructure or facility spending that you’re looking at now that you’re going to be back in the oilier areas versus the original gassier budget?

Sean Woolverton: No. Probably as a whole, both when we were thinking 1 rig gas, 1 rig oil, our overall CapEx to go to 2 is the same, but our percentage of what we spend on facilities and land always runs in that 10% to 12% range regardless if it’s 2 rigs oil, 2 rigs gas or a split. So pretty consistent. 90% of the spend goes to D&C. Of that 10 broken between facilities and land, it’s probably 2/3 facilities, 1/3 land. And then we always reserve the right that if there’s opportunistic leasing to do, we’ll maybe put more dollars to work on land.

Noel Parks: Sure. Sure. Right. And just wondering, with your — now hanging on to those DUCs instead of completing them right away, can you just talk a little bit about the frac pace you’re looking at? And I was just wondering if in making the changes you’ve made to the plan, any issues with frac crew access operating in a different end of the play?

Sean Woolverton: Yes. Why don’t I let Steve address that?

Steven Adam: Sure. Thanks, Sean. Good question, Noel. Let me kind of give a little bit of backdrop for it. Up until middle of last year, we were only 1 rig. And so we had kind of a lot of gaps in our frac schedule. But since the middle of last year, we haven’t been able to fully level load frac rig, but we’ve been a — proven spread, but we’ve been in a position to, on average, around 80%, 85% of the load, and we’ve been able to find comfortable fills for those gaps because we have a schedule that looks pretty far out. So the timing of all that, Noel, we’ve been able to come back pretty fast on anything that’s either an opportunity or as it’s scheduled. So for instance, our frac schedule follows pretty much in cadence with their drilling rigs.

As you know, historically, we’re not really a DUC company. So as it relates to these DUCs that we do have already in our portfolio, we have flexibility, and we have GAAP opportunity by which to take our frac spread to that. So that’s — availability right now hasn’t been a concern. In terms of the efficiency, right now, our frac spread is the premier frac spread in the entire Eagle Ford, and it’s the #4 frac spread in all of America short of 3 opportunities in the DJ Basin, which are much more — much different environment and not even as risk-oriented as what we do in the Eagle Ford. So very fortunate there from a frac efficiency point of view with respect to the crew that we’ve been able to use for some time now and continue to plan to use.

And then products related to that frac facility, as we look at all the components to it, horsepower, sand and chemical, we’ve been able to work with our provider and also hold the line on certain items as it relates to unit cost for that. And then secondly for sand and some of the other needs in terms of our water facility needs for that, we’ve also been able to hold the cost. And there, that’s why we’ve been able to offset some of those inflationary pressures that we talked about earlier and being able to now hold within 1% of AFE and then some — and then also at midpoint of CapEx. So we feel comfortable in being able to go with that forward, especially with the backdrop of some of the lower decline issues we’re seeing in inflation.

Noel Parks: Great. And just one last one for me. When you’re talking about with the DUCs, you do have some capital that’s in the ground that if you were just completing straight ahead, you get that return sooner. So just kind of thinking about liquidity. And yes, of course, you have flexibility on the credit line. But I’m just sort of thinking maybe for the rest of this year, there’s a little bit of crystal ball stuff I’m asking. But if you decided you were going to do a transaction or maybe gas responded more quickly, and you decided you were going to, I don’t know, go a little bit more aggressive on activity, all things being equal, would you see yourself if you decided to do some debt financing more gravitating towards the credit line, like a variable rate type debt?

Or would you be thinking more looking at the debt markets about, no, we want fixed rate, kind of the double we know? So I know it’s kind of a very amorphous question, but just curious your thoughts on that.

Sean Woolverton: Yes. No. Just like we think about drilling capital, right, in getting the best returns on our drilling capital, same on as we look at debt and credit. So always try to assess, hey, what’s the best cost of capital that we can get, but keep risk mitigated. I would tell you, our view would probably lean more towards fixed so that we know what that is and where it’s going forward. Right now, our debt, with that said, is variable, and it’s moved up on us. So both the revolver and our second lien have a variable component to it. So we’ve experienced that and think that, hey, if we found a fixed rate that works for us and we could term out some of that variable debt, that’s something we would do.

Operator: Your next question is from the line of Tim Rezvan with KeyBanc Capital Markets.

Slate DeMuth: This is Slate on for Tim today. Just a couple of questions. For one, I was wondering if you could talk specifically about the cost deflation you’re seeing with the rigs. And are you seeing anything similar on the pressure pumping side?

Sean Woolverton: Yes. Maybe I’ll let Steve kind of briefly touch on that high level off at the stage that we are seeing cost pressures peak and now are even starting to see a little relief. So encouragement on that front.

Steven Adam: Thank you, Sean. Yes, Slate, we are in a situation right now where the market on the rigs in the Eagle Ford, and I’ll just stay specific to that. At least on the gas side, there’s rigs that are coming down. And on the oil side, there’s even some rigs that are kind of either changing shape or coming down. That said, the market price is such that we’re seeing softening on the rig contracting side for rigs, both in the near term and also some conversation in the longer term. That said, it’s even further supported by the backdrop of term on contracts. So we’re seeing shorter term on contracts and, in some cases, pad-to-pad with quality equipment. So that’s kind of the near-term outlook on rigs, and we’re kind of expecting that deflation to continue into the second half of this year, and then we’ll see where ’24 takes us.

On the frac spread side, we’re seeing a lot of those costs just basically plateau and level out with some softening in certain areas, especially, say, for example, on things like water transfer and support and service and to some degree on sand. Sand has been kind of bimodal with a higher and a lower cost structure. We’re entering into that lower mode right now as we see some of these volumes tick down in the aggregate Eagle Ford area.

Slate DeMuth: Got it. That’s very helpful. And then for my follow-up, maybe just a bit bigger picture. I believe you all have highlighted kind of a longer-term 50-50 gas to liquids mix for your portfolio. I was wondering maybe just kind of a time line on that. Do you expect that to be over the next 2 years, 2 to 3 years? Or is that kind of maybe a bit longer-term view, 2025, 2026, that comes with this LNG build-out?

Sean Woolverton: As we look at getting to the end of this year, we’re starting to approach the 50-50 mix. So as we stay with that 1 rig — let’s assume ’24 is 1 gas, 1 oil, we’ll probably stay in and around that 45 to 55 split year-over-year. And where we would see it start to move away from that and maybe go more gas-heavy is if we shifted — allocated the capital to 2 gas rigs. So we’re getting to that 50-50 mix almost this year, and it’ll stay that way, assuming a 1 rig oil, 1 rig gas scenario.

Operator: Your next question is from the line of Charles Meade with Johnson Rice.

Charles Meade: So forgive me if I missed this, but thinking about the — your PDP, PV-10 at the strip, it looks to me based on some of the coordinates you gave us, it’s probably around one four, one five. I don’t know if you gave us that number or if that number is in the right ballpark.

Sean Woolverton: Yes. I hate to speak to it and that we’re looking at that quite often, and the strips always moving. So I don’t have like a firm number off the top of my head. We’re looking here — yes. What we provided was at SEC pricing. So yes, we don’t have that in front of us.

Charles Meade: Okay. But I think you did mention, Sean, the total PV-10 was — I think you said just under 3.

Sean Woolverton: It was right at 3. And so that’s kind of not a bad inference, right, that maybe you could get into it that at year-end, we were 45. The year-end value of 5 billion reflected just under 45% PDP. I’d say, take that and apply it.

Operator: There are no further questions at this time. I will now turn the call back over to the company for closing remarks.

Sean Woolverton: Appreciate everyone’s interest in the company. Appreciate the questions, and we look forward to our next call and sharing an update in the second quarter. Appreciate it. Thank you.

Operator: Ladies and gentlemen, thank you for participating. This concludes today’s conference call. You may now disconnect.