SilverBow Resources, Inc.
Q4 2018 Earnings Call Transcript

Published: 28 Feb 2019

[Operator:]

Hello, my name is Launi, 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.

[Jeff Magids:]

Thank you, Launi, 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 we'll 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.

[Sean Woolverton:]

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

[Steve Adam:]

Thank you, Sean. Moving onto our operational results. Production of 227 Mcfe per day in the fourth quarter was driven by a substantial back-end 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 six net wells during the first half of the year. During the fourth quarter, we brought online 12 net wells across our portfolio, these included three wells in our McMullen Oil area, an area where the company has been deploying more higher return capital. All three wells had 30-day IPs of 145 Boe per day per 1,000 foot of lateral. Based on results in this area, the operations team drilled two additional wells. Each well's lateral lengths exceeded 11,000 feet, with one 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. In our La Salle Condensate area, all three wells were turned to sales in the fourth quarter had 30-day IPs over 140 Boe per day per 1,000 foot of lateral with one-well greater than 175 Boe per day. In our Southern Eagle Ford gas area, we continued our successful delineation program and confirm the resource potential of our 60,000 gross acre position by turning three wells to sales, each well had 30-day IPs over 1.5 MMcfe per day per 1,000 foot of lateral. These well results validate the geological and petrophysical studies we have performed and demonstrate the potential of one of the best -- better -- 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've published yesterday. Operationally, 2018 was a transformative year for the company. On the completion side, we've moved from medium intensity exclusively gel-based frac designs. The 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 costs. Our La Salle Condensate area, in our La Salle Condensate area, we have consistently drilled wells under 10 days with some wells being drilled in less than seven days. As mentioned before, the team executed on foot 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 costs, 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 and engineering teams. We take an active approach to scheduling an 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 size set of wells coming online in the second quarter of 2019. Due to these two large well sets coming online on either side of the first quarter of this year, we will turn on approximately four 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 two rigs to one 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. Majority of our capital spend is focused on areas of high return development including our La Salle Condensate in 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 lifting costs associated with liquids 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 five 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.

[Gleeson Van Riet:]

Thanks Steve. My comments this morning, I'll highlight our fourth quarter financial results, as well as our operating costs, 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 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 with a 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. But 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 costs, lease operating expenses were $0.23 per 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 costs for the fourth quarter was $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 tax together, we achieved 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 are guiding for cash G&A of $20 million to $23 million. As Sean mentioned, our cash operating expenses including G&A sold $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 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 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 in 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.

[Sean Woolverton:]

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 liquids-rich higher working interest wells. For the year, we saw production increased 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 are 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 the clean balance sheet with ample liquidity and a ventured operating team, we're 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:]

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

[Ron Mills:]

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

[Sean Woolverton:]

This is Sean, I'll take your question. Yes, really it was driven by the three key drivers and you can outline those in your question. We considered production growth - get to a free cash flow position as well as maintaining flexibility in our balance sheet. So it's clear today the growth potential of our assets, we looked at a one-rig program versus a two-rig program, year-over-year our one-rig program as we stated is going to grow our production by about 25%, which we think really strong amongst our peers. With two-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 like 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 two reasons, one, 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 the 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 of product prices dictated both on either the oil or the gas side to ramp back up to activity and we will be focused around if the returns are justified to expand our activity base. So, those are the three key drivers that really drove and shaped our decision for our 2019 budget.

[Ron Mills:]

When you think then about moving to a one-rig program, is it fair to assume then as we think about exiting 2019 into 2020, does that one-rig program if you stayed at 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 grow as beyond the 2019 -- the year end 2019? Is that a fair way to look at it?

[Sean Woolverton:]

Yes, it is. You know, our strategy how long has been a strategy of growth and return. So as a small camp 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 indication that it a one-rig program that we can still demonstrate growth albeit probably not at the 25% level that we are 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 will ramp back up activity to flex that growth if the commodity price is justified.

[Ron Mills:]

And then the second direction I wanted to go, as you -- you mentioned leasing in bolt-ons and pursuing bigger acquisitions and it seems like the clear focus is to expand on the liquids 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? Or you're 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?

[Sean Woolverton:]

As we think about what the opportunity we have in front of us, the Eagle Ford presents somewhat of a unique investment opportunity and 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 one 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 decisions 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 in that the dynamic swing and oil prices is really cool, probably transactions, we were very active leading into the fourth quarter drop on deals, we were unable to get any transactions closed that would tell you the deals were out there really didn't never transact either. So we think going forward, as the market stabilized is up, you know, other companies look at their asset base that they'll have to -- we really think that there will be opportunities to acquire assets and we think it will be a favorable acquisition costs, we're really focused around full cycle returns and another reason why we really like the Eagle Ford is, we are not paying an astronomical upfront cost to acquire our inventory. So unlike other basins where prices get pretty high and we think it will pull cycle returns. We think in the Eagle Ford, we're going to have strong full cycle returns.

[Operator:]

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

[Jeff Grampp:]

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 -- that support that inventory and maybe any differences you might be looking at if you're -- had some parent well, say on a lease versus maybe an undeveloped track if that's any difference or is it generically are you guys approaching spacing more or less similarly, I guess, at least, within a given operating area?

[Steve Adam:]

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 -- and the Webb County side where we're well developed and long legs there and continuing to see further opportunities we have in the Upper Eagle Ford. Also 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 liquids side, even as we've added in the McMullen area this time around, we have infill opportunities there where we're properly spaced from our prior life and older generations, so, yes, we give credence to the liquids and we have a different spacing patterns there than we do in the deep gas, but right now we've been able to successfully develop both PUDs from either side as well as the delineation again in the gas.

[Jeff Grampp:]

And curious, if you guys are thinking about in '19 or maybe more in the 2020 and beyond timeframe, but any interest across the asset base and doing some of these, I guess, more appraisal type of projects like refracs, EOR, Austin Chalk, any of those types of projects that you think might garner some appraisal capital in '19?

[Steve Adam:]

Probably not in '19, Jeff, but we do have projects like that identified and let me kind of give a little bit more color on it. And 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 liquids 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 in-fill but it's -- from generations of fracs that were in the 2014, 2015. So it's leaving us headway both in the in-fill 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 liquids side and continuing that density.

[Jeff Grampp:]

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 maybe what a one-rig program costs you guys over a full year?

[Gleeson Van Riet:]

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 probably even within that first half of the year more in the second quarter just because the way kind of our scheduling of our fracs fleet went and all that we're going to bring - as Steve mentioned 3 to 5 net wells to 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. I think once we get in the second half and the one-rig program again that kind of lumpiness of completing wells in the second rig gets much more stable going forward. So I think you won't see as much lumpiness Q3 Q4 and thereafter on the long run one-rig program. Does that answer your question?

[Operator:]

[Operator Instructions] Your next question comes from the line of Neal Dingmann with SunTrust.

[Neal Dingmann:]

My first question, just you've laid out a plan, I guess, Sean for you, or Gleeson, just -- basically just the flexibility around the plan, I know you mentioned there that go into one-rig in 2Q and then potentially pick one up later, your thoughts about what could alter those plans, I mean is it just pricing or if that really is anything that could change that?

[Sean Woolverton:]

As we think about the drivers on our returns, the pricing 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, if we saw oil probably sustain above $60 and it would give us opportunities to generate the returns to drop in a second rig 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 five wells in our deep gas area with a primary focus on those wells to drive down costs lower. We think that we've really tested a wide range of stimulation designs there and 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, our drivers of -- our decision to move to second-rig.

[Neal Dingmann:]

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 not too conservative but versus some others that are drilling certainly tighter than you all in number of that areas out there, not to name any area 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?

[Sean Woolverton:]

No, I do think that we have more runway in our existing asset base in terms of adding drilling locations, primarily around stacked paid opportunities in our Southern Eagle Ford gas area, we've really been focused on just one 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 another maybe one to three benches in the Eagle Ford, and then at some point, we 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 a tremendous amount of resource in place that should give us plenty of runway long-term.

[Operator:]

[Operator Instructions] We have a question from the line of Ron Mills from Johnson Rice.

[Ron Mills:]

Just one follow-up on, when you show your slides, and that'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 -- our production history coming in above type curve. Steve, if you had to think about what the biggest changes where 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 of whether it'd be in the Condensate or in the McMullen area? Do you think those concepts can be applied there as well?

[Steve Adam:]

It's kind of breaking it down as you look across our portfolio. On the gas side, we've seen strong appreciations both in IP and EOR from increased job size and predominantly slickwater fracs. We've kind of push the limit in frac there and we think that we're kind of homing 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 it this way, it's not the same volume of sand per job, but it's certainly far increased where we were a year-over-year and clearly from prior generations. In those opportunities, we're being very selective and to where we have this spacing opportunity that's -- it's 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 frac-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 sync with your answer it size matters and the type of fluid matters. So once again to reiterate, in the gas the bigger jobs with slickwater have been favorable and on the more liquid side, it's been an increased job size, but very selective as to what that is and using a hybrid.

[Ron Mills:]

And then, Sean, from a acreage standpoint, you're only going to drill two wells -- the two 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 of footprint in that area? And that's all I have. Thanks.

[Sean Woolverton:]

You did touch on 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, it's our team study that in 2018, we looked at it and felt like many of the historical wells were drilled out of zone and were under stimulated. So we did drill some test wells in lot -- in the fourth quarter 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 are some bypassed oil there by inefficient historical wells in the longer history we get from the well that we brought online will then probably look to expand our assets or to 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 the expansion of our inventory there through leasing and acquisitions will probably dictate an increase in activity there in the future.

[Operator:]

There are no questions at this time. [Operator Instructions]

[Sean Woolverton:]

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

[Gleeson Van Riet:]

Thanks.

[Operator:]

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