SilverBow Resources Inc (SBOW) 2018 Q1 法說會逐字稿

Good morning. My name is Sonia, and I will be your conference operator today. At this time, I'd like to welcome everyone to the SilverBow Resources First Quarter 2018 Earnings Conference Call. (Operator Instructions) Thank you.

Mr. Doug Atkinson, Senior Manager of Finance and IR, you may begin your conference.

Thank you, Sonia, 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 in our website.

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 in 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 acute focus on costs provided for lease operating expenses up $0.34 per Mcfe in the quarter, which compares favorably to a year-ago levels of $0.47, and to our guidance. So in just over a one-year period, will we -- 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 2 rigs now drilling, we expect to enter the back half of the year primed for growth. Our drilling program for the year is built around strategic delineation and appraisal. We have 1 rig focusing on our shallower assets in Fasken and Artesia, while the other rig is customized specifically for the deeper southern Eagle Ford gas window. (inaudible) a dozen wells in our southern Eagle Ford gas blocks in LaSalle, McMullen and Live Oak Counties, where we've assembled over 55,000 acres.

On the completion side, we are testing advanced stimulation designs, with multiple ranges of sizes and volumes throughout all of -- 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 remained ample opportunities for us to add to our portfolio, whether it be from a leasing or an M&A standpoint. We will continue to evaluate any opportunities that crosses our desks with a disciplined focused 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 a significant growth in the back half of the year, as we realize the benefits in production and scale from the addition of a second rig.

And with that, I'll hand it over to Steve.

Thank you, Sean. Moving on to 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 reduction. These shallower declines reflect our managed pressure initiatives.

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 focus is 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 and 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 slot with select vendors, such as pumping services, which greatly enhance our ability to control the quality and timing of our operations.

We have been monitoring the potential for service cost inflation due to increasing oil prices. 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 the 6 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 spacing. 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 6 well pad and immediately drilled another 6 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 4 wells in the quarter, including 2 in Oro Grande and 2 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 pounds. 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 to Uno Mas.

In 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 spacings, proppant loadings 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 suppose -- as opposed to reaching out with overly long frac wings.

Specific to choke management, we are testing our pressure management techniques across our portfolio. We believe our 2 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 employing 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.

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 onetime 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 in the 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 our production and 68% of our revenues. You'll 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 processed 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 this new standard. As such, we have not changed our method of accounting for oil and gas sales and expenses.

During the quarter, our realized pricing was 100% of NYMEX natural gas, 103% of NYMEX WTI for oil and 36% of NYMEX WTI for 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 hedged 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 LLS and gas differentials. So we started locking in the favorable pricing dynamics of producing in Eagle Ford.

Turning to cost. Lease operating expense 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 through efficiencies in the Eagle Ford and also for the divestiture of higher cost Olmos assets. As a reminder, the AWP Olmos divestiture closed on March 1, for $27 million in cash proceeds, after prior period adjustments and direct selling expenses. 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 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 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 quarter, 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 a value of our developed reserves, which increased significantly during 2017. Additionally, fourth quarter 2017 levels benefited for several onetime 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 resulted in an 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 spent approximately $45 million on CapEx in the quarter, representing 18% of our annual budget. Capital expenditures are expected to increase in the second quarter, reflect a full quarter of drilling activity associated with 2 rigs and increased completions. However, several completions will not turn to sales until the third quarter given the timing and nature of pad drillings. As such, our 2018 production growth is expected to be back-end weighted.

In addition to our quarterly CapEx, we 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.

Our remaining total liability now stands at $10.2 million, of which $6.4 million is classified as a 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 [actual] retirement obligations to $4.7 million in total.

We reiterated our prior capital expenditures and production guidance for the full year 2018. Additionally, we provided second quarter 2018 guidance in our Corporate Presentation, but please to refer to it for our latest expectations. Our liquidity as of March 31 was approximately $274 million. As previously announced, we reaffirmed our borrowing base at $330 million during the spring redetermination. We view this spring 2018 redetermination as 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 are in full compliance with all of our financial covenants and have significant headroom.

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

Thanks, Gleason. 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 cost.

We continue to focus on driving operational efficiencies and operating with a peer 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 the clean balance sheet that has strong liquidity and a veteran 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.

(Operator Instructions) Your first question comes from the line of Ron Mills from Johnson Rice.

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 spacing, tighter cluster spacing within those stages and moving to test increased proppant levels and slickwater. 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 kind of on track for your 10 Bcf curve, and what you expect some of those tweaks to do, going forward particularly in that Fasken area?

Sure. We had a lot of experience from the Lower Eagle Ford, and we initially just tried to fold some of those, earlier general Lower Eagle Ford opportunities in the Upper Eagle Ford, and tried to basically rapidly optimize. What we've done in the meantime though, is seeing that there is some character difference between the 2, so we've gone ahead and have done some modeling and some 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 appeared to have a strong correlation to improve productivity. Not to mention tightening up the stages. Clusters might still be a little bit of a jury outstanding. But clearly, tightening up the stages and beefing up the proppant and the fluid looks to be more representative frac design for the rock characteristic in the Upper Eagle Ford. And we have a clear pathway forward, to seeing that that is going to generate the kind of 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 I mentioned, clearly tracking that 10 Bcf curve. The upcoming test, what level -- what increased level of intensity do you expect to test on the completion side as you work through that project?

Yes, 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 a 200, 200-minus. And likely, clustered 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 2 types of proppant we plan on using.

Okay. And then on the choke management side. I guess the presentation shows that some of which you've practiced different choke 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 to lead to such strong production in the first quarter?

The choke management that we have applied, there's been some historical information here that was based on early cleanup and then going to a managed pressure choke. And that has a lot of merit. We've taken that and refined it further with data from the Haynesville and the deeper part of the Utica. And with that, now we've come in to 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 known differentials by whereby we can change our chokes to maximize our production. So a 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 clean up the well and we go to a managed choke regime, that provides improved both IP and EUR.

Okay. And on well spacing, are -- 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 be both from an aerial extent or as you test upper and lower, any vertical impacts?

So on our legacy asset in the past scenario, both upper and lower, were on about a 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 plain, the in plain 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 that 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 plain, 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 well tests in there and we have very thick sections. And so where we're dealing in the lower, we haven't seen any in plain, even when we drilled wells side-by-side. And of course were not in [SAC] part of the development, to know the vertical. But we're not concerned about that in the near future, and we're -- 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 2 rigs running, at some point, would you potentially consider adding a dedicated frac spread or how do you think about that, as we think about the rest of this year and even moving into next?

Yes, Ron. 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 is going into 2019. So right now, with some of the advances that we've been able to make on the drilling side, its lent us that opportunity and so we've just opened up those discussions with our service provider and they're positive at the present time.

You're next question comes from the line of Neil Dingmann from SunTrust.

Well, just the first question I had. Guys, you talked a bit about, I noticed on some of your wells, you've had, I guess, number one, on the Fasken, talked about, you looked like you had a bit of delivery constraint. I know we've talked about that, wondering how long that will go and then sort of tying into that, I know on some of your south Eagle Ford gas, Oro Grande, Uno Mas and AWP, you've been pretty conservative on the choke management, if you could talk about those 2 things.

On the -- 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, they're 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 kind of approach from what we've done historically as well as with the other deep basins, and then we conservatively work the chokes to optimize, kind of a 3-way thing, that we're currently internalizing between IP, EUR and kind of a 3-year plus MTB.

Very good. And then just lastly. It looks like -- staying with that 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.

Neal, I'll take that one. This is Sean. We've put several type curves out there ranging from Oro Grande up through AWP over to Uno Mas with a range of 10 to 14 Bcf. We're finding that, we're seeing wells perform within that range, it's still early, that we've brought half a dozen wells on. I think, as we get through this year and get another dozen wells, giving us 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 a better understanding of the rock. So right now, we're not ready to revise upwards or downwards. We're kind of staying in the course for now.

Your next question comes from the line of Jeff Grampp from Northland Capital. You're next question comes from the line of Ben Wyatt from Stephens.

Well, one just question, maybe I wanted to ask on may be the drilling base side of the D&C conversations we always have. If we normally think about drill days, you guys get and call it 2 wells per month on the asset. What did that look like? What do the drill days look like on the 6 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?

Ben, this is Steve. I'll take that on the -- where we were referring to 2 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're able to identify through some petro-physical 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 2-plus in the upper at the present time, and likely to see 2.5 there, too. So we've made a high quality ROP improvements in both levels of that legacy asset. And they all looked to be repeatable. The other thing as it relates to what is the rig doing for us. That particular rig is a -- without getting into too many details, is one of your typical flex 3s 1,500 system with 3 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 rig. 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 to and fro as well as side-to-side on this multi-well pads. And we've generally been able to tell historically, since now that we're doing multi-well pads in that area, as we're getting those added drilling efficiency. So it's hand-in-hand. The mobility and the flexibility of the rig is clearly generating faster penetration rates. Not only in terms of the technical sub-surface part, but also well-to-well.

Very good, Steve. I appreciate that. And then may be just along those lines. Starting to see some improvement though. But may be Gleeson, on your side, should we kind of think of the year-end DUCs as unchanged or if you guys feel better about that, you'll just update us a little later on may be completions and what the DUCs looks like at year-end?

Yes. So your question is on year-end DUCs?

Yes, I'm assuming there's no change now, but obviously, if these -- if the drill days continue to improve, that improves and you guys will just update us, as you'll have more confidence around that.

I think that's fair. I think 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 call. You may now disconnect.

Thank you.

Thank you.