SilverBow Resources, Inc. (NYSE:SBOW) Q1 2018 Earnings Conference Call May 9, 2018 11:00 AM ET
Doug Atkinson - Senior Manager of Finance and Investor Relations
Sean Woolverton - Chief Executive Officer
Steve Adam - Chief Operating Officer
Gleeson Van Riet - Chief Financial Officer
Ron Mills - Johnson Rice
Neal Dingman - SunTrust Robinson Humphrey
Ben Wyatt - Stephens Inc
Good morning. My name is Sonya, and I will be your conference operator today. At this time, I would like to welcome everyone to The SilverBow Resources First Quarter 2018 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session [Operator Instructions]. Thank you.
Mr. Doug Atkinson, Senior Manager of Finance and IR, you may begin your conference.
Thank you, Sonya, 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 on to our Web site, 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 risk 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 Web site.
And with that, I'll turn the call over to Sean.
Thank you, Doug. And thank you everyone for joining our call this morning. We are pleased to report another solid quarter and a great start to 2018. Our financial and operational results demonstrate our consistent ability to execute across our portfolio. Our program in Fasken, combined with our strong performance and flatter production profiles from our wells in our Southern Eagle Ford gas position, contributed to production levels that came in at the high end of our guidance.
On the cost side, we continue to find ways to lower our cost structure, while improving upon our safety metrics, which is a testament to the team we have in place. Our huge focus on cost provided for lease operating expenses of $0.34 per Mcfe in the quarter, which compares favorably to a year ago levels of $0.47 into our guidance. So in just over a one year period, we will have reduced our LOE by over 30% on a per unit basis. We are well on our way to achieving our stated goal of becoming the low cost operator in the basin.
Turning to our capital program. With two rigs now drilling, we expect to enter the back half of the year prying for growth. Our drilling program for the year is built around strategic delineation and appraisal. We have one rig focusing on our shallower assets in Fasken and Artesia, while do the rig is customized specifically for the deeper Southern Eagle Ford gas window. With a dozen wells in our Southern Eagle Ford gas blocks in LaSalle, McMullen and Live Oak Counties where we have assembled over 55,000 acres.
On the completion side, we are testing advanced stimulation designs with multiple ranges of sizes and volumes throughout all areas of our portfolio, as well as testing different choke management concepts, honing in on what pressure management regimes work best in each area. Finally, on the leasing front, as you know, we were a fast mover in the basin in pursuing the gas fairway in 2017, adding approximately 35,000 acres to the portfolio. We believe our early actions in the play positioned us with some of the best acreage that was available from a leasing standpoint.
While the landscape in the basin has become more competitive with more companies entering the play and lease bonuses increasing, we believe there remain ample opportunities for us to add to our portfolio, whether it’d be from a leasing or an M&A standpoint. We will continue to evaluate any opportunities that crosses our desk with a disciplined focus on full cycle returns.
So I will close by saying that we are off to a great start in 2018. The Company is well-positioned and poised for significant growth in the back half of the year as we realize the benefits and production and scale from the addition of the second rig.
And with that, I will hand it over to Steve.
Thank you, Sean. Moving onto our operational results for the first quarter. Production of 161 million cubic feet of gas equivalent per day in the quarter was driven by strong performance from new wells in Fasken and shallower declines from our base production. These shallower declines reflect our managed pressure initiative.
Moving on to cost. We are evaluating and optimizing all of our unit costs, processes and procedures for our operating and supply chain functions. Moving forward, our granular focuses on de-bundling and selective aggregation of services along the value chain for both CapEx and OpEx spends. We are already starting to see this impact on our bottom line and lease operating expenses. We expect our lease operating expenses to decline throughout 2018 due to our AWP Olmos divestiture and continued cost discipline combined with the growth in production associated with our second rig.
The second rig provides additional scale, which we are leveraging to selectively procure goods and services directly from service companies and manufacturers. Specifically, we have secured a dedicated time slots with select vendors, such as pumping services, which greatly enhanced our ability to control the quality and timing of our operations.
We have been monitoring the potential for service cost inflation due to increasing in oil price. As such, we expect to offset any potential cost inflation in 2018 with improved operating efficiencies. Our keys to success this year will include refinements in bid selections, vendor performances and rigorous commercial management of our drilling, completion and production services.
Turning back to the first quarter, as mentioned earlier, we completed a six well pad in Fasken, which by the way was the largest pad in the Company's history. The results from this pad demonstrate the deliverability from our Fasken asset. This pad delivered an average rate of approximately 65 million a day over its first month of production. Three of the wells were in the Upper Eagle Ford, and completed with an average of 1,500 pounds of proppant per lateral foot and tighter stage space. We believe this completion design change is increasing well performance as these Upper Eagle Ford wells each average 10 million a day for the first month.
Going forward, our plan is to optimize further by keeping tighter stage spacing and increasing sand volumes to 2,500 pounds per foot. We also plan to test a different fluid system, moving from a hybrid design to slick water. Average well cost for that pad came in under the Company’s $5 million type curve estimate. We took our learnings from this six well pad and immediately drilled another six well pad in Fasken using the recently contracted high tech rig. Drilling these large pads are beneficial for both us and the service companies as they provide the consistencies and efficiencies to meet our goals.
Developing stack pay at Fasken, including Austin Chalk potential, is a significant opportunity for us since we can leverage the existing infrastructure for further economic upside. Testing additional zones is our lowest cost method for growing our inventory. As such, we are now planning more upper Eagle Ford development at Fasken due to the encouraging early results in productivity and stimulation.
As Sean mentioned, our customized rig, which is dedicated to our deeper higher pressured Southern Eagle Ford gas area, spud four wells in the quarter, including two in Oro Grande and two in AWP. The wells in Oro Grande were both pumped with approximately 3,700 pounds of proppant per foot of lateral with some stages testing up to 4,500 pound. These wells were brought online in late April, and we will have more to report during our second quarter call.
This same rig is currently finishing up in AWP and will soon be moving over Uno Mas. At Oro Grande and Uno Mas, we have been able to confirm significant section thickness in the lower Eagle Ford, including other targets across the entire Eagle Ford section. These thicknesses potentially warrant additional landing zones, which are currently being evaluated.
Our challenge going forward is to appraise and successfully delineate the sweet spots across these multiple intervals. We are currently evaluating our completion designs, including fluids, stage facings, proppant loading and other value driven intensities for our wells in Oro Grande, AWP and Uno Mas. We continue to focus on stimulation designs that further optimize and effectively treat near wellbore rock as opposed to reaching out with overly long frac length. Specific to choke management, we are testing our pressure management techniques across our portfolio.
We believe our two Bracken wells, completed in 2017, are delivering higher recovery efficiencies and enhanced returns, because of our pressure management initiative for that area. We expect to see similar results from our wells in Oro Grande completed under the same program. This said, we are also implying various choke management practices to all of our wells to better assess values and recoveries from these methods.
With that, I’ll turn it over to Gleeson.
Gleeson Van Riet
Thanks Steve. As mentioned, production for the quarter averaged approximately 161 million cubic feet of gas equivalent per day, which represents a slight decrease from the fourth quarter. This decrease reflects a series of one-time events, including a change in number of first deliveries, frac interference mitigation and the impact from the sale of our AWP Olmos properties.
Looking out into second quarter of 2018, we’re guiding for production to rebound up to 158 to 164 Mcfe per day, and then accelerate further in the back half of the year as we start delivering completed wells from our second rig. First quarter revenue was $52.8 million with natural gas representing 82% of production and 68% of our revenues.
You will see some disclosure in our 10-Q describing our adoption of the new ASC 606 revenue recognition standard that all U.S public companies are required to follow starting January 1 of this year. Historically, we recorded all revenue for process gas and NGLs at gross value, and recorded related processing and transportation fees as an expense. After evaluating our existing T&P contracts, we have determined that our historical method of accounting is consistent with those new standard. As such, we have not changed our method of accounting for oil and gas sale and expenses.
During the quarter, our realized pricing was 100% of NYMEX natural gas, 103% of NYMEX WTI oil and 36% of NYMEX WTI per NGLs. While oil prices have recently rallied, NGL realizations have lagged so we’re now getting to 31% to 34% NGL realizations for the second quarter. Our hedging gain on settled contracts for the quarter was approximately $735,000. We continue to be active with our hedging program, and now have approximately 65% of our production hedge for the balance of 2018 based on the midpoint of our guidance. In addition, we recently received approval from our lenders to enable us to hedge our LOE and gas differentials. So we started locking in at favorable pricing dynamics are producing it.
Turning to cost, lease operating expenses was $0.34 per Mcfe, which was down 28% compared to Q1, 2017 and flat compared to fourth quarter levels. For the second quarter of 2018, we’re expecting LOE expense of $0.30 to $0.32 per Mcfe. We’re achieving those lower operating costs for efficiencies in the Eagle Ford, and also through the divestiture of higher cost Olmos assets. As a reminder, the AWP Olmos divestiture closed on March 1st for $27 million in cash proceeds after prior period adjustments and direct selling expense. As a result, January and February revenues and LOE associated with those wells are included in our first quarter results. The second quarter will represent the first clean quarter without the AWP Olmos assets, and is more representative of our current cost structure.
We expect continued improvement LOE on a per unit basis as we step up our production in the back half of the year. Transportation and processing costs for the first quarter was $0.35 per Mcfe. Adding our LOE and T&P together, we have a total OpEx of $0.69, which we believe compares favorably to our peers. Production taxes were 5.7% of oil and gas revenues for the first quarters, which was an increase compared to fourth quarter levels due to an increase in our estimates for 2018 ad valorem taxes. Specifically, Texas ad valorem taxes are based on the value of our developed reserves, which increased significantly during 2017.
Additionally, fourth quarter 2017 levels benefited from several one-time credits. Cash G&A of $4.2 million compared favorably to guidance and fourth quarter levels of $5 million. In total, strong production and continued cost focus results in adjusted EBITDA of $36.1 million in the quarter. Cash interest expense was $5.2 million for the quarter, an increase driven by full quarter of interest expense associated with our second lien notes, which were issued on December 15, 2017.
Turning to capital expenditures. We spend approximately $45 million on CapEx in the quarter, representing 18% of our annual budget. Capital expenditures are expected to increase in second to reflect a full quarter drilling activity associated with two rigs and increased completions. However, several completions will not turn to sales until the third quarter, given the timing and nature of pad drilling. As such, our 2018 production growth is expected to be back end weighted.
In addition to our quarterly CapEx, we’ve spent $6.1 million in cash associated with the sale of our Bay De Chene plugging and abandonment liability, a deal we signed back in December for $16.2 million. The remaining total liability now stands at $10.2 million of which $6.4 million is classified as current liability and $3.8 million is classified as a long-term liability.
This transaction removed $20.9 million in ARO from our books while the AWP Olmos divestiture removed another $6.3 million. Combined, these transactions reduced our after term in obligations to $4.7 million in total. We reiterated our prior capital expenditures and production guidance for the full year 2018. Additionally, we provided the second quarter 2018 guidance in our corporate presentation, so please refer to it for our latest expectations.
Our liquidity as of March 31st was approximately $274 million. As previously announced, we reaffirmed our borrowing base to $330 million during the spring redetermination. We view the spring 2018 redetermination a favorable outcome given our AWP Olmos divestiture and challenging gas price backdrop. Our strong liquidity and solid balance sheet are a testament to our entire team’s efforts, and I’d like to thank our bank syndicate for their continued support.
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 first quarter, we’re in full compliance with all of financial covenants, and have significant headroom.
And with that, I’ll turn it over to Sean to wrap up our prepared comments.
Thanks, Gleeson. So to summarize, the first quarter was a great start as we have positioned ourselves with a lot of momentum heading into the back half of ’18 when we expect to realize the full benefits of scale and the associated production response from our second rig. As we think about 2018 and beyond, our goal is to still grow production by drilling wells with attractive rates of return and maximizing our margins by leveraging our low operating costs.
We continue to focus on driving operational efficiencies and operating with a pure leading cost structure. We have developed a robust drilling inventory with a substantial number of locations that deliver attractive rate of returns, and we are continuously working to high grade this opportunity set. Along with a clean balance sheet that has strong liquidity and a certain operating team, we are well positioned for strong growth over the coming years.
And with that, I’ll turn it back to the operator for the Q&A portion of the call.
Thank you [Operator Instructions]. Your first question comes from the line of Ron Mills from Johnson Rice. Your line is open.
Steve, as it relates to some of the changes, you highlighted a lot of things on the completion side in terms of tighter frac stage basing, tighter cluster spacing within those stages, and moving to test increased proppant levels and slick water. So could you just provide a little bit of a backdrop in terms of -- from your first iteration of Upper Eagle Ford wells to the second iteration, which are on track for the your 10 bcf curve, and what you expect some of those tweaks to do going forward, particularly in that Fasken area?
We have a lot of experience from the lower Eagle Ford and we initially described some of those earlier general Eagle Ford opportunities in the Upper Eagle front, and try to basically rapidly optimize. What we’ve done in the meantime though is seeing that there is some character difference between the two. So we've gone ahead and have done some modeling and forecasting, whereby we can see proppant loading increasing upwards of around 2,000 to 2,500, and also some additional changes to our fluid design even along the lines of more fluid versus less that appear to have a strong correlation to improved productivity, not to mention tightening of the stages.
Clusters may still be a little bit of a jury outstanding. But clearly tightening up the stages and deepen up the proppant to fluid looks to be a more representative frac design for the rock characteristic in the Upper Eagle first. And we have a clear pathway forward to seeing that that’s going to generate the EURs and returns we’re looking for.
And looking at the presentation when I look at the most recent wells in the upper Eagle Ford, as mentioned clearly tracking that 10 Bcf curve, the upcoming test. What increased level of intensity do you expect to test on the completion side as you work through that project?
We’re going to go ahead and test moving more from a hybrid to a slick water. We’re also going to test going more from a 300 plus stage spacing to 200, 200 minus, and likely cluster somewhere in that 17 to 25 foot range. And proppant loadings, like I say, pushing more towards 2,500 to a foot as we overall disperse the two type of proppant we plan on using.
And then on the choke management side, I guess the presentation shows that some of which you’ve practiced differential management. But when you look at the internal data, what has that accomplished in terms of the production profiles, is that partly what's driving the shallower base decline that helped lead to such production in the first quarter?
The choke management that we have applied, there has been some historical information here that was based on early cleanup, and then going through our managed pressure choke, and that has a lot of merit. We've taken out and refined it further with data from the Haynesville and the deeper part of the Utica. And with that, now we’ve come into a practice where we have a strong early cleanup and then we work a very conservative choke setting that takes us to somewhat of a peak pressure. And then from there, we have some proprietary data that gives us some knowing differentials by whereby we can change our chokes to maximize our production.
So as the short answer to that Ron, is we had historical learnings that we tweaked from current day deep gas practices elsewhere, as well as some tests that we have done. And now we get into a -- where we cleanup the well and we go to a managed choke regime that provides -- improve both IP and the EUR.
And on well spacing, where are you currently drilling your wells given the focus on parent-child relationships over the past few months. Are you seeing any such impacts, whether it’d be both from an aerial stand or as you test upper and lower, any vertical impacts?
In our legacy asset in the Fasken area, both upper and lower, were on about 660 spacing there, roughly 115 acres. And in our more resource oriented areas, we’re somewhere in that 880, 160 acre type spacing. And what we’re seeing, Ron, is in the legacy assets the interference we’re seeing there in play, and the in-play interference has been about similar to what other people are seeing in the Eagle Ford. However, we’re highly developed in the lower Eagle Ford already. And in the upper, as you compare our gas assets to other parts of the Eagle Ford to the North, we’re not seeing the type of interference on the vertical side that’s being experienced elsewhere. That’s on the more legacy side.
So again summarizing on the legacy side; in-playing not as much as to the north and vertically very little; over on the resource side of our basin where you’re looking at Oro Grande and Uno Mas, we don’t have near the wells test in there and we have very fixed sections. And so where we’re dealing in the lower, we haven’t seen any in-playing even when we drill well side-by-side. And of course, we’re not in the stack part of the development yet to know the vertical. But we’re not concerned about that in the near future, and we clearly feel very comfortable about planning around it in the far future.
And then one last one, you talked about having dedicated frac slots. Sean, from your -- or maybe Steve, from your standpoint, with two rigs running. At some point, would you potentially consider adding a dedicated frac spread or how do you think you develop that as we think about the rest of this year and even moving into next? Thanks.
And we’ve given that considerable thought over the past couple of months. And we do have that in our plan as an option and we’ve been dealing with our service provider for that as an option, both in the near-term as well as going into 2019. So right now with some of the advances that we’ve been able to make on the drilling side, it’s that opportunity and so we’ve just opened up those discussions with our service provider, and they’re positive at the present time.
Your next question comes from the line of Neal Dingman of SunTrust. Your line is open.
Probably just the first quarter I had, guys can you talk a nit about, I noticed on some of your wells, you’ve had, I guess number one on the Fasken, talk about -- looks like you had a bit of delivery constraint. I know we’ve talked about that. I am wondering how long that will go? And then tying into that, I know on some of your Eagle Ford gas Oro Grande, Uno Mas and AWP, you’ve been pretty conservative about the choke management, and if you can talk about those two? Thanks.
At Fasken, as you know, we have a volume constraint there based on our deliveries in the Howard. And so we’re very mindful on how we develop and spend our capital there. So that we’re always in a position to deliver to that, and when possible, deliver over but certainly always be in a position to where we’re not overspending in terms of our deliverability in that area. So that goes hand-in-hand with both our development and how we choke the wells there in both a high pressure medium and low pressure system.
Taking that over to Oro Grande in terms -- and Uno Mas in terms of our choke management, we’re very committed there to cleaning up the wells. There all perf and plug completions. And as we increase the stages, we’re doing it both with disposable and cleanout opportunities. So we're very committed to cleaning up those wells in the early part of our choke regime. And then from there, we take a hybrid approach from what we've done historically, as well as what the other deep basins. And then we conservatively work the chokes to optimize a three way thing that we're currently internalizing between IP, EUR and a three year plus [MTB].
And then just lastly, it looks likes to staying with us same southern Eagle Ford gas area. It looks like some of these wells, a number of them in fact have been outperforming your type curve. Just your thoughts on current type curve versus potentially boosting those a bit?
We put several type curves out there ranging from Oro Grande through AWP over to Uno Mas with the range of 10 to 14 Bcf. We’re finding that we’re seeing wells perform within that range still early that we brought half dozen wells on. I think as we get through this year and get another dozen wells, given that 20 wells across that large acreage block, we’ll be able to start honing in on the type curve may even move towards fewer type curves as we get better understanding of the rock. So right now, we’re not ready to revise upwards or downwards kind of staying the course for that.
Your next question is from the line of Jeff Grampp from Northland Capital. Your line is now open.
Operator, why don’t we move to next caller in the queue?
Certainly. Your next question comes from the line of Ben Wyatt from Stephens. Your line is open.
One just question maybe I wanted to ask on maybe the drilling base side of the D&C conversations we always have. If we only think about drill days, you guys getting, call it two wells per month on the asset. What did that look like -- what did the drill days look like on the six well pad that you guys did? And then with the new high spec rig that you guys have, should we expect that to improve even more? Thanks.
Well, we were referring to two wells per month there in our legacy asset, Fasken both upper and lower. In the lower, we've now been able to advance that to 2.5 wells per month and in the upper, we had been lagging on that. But just recently, we were able to identify through some petrophysical work some sweet spots that greatly aided our penetration rates. So now in the upper, we’re going from 2 to 2.5 as well. We’re just like two plus in the upper at the present time and likely to see 2.5 there to.
So we’ve made high quality ROP improvements in both levels of that legacy asset, and they all look to be repeatable. The other thing as it relates to what is the rig doing for us, that particular rig is without getting into too many details is one of your typical flex threes 1,500 system with three pumps, and the mass capability of doing that work and sometimes even deeper. But what’s of interest, it’s one of their new super specs that just hit the market. So it’s not a rail rig, it is a full articulating walking rigs.
So what that gives us the latitude now in Fasken where we didn’t have before is the big pumps, the big pressure and the ability to walk both two and fro as well as side by side on these multi-well pads. And we generally are able to tell historically since now that we’re doing multi-well pads in that area as we’re giving those added drilling efficiencies. So it’s hand-in-hand. The mobility and the flexibility of the rig is clearly generating faster penetration rate, not only in terms of the technical sub-surface part but also well to well.
And then maybe just along those lines, starting to see some improvement though, but maybe Gleeson on your side. Should we think of the year ducts is unchanged or if you guys feel better about that, you’ll just update us a little later on maybe completions and what the ducts look like at year-end?
Gleeson Van Riet
Yes, your question around year-end ducts?
Yes, I’m assuming there is no change now. But obviously, if the drill days continue to improve that improves and you guys will just update as you have more confidence around that?
Gleeson Van Riet
I think that’s fair. I think in our next call will be second quarter will be early August so by then we’ll be able to, if we have any change, we’ll be able to give you guidance at that stage.
[Operator Instructions] There are no further questions at this time. This concludes today’s conference. You may now disconnect.