SilverBow Resources, Inc. (NYSE:SBOW) Q2 2018 Earnings Conference Call August 8, 2018 11:00 AM ET
Matthew Brown - IR
Sean Woolverton - CEO & Director
Steven Adam - EVP & COO
Gerald Gleeson - EVP & CFO
Jeffrey Grampp - Northland Capital Markets
Duncan McIntosh - SunTrust
Neal Dingmann - SunTrust Robinson Humphrey
Good morning. My name is Bella, and I will be your conference operator today. At this time, I would like to welcome everyone to the SilverBow Resources Second Quarter 2018 Earnings Conference. [Operator Instructions]. Thank you. Matt Brown, you may begin your conference.
Thank you, Bella, and good morning, everyone. Thank you very much for joining us. Joining me on the call today are Sean Woolverton, our CEO; Steve Adam, our COO; and Gleeson Van Riet, our CFO. We posted an updated corporate presentation onto our website, and we will occasionally refer to it during this call, so I 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'll turn the call over to Sean.
Thank you, Matt, and thank you, everyone, for joining our call this morning. Let me start by saying that in the second quarter, we delivered on guidance on all aspects. On production, we came in at 160 million cubic feet equivalent per day, giving us essentially a flat first half of the year and in line with what we indicated in our first quarter call. On cost, we came in below guidance, which reflects our efforts to optimize our portfolio and drive down our operating expenses. On the CapEx side, the first half of the year was really about increasing our scale and setting us up for a significant production ramp in the second half. Steve will go into more of the details. But I think one of the things that drives this point home is the fact that in the first half of the year, we brought online 7 net wells, whereas in the month of July alone, we have delivered 8 net wells. And we entered August producing 200 million cubic feet equivalent per day, a 25% increase over the first half average.
As we pivot to the second half growth, we're seeing a number of successes in our capital program that are driving this ramp. First, in Fasken, we're seeing strong performance from the field where we have produced over 215 million a day on a gross basis, taking advantage of available midstream capacity, and we are seeing positive results from our stacked pay program there, as 3 Upper Eagle Ford wells drilled in the first quarter are tracking above their 10 Bcf type curve.
These wells were completed with an average of 1,500 pounds of proppant per lateral foot. Given these results, we completed 3 more Upper Eagle Ford wells in the second quarter, utilizing an even larger stimulation design of 2,000 pounds. We've also begun drilling some of the first wells in the area on the acreage we acquired in 2017. We'll have more to report on those wells on the next quarter's call. No doubt Fasken is a core asset, and we continue to find ways to get even more out of this great property.
Second, in our Southern Eagle Ford block, we continued to make significant progress on testing and delineating our large resource base that now consists approximately 55,000 acres and spans from our Oro Grande block in Southern LaSalle to our Uno Mas block in Live Oak County. In our AWP acreage, we brought on two wells in July. While it's still early on in the life of those wells, they're above their type curves. On average, each well is producing 15 million a day equivalent, consisting of 9 million a day of gas, 900 barrels of NGLs and 75 barrels of oil.
At Oro Grande, the NMC 1H has been online for over 1 year and has a cumulative production of 3 Bcf. At that level, the 1H is a top 50 gas producer in the Eagle Ford, a strong result for our first well in this new area of the basin. As such, wells 2, 3 and 4 have further tested a range of stimulation designs. These wells are performing at or around 90% to 95% of their type curves, and we continue to learn and test stim designs in this area. We are currently drilling wells 5 and 6 and are applying our learnings, and we will be testing slick water designs in this area for the first time.
At Uno Mas, we drilled our second and third wells, not only did these wells come in under their AFEs on the drill side, they also improved by reducing their drilling times by 9.5 days from the first well. We are completing these wells now, and we will be bringing them online in late August. We see all these results as catalysts for second half growth. We are guiding for third quarter production of 190 million -- 195 million cubic feet a day at the midpoint, up over 25% over the first half. With our Fasken extensions coming on, our increased activity in Artesia, which adds more liquids and further delineation activity in our Southern Eagle Ford, we are targeting bringing on 13 net wells in the third quarter. The second half of the year will no doubt be a pivot point for the company. We are on track to deliver the production ramp that we have been forecasting. We continue to bring down our cost structure and optimize our well performance.
Taking into account the top line growth we were generating with the bottom line cost reductions, we see strong EBITDA growth for the company over the coming quarters. And with that, I'll hand it over to Steve.
Thank you, Sean. Moving on to our operational results for the quarter. Production was driven by continued strong performance of Upper Eagle Ford wells at Fasken, 2 Oro Grande wells and successful base production optimization projects across all assets.
As for cost, we are continuing to evaluate and optimize all of our unit costs, processes and procedures for our operating and procurement functions. For example, we are evaluating and testing regional sand as an alternative to Northern white, which should allow us to decrease overall stimulation costs while retaining and improving fracture conductivities. Admittedly, we have seen some service cost inflation due to increasing oil prices. However, we continue to offset upward pressure related to vendor prices with improved operating efficiencies and purchasing power associated with our increased activity.
Verifiably, we are already seeing this impact on our bottom line and lease operating expenses. LOE for the quarter was $0.26 per Mcfe compared to $0.36 a year ago. We expect our lease operating expenses on a unit basis to see further improvement in the back half of 2019 -- 2018 due to continued cost discipline, combined with the expected growth in production from our second rig.
Turning back to the second quarter, as mentioned earlier, we completed 2 net wells of a 6-well pad in Fasken, as well as a total of 4 net wells from Oro Grande and AWP. The most recent 3 wells completed in the Upper Eagle Ford at Fasken employed larger stimulation designs relative to the wells that were completed in the first quarter. The first quarter wells had average proppant loadings of 1,500 pounds per foot, and after 5 months, are outperforming type curves. The most recent wells were completed with proppant loadings of 2,000 pounds per foot, and early results are encouraging.
Now shifting to the Lower Eagle Ford. We continue to see consistent performance with wells producing in line with 14 Bcf type curves. We continue to look at optimizing these results and are testing upsized slick water fracs. We completed our first slick water fracs in early July at Fasken, and we are currently flowing them back. We look forward to sharing these results on our third quarter call.
The company completed the NMC 3 and 4 at our Oro Grande asset. These wells have completed lateral lengths of 6,600 feet and 6,900 feet, respectively. They were completed with hybrid frac designs of 3,700 pounds per foot, which were the largest stimulations in the company's history. When normalized for lateral length, these wells are performing at type curve. We also completed the Bracken 25 and 26 at our AWP assets and brought both of these wells to sales in July. These wells had completed lateral lengths of 6,700 feet and 9,200 feet, respectively, with the latter being the second-longest lateral in company history. They were completed with hybrid frac designs of 2,600 pounds per foot with increasing stage and cluster densities relative to previous wells. As Sean mentioned earlier, these wells are performing well above type curve. We continue to test larger sand volumes, tighter stage spacings and slick water fluid designs across our portfolio. And to focus on stimulation designs that further optimize and effectively treat near wellbore rock.
The SilverBow team is gearing up for an exciting third quarter. We expect to bring 13 net wells to sale during the third quarter, compared to 2 wells in the second quarter. With that, I'll turn it over to Gleeson.
Thanks, Steve. As mentioned, production for the quarter averaged approximately 160 million cubic feet of gas equivalent per day, which represents a slight decrease from the first quarter. Looking out into the third quarter of 2018, we're guiding for production to increase to 187 million to 204 million cubic feet equivalent per day as we start delivering completed wells from our second rig.
Second quarter revenue was $51.3 million, with natural gas representing 86% of our production and 71% of revenues. During the quarter, our realized pricing was 105% of NYMEX for natural gas, 101% of NYMEX WTI for oil, and 37% of NYMEX WTI for NGLs. While oil prices have recently rallied, NGL realizations have lagged, so we are now guiding for 33% to 36% NGL realizations for the third quarter.
Our hedging loss on settled contracts for the quarter was approximately $3.2 million. We continue to be active with our hedging program and now has approximately 70% of our production hedged for the balance of 2018 based on the midpoint of our guidance.
In addition, we've also used basis swaps to help manage our exposures to natural gas and oil basis differentials. For the balance of 2018, we have gas basis hedges of 127 million cubic feet per day at a weighted average differential of negative $0.04, which represents approximately 70% of the midpoint of our gas guidance. For 2019, we have increased our basis hedging slightly to 130 million cubic feet per day.
Turning to cost. Lease operating expense of $0.26 per Mcfe was down 28% compared to Q2 2017. As a reminder, this is our first clean quarter of LOE after accounting for our AWP Olmos divestiture, which closed March 1 of this year. For the third quarter, we're expecting LOE expense of $0.25 to $0.27 per Mcfe. We expect continued improvement in LOE on a per unit basis as we step up our production in the back half of the year.
Transportation and processing cost for the second quarter were $0.37 per Mcfe. Adding our LOE and T&P together, we have a total OpEx of $0.63 per Mcfe, which we believe compares favorably to our peers. In total, strong production and continued cost focus resulted in adjusted EBITDA of $31.3 million in the quarter.
Cash interest expense was $5.8 million in the quarter, a slight increase compared to first quarter levels due to increased borrowings on our credit facility.
Turning to capital expenditures. We spent approximately $72 million on CapEx in the quarter. As Sean mentioned, we have brought 8 net wells to sale in the month of July alone compared to 2 net wells during the entire second quarter. We reiterated our prior capital expenditures and production guidance for the full year of 2018. Additionally, we've provided third quarter 2018 guidance in our corporate presentation, so please refer to it for our latest expectations. Our liquidity as of June 30 was approximately $255 million. We expect to fully fund our 2018 capital program with cash generated from operations and borrowings on our credit facility. At the end of the second 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 comments.
Thanks, Gleeson. So to summarize, the second quarter really highlights our cost structure and the stacked pay potential of our Fasken asset. We are positioned with significant momentum heading into the back half of '18 as our completion operations accelerate significantly. As we think about 2018 and beyond, our goal is to grow production by growing wells with attractive rate of returns and maximizing our margins by leveraging our low operating cost. We continue to focus on driving operational efficiencies and operating with a competitive cost structure. We have developed a robust drilling inventory with a substantial number of locations that deliver attractive rates of return, and we are continuously working to high grade this opportunity set. Along with a clean balance sheet that has strong liquidity and a ventured operating team, we're well-positioned for strong profitable growth over the coming years. And at this point, I'll turn it back to the operator for the Q&A portion of the call.
[Operator Instructions]. Your first question comes from the line of Jeff Grampp from Northland Capital Management.
Definitely appreciate all the operational comments in the prepared remarks. That was helpful. I was curious, it sounds like you guys are doing a fair amount of slick water tests across your asset base with higher proppant. I wanted to see, is it a fair conclusion to make that, that seems to be kind of -- where you guys are kind of headed across the assets, slick water, higher proppant? And then if you can maybe give us a sense of what are kind of the give-and-takes on the cost and cycle times and how that can potentially change as well?
Yes, Jeff. This is Steve. Thank you for the question. The answer is yes. We see that as a moving trend in terms of more and more slick waters as we continue to both develop and delineate our assets. In terms of cost, we're working through those propositions now. In some cases, there's a trade-off for more costs and in other cases, there are trade-offs for optimization as we go across the different assets. And in terms of cycle times, the reeling only cycle time impact we're seeing is, as a little bit more pump time as it relates to bigger jobs per stage. And also, a little bit more cycle time as it relates to longer and longer flow backs, as it relates to pulling off all the water off of these wells.
Okay, great. That's really helpful. And then for my follow-up, given that we got another quarter, at least, of data across some of your assets, and I understand in 6 months, you'll probably know heck of a lot more about kind of the outlook of these various areas than we do today. But any kind of early indications for certain areas that may garner more capital year-over-year as we look into '19? Or should we think about '19 as still largely a kind of delineation year for your various project areas?
Yes, Jeff. This is Sean. I would say we're just starting to think about the 2019 budget that we're getting to that time of the year. At this point, I think the results we're seeing across all the areas are still encouraging. So we haven't really thought about repositioning or reallocating the capital quite yet. And we'd tell you that the allocation that we have this year is probably still a good allocation to use in modeling next year.
Your next question comes from the line of Ron Mills from SunTrust.
This is Dun MacIntosh on for Ron at Johnson Rice. Just had a couple of questions on the Upper Eagle Ford at Fasken. It sounds like you've started to do some slick water completions over there as well. Wondering what kind of uplift you're seeing relative to that? Or kind of expand a little bit about the uplift relative to type curve you've seen with that shift in completion design.
On the Upper Eagle Ford at Fasken, we are seeing a -- we're seeing a good relationship, a quality match to the type curves that we've presented. And we're also seeing an upside from there. It's still early, as you know, with the number of wells that we have in place. But we're looking to see that type curve and those upsides to type curves as we continue to develop through that property and other area properties that are similar.
Yes. I'd add a little bit to that. Slick water, we've done 1 Upper Eagle Ford slick water job there. That well's always been on for a couple of weeks. Looks very encouraging. What we're excited about in terms of the Upper Eagle Ford, the wells that we brought online earlier in the year, back in February that now have close to 4.5 months of production, they're performing about 10% above the type curve. And those wells were hybrids with 1,500 pounds per foot. We tightened up stage spacing, did a little bit more mechanical diversion on those wells. So we're going to -- what we did on this next round of wells is brought those concepts in, scaled up the sand and then switch to slick water fracs. So we're excited with the results we've seen from earlier in the year and I think we have upside from there.
Okay, great. And then also at Fasken. Wondering just on the Lower Eagle Ford, in terms of running room and kind of any completion test over there that you've been doing, or have you done anything differently in the Lower Eagle Ford? And what that's looking like at Fasken?
The Lower Eagle Ford at Fasken, as you know, we drilled up a lot of that inventory. However, we have these select spots and where we have select spots, we know there's going to be less interference and where we're crowding up against lease lines and things like that. We've gone ahead and tested some of that. And so we currently have some of our larger slick water designs in place, and we have one that we've tested just recently that we'll be able to announce in the third quarter. But I can share with you that it's very favorable and likely to be maybe one of the best wells in the area.
[Operator Instructions]. Your next question comes from the line of Neal Dingmann from SunTrust.
Sean, my first question, if you're looking at Slide 11, where you kind of laid out your portfolio. For you or Steve, your thoughts on drilling locations there, is there -- how much upside you see? I'm just -- wanting to try and get a sense of how conservative do you think you're being on that?
Yes. On the slide where we lay out our inventory, you can see -- really, we think about it in terms of a breakdown from the Western Webb County acreage where we've been -- kind of our core asset, Fasken, we've added acreage there and have captured that upside already. And then Artesia is in the Western Eagle Ford area, and we've been able to add some acreage there year this year. So adding a little bit of inventory there and we continue to look in both of those areas to bolt on acreage. A lot of running room has been -- is all -- over on the Southern Eagle Ford gas area. I think we've been conservative on our inventory there. That's -- that part of the Eagle Ford is some of the thickest, richest rock in the basin. And right now, we've modeled our inventory, really, between 660 and 880 spacing, with most of those wells all being in a single zone. So in the next, probably, year, we'll have to start thinking about some spacing tests as well as maybe some stacked lateral test in that area to demonstrate the upside of our overall position there.
Got it. And then just lastly for you or Gleeson, Sean. When you guys think about sort of internal or external growth given your financial position, your shares as currency, I'm just wondering, as you sit today, how do you sort of think about both those factors?
Neal, it's Gleeson. Sorry. So the question is whether it's lease or acquisition, how we think about financing them? Is that the question?
Exactly right. Or the need to do that today given -- based on kind of my last question, that size of inventory you already have. All that packs together, Gleeson.
Yes. So a couple of math question, but coming back, I think we're ending the quarter with $255 million of liquidity, which is a good place to be in. Leverage, I think, is kind of in good shape. Yes, we think we've got a lot of running room in our existing assets. We think there's a lot of efficiencies going into the second rig, getting almost the -- have enough activity to have a dedicated frac spread and all that. So when we think about opportunities, we've got a lot to do with existing acreage. That said, we're very full cycle returns-focused whether we can lease the right acreage or buy the right acreage, if we can do it at the right price and get the right returns on that. And there's also some benefit to kind of -- synergies of economies of scale, as we get bigger within the basin. So I think from where we are, we have a pretty active BDF that looks a lot things. I think we were pretty good at analyzing things as we've leased a lot last year, as you saw. So I think there's opportunities for us to increase our scale at attractive returns that will actually help deliver even lower cost as we kind of get more scale under our business.
[Operator Instructions]. There are no further questions at this time. Please continue.
If there's no further questions, I want to thank everyone again for joining us this morning, and we'll conclude our call.
Thank you for participating. This concludes today's conference call. You may now disconnect.