SilverBow Resources Inc (SBOW) 2018 Q4 法說會逐字稿

Hello, my name is Lonnie, and I will be your conference operator today. At this time, I would like to welcome everyone to the SilverBow Resources Fourth Quarter and Full Year 2018 Earnings Call. (Operator Instructions) Thank you. I would now like to turn the call over to your host, Jeff Magids. You may begin.

Thank you, Lonnie, and good morning, everyone. Thank you very much for joining us for our fourth quarter and full year 2018 conference call.

Joining me on the call today is Sean Woolverton, our CEO; Steve Adam, our COO; and Gleeson Van Riet, our CFO.

We posted a new corporate presentation onto our website and will occasionally refer to it during this call. We encourage investors to review it. 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 will 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.

And with that, I will turn the call over to Sean.

Thank you, Jeff, and thank you, everyone, for joining our call this morning. We are pleased to report another strong quarter, closing out what was a year of execution for SilverBow.

Our financial and operational results demonstrate both the quality and growth potential of our assets. This morning, I will briefly highlight what we accomplished in 2018 and lay out our objectives for 2019.

In 2017, we discussed what separates our company from others, quality assets, exceptional people and a strong capital structure. With those elements in place, we spent the bulk of 2018 taking a disciplined approach to developing our acreage, by focusing on growth, continual per unit cost reductions, expansion of our drilling portfolio and management of our balance sheet.

In terms of our assets, we have been active across all areas. We pursued a 2-rig drilling program for the majority of the year. This program not only allowed us to develop and delineate our acreage position, but also provided us with extensive and valuable data.

Our backend-loaded program led to fourth quarter productions at the high end of guidance, representing nearly 20% growth quarter-over-quarter and approximately 33% growth in the second half of the year.

We reported both strong oil and NGL production in the fourth quarter with oil coming in 20% higher than the midpoint of our full year guidance. Our recent results indicate the commerciality of our liquids portfolio, which we look to increase as a percentage of our overall production in 2019.

On the cost structure side, we were able to bring more wells to sale than we originally planned due to cycle time compression and efficient scheduling. Even as the cadence of operations increased, our team continues to find opportunities to both reduce capital expenditures and expenses.

This was evidenced by the 33% decline in lease operating expenses on a per unit basis year-over-year. Our relentless drive to target efficiencies continues as we further delineate our position.

All in, our cash operating expenses, including G&A, totaled $0.92 per Mcf in the fourth quarter, making us one of the most cost-competitive producers in the basin today. Steve will provide additional details on our cost-reduction initiatives in the operational section.

Our growth profile is supported by a deep inventory of drilling locations. As of year-end 2018, we held 1.35 Tcf-approved reserves, up 31% compared to 2017. Our PV-10 increased to $1.1 billion, up 40% compared to the prior year. Approximately 40% of our reserves are proved developed. We believe our acreage links to stack pay development and further upside potential with over 15 years of future development at a 2-rig pace, we have a significant runway to grow our business.

From a financial perspective, our adjusted EBITDA of $168.4 million for 2018 represents a 38% increase year-over-year. Given strong well results, access to premium markets and effective cost control, we achieved our goal of expanding our EBITDA margin to 65%.

Unlike operators and other plays across the country, we realized a premium to both WTI and Henry Hub. This allows us to generate some of the strongest revenue on a per unit basis amongst our gas-producing peers.

Our competitive cost structure is further supported by improving financial strength. During our semiannual borrowing base redetermination, our revolving credit facility was increased to $410 million, offering us even greater financial flexibility as we develop our assets.

Our balance sheet and debt metrics will continue to be a focal point for us as we navigate what has proven to be a challenging commodity price environment. Gleeson will touch on this in his remarks.

As we look forward to 2019, we are well positioned to capitalize on our team's talent and assets to generate even greater value. Our team continues to explore additional ways to improve our performance, including the testing of new landing targets, high-intensity slickwater completion designs, proppant intensities and stage spacing across all areas of our portfolio.

Our 2019 capital budget range of $250 million to $260 million represents a 17% decrease from 2018. From an activity standpoint, we will be moving to a 1-rig program in the second quarter. Approximately 85% of our 2019 capital budget is allocated toward drilling and completion. And similar to last year, we will be investing across our entire asset base, developing both our liquids and gas properties.

As highlighted in our corporate presentation, we are targeting approximately 36% of our spend on gas-weighted projects and approximately 64% of our spend on liquids-weighted projects.

Our 2019 capital budget provides for 25% growth in production based on the midpoint of our guidance and sets the stage for us to reach positive cash flow in the second half of this year.

On the leasing front, we plan to continue adding low-cost inventory additions at attractive full-cycle economics returns. Approximately 5% of our 2019 capital budget is dedicated to this leasing effort.

The remainder of our capital spend will be for facilities and other optimizations. To support our multiyear development plan, we are vigilant about layering on commodity hedges and basis swaps to protect our returns as prices dictate.

We currently have approximately 65% of our production hedged for 2019 based upon the midpoint of our full year guidance. In addition to growing to the drill bit, we continue to evaluate acquisition opportunities of various size, commodity mix and geographic footprint within the Eagle Ford.

While we cannot predict the timing of our next acquisition, we are prepared to transact when the appropriate opportunity arises.

In closing, 2018 proved to be another exceptional year for SilverBow. We drilled across our entire portfolio, demonstrating the depth of our inventory, received favorable pricing from the premier market in the U.S., enacted cost initiatives, allowing us to reach a peer-leading EBITDA margin and expanded our borrowing base, showcasing the growth potential of our assets.

The progress we have made over the last 6 months has set the stage for us to move toward a more balanced commodity mix and has provided a clear path for us to reach positive cash flow.

And with that, I will hand the call over to Steve.

Thank you, Sean. Moving on to our operational results. Production of 227 Mcfe per day in the fourth quarter was driven by a substantial backend-weighted increase in activity across our portfolio.

For the full year, the company drilled 33 net wells and completed 32 net wells. We brought 24 net wells to sales in the second half of the year versus 6 net wells during the first half of the year.

During the fourth quarter, we brought online 12 net wells across our portfolio. These included 3 wells in our McMullen Oil area, an area where the company has been deploying more higher return capital.

All 3 wells have 30-day IPs of 145 BOE per day per 1,000-foot lateral. Based on results in this area, the operations team drilled 2 additional wells. Each well's lateral length exceeded 11,000 feet, with 1 being a SilverBow record lateral of 11,400 feet.

The company is looking forward to strong results out of these wells as we plan to complete them in the first half of 2019.

Our LaSalle condensate area -- in our LaSalle condensate area, all 3 wells returned to sales at the fourth quarter, at 30-day IPs over 140 BOE per day per 1,000-foot lateral with 1 well greater than 175 BOE per day.

In our Southern Eagle Ford gas area, we continued our successful delineation program and confirmed the resource potential of our 60,000 gross acre position by turning 3 wells to sales. Each well had 30-day IPs over 1.5 MMcfe per day per 1,000-foot lateral.

These well results validate the geological and metaphysical studies we have performed and demonstrate the potential of one of the best -- one of the better gas reservoirs in the country.

Given the strong well results across SilverBow's portfolio in 2018, we have updated our type curves. You can see a summary of these in the presentation we published yesterday.

Operationally, 2018 was a transformative year for the company. On the completion side, we moved from medium intensity exclusively gel-based frac designs to high-intensity frac selectively using slickwater designs across the portfolio. In the second half of the year alone, we completed 18 gross wells with slickwater designs out of 23 total wells.

Our average proppant intensity for the second half of the year was 2,900 pounds per foot, a 42% increase in the first half of the year. In the Southern Eagle Ford gas fairway, we tested proppant intensities up to 4,500 pounds per foot.

On the drilling side, we saw an increase in speed and efficiency across all areas and a corresponding decrease in cost. Our LaSalle condensate area -- in our LaSalle condensate area, we have consistently drilled wells under 10 days with some wells being drilled in less than 7 days.

As mentioned before, the team executed on 2 laterals in the McMullen Oil area that were longer than 11,000 feet. These results showcase the operational talent within SilverBow and our ability to efficiently execute anywhere within the Eagle Ford while driving a competitive cost structure.

Speaking of cost, we reduced our LOE to $0.23 per Mcfe in the fourth quarter, a 5% decrease from the third quarter. We achieved this through renegotiating chemical costs, optimizing maintenance activity and renewing our focus on field labor costs. Our peer leading LOE is the direct result of this cost reduction initiative and the performance throughout the year from our field operations in engineering teams continues.

We take an active approach to scheduling and operational management in order to minimize cycle times and bring forward production and cash flow. As part of this approach, we were able to accelerate more wells into the fourth quarter of 2018, and we will have another similar side set of wells coming online in the second quarter of 2019.

Due to these 2 large well sets coming online on either side of the first quarter of this year, we will turn on approximately 4 net wells in the first quarter of 2019. Specific to our 2019 budget, we plan to drill 26 to 27 net wells.

We will invest between $250 million and $260 million and shift down from 2 rigs to 1 rig in the second quarter. The reduced pace of activity is driven by our goal to reach positive cash flow in the second half of 2019.

The majority of our capital spend is focused on areas of high-return development, including our LaSalle condensate and McMullen Oil properties. Drilling these properties will also continue the company's trend of moving toward a more equally weighted production mix, which we feel is beneficial and given the volatility and current backdrop of the commodities market.

As we increase oil production, we plan to carry forward our peer-leading LOE, as we move to inherently more expensive-looking cost associated with liquid wells. We will also plan to invest as needed to further our understanding of the Southern Eagle Ford gas fairway and to prepare for increasing development in the coming years.

As part of this continued delineation and appraisal, we will drill 5 Southern Eagle Ford gas wells in 2019.

To recap, 2018 was a great year for SilverBow and the team achieved several important executional and operational milestones that will set us up for success this year.

With that, I'll turn it over to Gleeson.

Thanks, Steve. In my comments this morning, I'll highlight our fourth quarter financial results as well as our operating cost, hedging program and capital structure.

Fourth quarter revenue was $88.2 million, with natural gas representing 84% of production and 77% of revenue. During the quarter, our realized pricing was 104% of NYMEX WTI, 105% of NYMEX and Henry Hub and 39% of NYMEX WTI for NGLs.

We continue to be active with our hedging program. Based on the midpoint of our full year guidance, our total estimated production is 65% hedged for 2019. Our gas production is approximately 72% hedged, the weighted average price of $2.94 per MMBtu. Our oil production is approximately 39% hedged with a weighted average price of $56.69 per barrel of oil and our NGL production is approximately 42% hedged with a weighted average price of $27.93 per barrel.

In addition, we've also used oil and gas basis swaps to manage our exposure to differentials. For 2019, we have gas basis hedges on 158 Mcfe per day with a weighted average differential of $0.00. For 2020, we have gas basis hedges of 129 Mcfe per day with a weighted average differential of negative $0.04.

Turning to cost, lease operating expenses were $0.23 for Mcfe, down 33% compared to the fourth quarter of 2017, and down 5% compared to the third quarter of this year, primarily driven by continued cost reduction initiatives.

Transportation and processing cost for the fourth quarter were $0.35 per Mcfe, while production taxes for the quarter were 3.7% of oil and gas revenue, coming in below the low end of our guidance range.

Adding our LOE, T&P and production taxes together, we achieve total production expenses of $0.73 per Mcfe, which we believe stands out amongst our gas-producing peers.

Cash G&A of $4 million compared favorably to guidance of $4.6 million due to ongoing efforts to reduce administrative costs. We're guiding for cash G&A of $5.2 million to $5.7 million in the first quarter due to the timing of our annual bonus payments.

For full year 2019, we're guiding for cash G&A of $20 million to $23 million. As Sean mentioned, our cash operating expenses, including G&A, totaled $0.92 per Mcfe in the quarter compared to $0.95 in the prior quarter.

We ended the year at a level considerably low, below our $1.10 target. In total, strong production and continued cost initiatives resulted in adjusted EBITDA of $56.5 million, up 27% compared to the prior quarter.

Cash interest expense was $7.2 million for the quarter, a slight increase compared to the third quarter due to increased borrowings on our credit facility.

Turning to capital expenditures, we spent approximately $95 million to bring 12 net wells to sales in the quarter.

Our 2019 capital budget ranges -- range of $250 million to $260 million, provides for 26 to 27 net wells to be drilled compared to 33 net wells in 2018, approximately 85% of our budget is allocated towards drilling and completion capital.

Looking out into the first quarter, we're guiding for production of 210 to 217 MMcfe per day. For full year 2019, the capital budget provides for average production of 225 to 239 MMcfe per day. Our corporate presentation includes updated first quarter and full year 2019 guidance so please refer to it for our latest expectations.

Turning to our balance sheet, we had $195 million outstanding under our revolving credit facility at the end of the quarter and our liquidity position was approximately $217 million.

We expect to fully fund our 2019 capital program with cash generated from operations and borrowings on our credit facility. At the end of the fourth quarter, we were on full compliance with all our financial covenants and had significant headroom.

And with that, I'll turn it over to Sean to wrap up our prepared remarks.

Thanks, Gleeson. So to summarize, 2018 proved to be another exceptional year for SilverBow. We pursued a more active drilling program, completed more wells than originally planned and continued to optimize our frac designs. We drilled in all areas of our portfolio, and more recently, shifted our activity to more liquid storage, higher-working interest wells.

For the year, we saw production increase 20%, reserves grew 31%, operating expenses on a per unit basis declined 33% while our adjusted EBITDA went up 38%.

As we think about 2019, we're focused on becoming cash flow positive while still producing meaningful annual production growth from a balance of liquids and gas opportunities. Our goal of superior well results and effective cost control remains.

While we have developed a drilling inventory with a substantial number of locations that deliver attractive rate of returns, we are continuously working to high grade this opportunity set.

Our operational efficiency and capital discipline translate into greater value for our company and our shareholders. Along with a clean balance sheet with ample liquidity and a veteran operating team, we are well positioned to drill wells with attractive rate of returns and maximize our margins.

And at this point, I will turn it back to the operator for the Q&A portion of the call.

(Operator Instructions) And we have a question from the line of Ron Mills from Johnson Rice.

First question would be on the 2019 budget and the move to free cash flow by year-end this year plus maybe even a year ahead of what I had thought. You talked a little bit about the way you developed the program, the trade-off between growth and free cash flow, and the way you approach it from a leverage profile standpoint.

Yes. Thanks, Ron. This is Sean. I'll take your question. Yes, really it was driven by the 3 key drivers, and you kind of outlined those in your question. We considered production growth (inaudible) to a free cash flow position as well as maintaining flexibility on our balance sheet. So we said, the growth potential of our assets, we looked at a 1-rig program versus a 2-rig program. Year-over-year, our 1-rig program, as we stated, it's going to grow our production by about 25%, which we think really is strong amongst our peers. With 2 rigs, we probably would have seen growth north of 40%, close to 50% year-over-year. But in doing so, we would have been in a negative cash flow position and just felt it wasn't the right decision in light of the dynamic commodity prices, both on the gas and oil side to push that hard. And we thought that it was more important to demonstrate the ability to be disciplined around our balance sheet, get to a cash flow positive position while still leaving us a lot of flexibility in our balance sheet, really for 2 reasons: 1, we think that now is a good time to be looking to buy assets and to expand our liquids portfolio. So we wanted to be in a position to be proactive on that front, and we have both aggressive leasing and acquisition program underway to look to expand our liquids portfolio in the Eagle Ford. As well as we wanted to maintain flexibility if product prices dictated both on either the oil or the gas side to ramp up back up activity, and really be focused around if the returns are justified to expand our activity base. So those are the 3 key drivers that really drove and shaped our decision for our 2019 budget.

And just a follow-up on that one. Then the follow on -- look at that, when you think then about moving to a 1-rig program, is it fair to assume then as we think about exiting 2019 into 2020, does that 1-rig program, if you stated that level, then allow you to kind of keep production flat at kind of a fourth quarter exit rate? And then, therefore, your free cash flow in 2020 probably even grows beyond the -- the year-end 2019? Is that the fair way to look at it?

Yes, it is. Our strategy all along has been a strategy of growth and returns. So as a small cap, we want to still be able to demonstrate growth but strong returns. And so as we look into 2020, we haven't provided guidance around that but would give an indication that at a 1-rig program that we can still demonstrate growth, albeit probably not at the 25% level that we're going to see this year at a more moderate level. And then like I mentioned, that we want to be flexible that if returns justify it, we'll ramp back up activity to flex that growth if the commodity price is justified.

Okay, great. Then the second direction I wanted to go was, you mentioned leasing and bolt-ons and pursuing bigger acquisitions. And it seems like the clear focus is to expand on the liquid side and kind of have both legs to that stool. Can you talk about the state of that A&D market? What was it like last fall? Were you looking at a number of transactions before the price dislocation? And I don't remember a lot of deals transacting, but once prices stabilize for a little bit more time, do you think that opportunity set kind of represents itself again as we move through this year?

Yes, yes. As we think about what the opportunity we have in front of us, the Eagle Ford presents somewhat of a unique investment opportunity in that it provides the ability to drill either in the liquids window or the gas window, depending upon commodity prices, which is fairly unique relative to a lot of the other basins in the country that are dominated by 1 commodity or another. We also think that demonstrating for the low-cost operator in the basin sets us up well for acquisitions. So we are definitely focused on the opportunity set. We think it will set up a competitive investment decision relative to other basins and other peers that are focused solely on liquids.

Now turning to what's the current state of the market, you're right that the dynamic swing in oil prices has really cooled probably transactions. We were very active leading into the fourth quarter drop on deals. We were unable to get any transactions closed, I would tell you, the deals were out there really do never transact either. So but we think going forward as the market stabilize, as other companies look at their asset base that they'll have to -- we think that there'll be opportunities to acquire assets and we think it will be a favorable acquisition cost. We're really focused around full cycle returns and another reason why we really like the Eagle Ford, you're not paying astronomical upfront cost to acquire our inventory. So unlike other basins where prices get pretty high, and we think a road full of cycle returns -- we think, in the Eagle Ford, we're going to have strong full cycle returns.

(Operator Instructions) Your next question comes from the line of Jeff Grampp with Northland Capital.

I was hoping to get some -- a little bit more background on the updated inventory and type curves that you guys laid out. Can you talk a little bit about spacing assumptions that support that inventory and may be any differences you might be looking at if you're -- had some parent well stay on a lease versus may be an undeveloped tract if that's any different or is it generically -- are you guys approaching spacing more or less similarly, I guess, at least within a given operating area?

Yes, Jeff, this is Steve. Thank you for the question. Our spacing is pretty much, right now, unchanged from where we've been year-over-year. In our gas area, as you know, we are -- at the Webb County side, we're well developed and have long legs there and continuing to see what further opportunities we have in the Upper Eagle Ford. Over in the other part of the Southern Eagle Ford gas, we're still largely in apparent lifestyle there, so ample spacing. And then over on the liquid side, even as we've added in the McMullen area this time around, we have infill opportunities there where we're properly spaced from a prior life and older generations. So yes, we give credence to the liquids and we have a different spacing pattern there than we do with the deep gas. But right now, we've been able to successfully develop both PUDs from either side as well as delineation again in the gas.

All right. Great. Very helpful. Curious if you guys are thinking about in '19 or maybe more in the 2020 and beyond time frame, but any interest across the asset base in doing some of these, I guess, more appraisal type of projects like refracs, EUR, Austin Chalk, any types of those types of projects that you think might borrow some appraisal capital in '19?

Probably not in '19, Jeff, but we do have a projects like that identified and let me kind of give a little bit more color on it. In the -- and obviously, in the deep gas, we're dealing with incredible thickness there, so we're being very prudent on how we develop that from the base coming up. And then over on the oil side, or the liquid side, we do have opportunities in other benches there just other than the Eagle Ford, but right now, we've had a great insight and early success in what we're calling infill, but it's from generations of fracs that were in the 2014, 2015, so it's leaving us headway both in the infill development area as well as some stacked staggered potential that had never been accomplished before. So we're looking very forward to what we have in the liquid side and continuing that density.

Okay, understood. And last one for me and maybe for Gleeson. Do you have a sense of on the CapEx budget how maybe that splits first half versus second half just kind of given the dynamics of the rig dropping? And I guess just trying to get a sense of may be what a 1-rig program caught you guys over a full year.

Yes, good question. It's going to be a little bit lumpy. It's probably 60-40 first half of the year versus back half of the year. And we're probably even -- within that first half you're getting more in the second quarter just because the way kind of our scheduling of out our frac fleet went and all that, we're going to bring, as I think, Steve mentioned, about 3 to 5 net wells sales in Q1, but kind of double or triple that number in Q2. So I think overall, 60-40 first half and then more of that in the first half weighted to the Q2. And then once you get in the second half, the 1-rig program, again, that kind of lumpiness of completing wells in the second rig, it gets much more stable going forward. So I think you won't see so much lumpiness Q3, 4 and then thereafter as long as we run a 1-rig program. That answer your question?

Got it. Yes. No, that's perfect.

(Operator Instructions) Your next question comes from the line of Neal Dingmann with SunTrust.

My first question, just you laid out a plan, I guess, Sean, for you or you or Gleeson, just basically the flexibility around the plan. I know you mentioned there about going to 1 rig in 2Q and then potentially pick 1 up later. Your thoughts about what could alter those plans. Is it just pricing or if there really is anything that could change that?

Yes, as we think about the drivers on our returns, fracking is by far the biggest driver. So what's nice is, we can take advantage of strong move in gas price up, that would alter probably adding the rig into our gas portfolio or vice versa. On the oil side, we saw oil probably sustain above $60 that would give us opportunities to generate the returns to drop in a second ring and still feel comfortable about our balance sheet. So really price drives it. However, we are very focused on driving down costs. We're going to drill another 5 wells in our deep gas area with a primary focus on those wells to drive down cost lower, we think that we've really tested a wide range of stimulation designs there. I didn't really want to optimize that this year, so we could get that combination in that part of our asset base to take advantage of maybe some price movement upwards and combined with lower CapEx cost per well to move up to the second rig. So those would be the -- really price and CapEx side are drivers of our decision to move to a second rig.

Okay, and then one just last follow-up. I know you've talked about this in the past, but I think looking at Slide 14, just on the portfolio, you guys still, to me, seem a bit -- maybe I'm too conservative, but versus some others that are drilling certainly tighter than you all in a number of the areas out there, not to name any areas specifically, just when you look at your total, I think you've got 677 identified gross undrilled locations. Sean, how you think about that? Is there still potential just with the existing portfolio to expand? Or are you pretty comfortable now with the way that you're -- you've got these sort of set?

No. I do think that we have more runway in our existing asset base in terms of adding drilling locations primarily around stacked pay opportunities in our Southern Eagle Ford gas area, we've really been focused on just 1 bench within the Lower Eagle Ford, and that area has some of the thickest Eagle Ford in the basin. So I think over time, we'll probably be able to come up, prove up on another maybe 1 to 3 benches in the Eagle Ford. And then at some point, when you want to think about testing the Austin Chalk on our asset base as well. So those numbers aren't really captured in our inventory count, so we do think that with the 100,000 acre position we have, we have a tremendous amount of resource in place that should give us plenty of runway long term.

(Operator Instructions) We have a question from the line of Ron Mills from Johnson Rice.

Just one follow-up on the -- when you show your slides, and it's the individual well results versus type curves. Over the course of '18, you saw a dramatic improvement with virtually all the wells now coming on -- or production should be coming in above type curve. Steve, if you had to think about what the biggest changes were, can you weight them between the move to slickwater versus the higher proppant and fluid? Or do you think they're kind of equally weighted and especially as you look towards the liquids area, whether it be in the condensate or in the McMullen area, do you think those concepts can be applied there as well?

Yes, thank you, Ron. Kind of breaking you down as you look across our portfolio. On the gas side, we've seen strong appreciations, both in IP and EUR from increased job size and predominantly slickwater fracs. We've kind of pushed the limit in frac there, and we think that we're kind of honing in on a possible late-inning optimization even though we're still early in the life of some of those plays.

Over on the oil side, we're seeing similar, let me just put this way, it's not the same volume of sand per job, but it's certainly far increased where we were year-over-year, and clearly from prior generations. In those opportunities, we're being very selective and to where we have the spacing opportunity that fits more of a slickwater combination hybrid design, we employ that. Where we get into a little bit higher density, we employ a hybrid-type fluid system, more of a frac-pack design as it relates to both the combination of sand and fluid. So we're being very selective of it as we go across our portfolio, but to succinctly answer it, size matters and the type of fluid matters. So once again, to reiterate, in the gas, the bigger jobs with slickwater than favorable. And on the more liquid side, it's been an increased job size but a very selective as to what that is and using a hybrid.

Okay, great. And then just, Sean, from a acreage standpoint, you're only going to drill 2 wells -- 2 additional wells, bring them on in McMullen, but you seem to have a decent inventory there. What would potentially drive you to ramp activity there? Is it continued production history? Or is it a matter of still wanting to try to build out a footprint in that area? And that's all I have.

Yes, yes. Thanks, Ron. This is Sean. A lot of the thoughts that we have in, or considering in McMullen oil area. First, it's an area that the company hadn't been active in for a number of years. As our team studied it in 2018, we looked at it and felt like many of the historical wells were drilled out zone and were understimulated. So we did drill some test wells in the fourth quarter and brought them on, and we're looking to kind of see how those wells hold in there over time. Right now they're performing quite well, so we think we've proven up the theory that there's some bypassed oil there by inefficient historical wells. In the longer history we get from the well that we brought online, we'll then probably look to expand our asset -- or expand our drilling program there. But at the same time, we have been adding acreage in the area. We've done some small bolt-on transactions late last year, early part of this year, and we're finding some leasing opportunities as well. So the combination of longer production history with expansion of our inventory there through leasing and acquisitions will probably dictate an increase in activity there in the future.

There are no questions at this time.

Okay, Lonnie. Thank you. I think, at this point, we can conclude the call and appreciate everyone's interest in the company and participating in the call with us. And we look forward to reporting out our first quarter results here in early May. Thank you.

This does conclude today's conference call. You may now disconnect.