SilverBow Resources Inc (SBOW) 2017 Q3 法說會逐字稿

Good morning, my name is Kayla, and I will be your conference operator today. At this time, I would like to welcome everyone to the SilverBow Resources Third Quarter 2017 Earnings Conference Call. (Operator Instructions) Thank you. Mr. Doug Atkinson, Senior Manager of Financial and IR, you may begin your conference.

Thank you, Kayla, and good morning, everyone. Thank you very much for joining us. Joining me on the call today are Sean Woolverton, our CEO; Gleeson Van Riet, our CFO; and Steve Adam, our recently appointed COO. 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, Doug, and thank you, everyone, for joining our call this morning. Before I begin, I'd like to take a second to introduce Steve Adam, who joined SilverBow as our Chief Operating Officer effective November 6. We are excited to have an industry veteran with such extensive operational experience across the Eagle Ford and several other basins joining our team. Much of our focus lately has been on expanding and derisking our inventory. Additionally, the team has done a tremendous job of lowering costs, thus far, which has laid the groundwork for the success we have achieved year-to-date. As we look forward to the next phase of development with even greater focus on growth with returns, we're confident that Steve's demonstrated low-cost leadership skills will complement our long-term growth objectives. Since Steve's first day was yesterday, I'll handle the operational comments on today's call. But you can expect to hear from Steve on our calls going forward.

Moving on to the third quarter. We're pleased to report another strong quarter for the company. We continue to execute on the plan that we've set out earlier in the year to unlock shareholder value through an acute focus on well performance, cost structure, acreage delineation and a strategic leasing program. Our primary focus has been to generate bottom line growth and to expand our drilling inventory in our core Eagle Ford acreage. I'm very pleased with our results year-to-date.

Starting with production. Our net production in the quarter was 156 million cubic feet equivalent per day, which represents growth of 7% on the second quarter and 23% since the fourth quarter of last year.

On the cost side, our lease operating costs came in favorable to guidance as our teams continue to find efficiencies in our business to lower our cost structure. This strong operational performance translates to an improved bottom line.

For the third quarter, we reported adjusted EBITDA of $31.1 million, which was a 15% increase from the second quarter. In terms of inventory, during the year, we drilled a number of successful wells that we have -- that have significantly expanded our drilling inventory of high rate of return wells. Included in this well set are 2 wells at Oro Grande; 7 wells at Artesia; 2 Upper Eagle Ford wells; and we recently TD-ed our first well at Uno Mas. These wells have provided the company several catalysts for future growth.

Another catalyst for growth has been the success of our strategic leasing program, where we've added 28,000 acres in over 300 locations to our portfolio this year. As a result of our leasing success, we are increasing our 2017 capital program by $15 million to approximately $205 million to $215 million to reflect additional acreage acquisitions. We will continue to be active on the leasing front as this adds high-quality locations to our inventory at very favorable prices.

Finally, before jumping to the operational results for the quarter, I wanted to touch on our hedging program. As you know, we have been actively expanding our hedge book. We continue to layer on hedges to protect our returns as prices warrant it. Gleason will have more to add about our hedging program.

Moving on to the operational results for the third quarter. Our production growth was driven by continued outperformance in Fasken and contribution from recent wells drilled in AWP, Artesia and now Oro Grande. As previously announced, our initial well in Oro Grande was an important proof-of-concept well for the company. We have now successfully transferred our learnings in Fasken and AWP over to both Artesia and Oro Grande with commercial success. Given the momentum we have achieved year-to-date and despite some curtailments due to Hurricane Harvey, we believe we are on track to deliver full year production of 150 million to 152 million cubic feet of natural gas per day.

Walking through field-by-field performance, starting with our Fasken field in Webb County. Net production for the quarter averaged 92 million cubic feet of natural gas per day, which represents approximately 59% of our total production. We drilled a 3-well padded Fasken in the third quarter, including 2 wells targeting the Upper Eagle Ford. As you recall, we redirected our high-spec drilling rig back to Webb County to drill 2 Fasken Upper Eagle Ford wells after observing the success of our Fasken 63H well. Our Fasken 63H was drilled partially in the upper and lower intervals and is currently tracking above our internal type curve of 14 Bcf for our Lower Eagle Ford Fasken wells. While it is still early in the production life of the 2 new Upper Eagle Ford Fasken wells, initial results look very encouraging, providing us another zone with good inventory to develop at our Fasken field that can compete for capital in our current portfolio. Developing stack pay at Fasken is a great option for us as we can leverage the existing infrastructure in place there.

Over at our AWP field in McMullen County, our production for the quarter was approximately 35 million cubic feet of natural gas equivalent per day. The AWP production mix consisted of 55% gas, 25 -- 27% natural gas liquids and 18% oil. We continue to like what we see out of our managed reservoir pressure initiatives for the Bracken 21H and 22H, which were completed earlier this year. We believe our pressure management approach here will provide higher recovery efficiencies and enhanced economic returns. Additionally, we are very focused on optimizing spacing and drilling sequencing in order to maximize the overall productivity of the field.

At a cumulative production of 700 million -- 750 million cubic feet equivalent, the Bracken 21H and 22H are demonstrating an average surface pressure of 540 psi compared to our -- 540 psi higher compared to our 4 2016 wells drilled in the same area at the same cumulative production. These results are in line with our type curve for the area.

In LaSalle County, we pushed forward with our liquids-rich drilling program in our Artesia area during the third quarter in an effort to deploy our newer generation drilling and completion technology. This marked our return to the area for the first time since 2013. Earlier wells in this area were drilled without the benefit of a 3D seismic, target window identification and modern completion designs tied to longer laterals. We have completed 7 wells in the Northern Artesia area this year with lateral lengths ranging from 6,000 to 11,000 feet.

The average drilling cost of $2.1 million for the 7 wells drilled in Artesia during the second and third quarter decreased 38% from our 2013 drilling campaign. Likewise, the average completion cost of $111,000 per stage decreased 33% despite increasing proppant volumes by 62% compared to our average completions in 2013. We like the returns we are seeing on our Artesia wells with EURs of 1,500 Mboe, a roughly 50-50 mix of gas and liquids and well costs below $5.5 million. Our returns in this area are in excess of 50%.

For the quarter, we produced 22.4 million cubic feet equivalent per day in Artesia, which consisted of approximately 44% natural gas, 35% natural gas liquids and 21% oil.

At Oro Grande also in LaSalle County, we completed our first well, the Nueces Minerals #1, during the second quarter. The NMC 1 had cumulative production of approximately 940 million cubic feet equivalent with flowing tubing pressures of over 6,000 pounds for the first 90 days, which is on line. This is in line with our internal 14 Bcf type curve for the area. This well also has the highest bottom hole and surface pressures of any Eagle Ford well that the company has completed to date. This has been a very important concept well that we hope will lead to full development of this large position following some additional delineation work.

In that regard, we did move the rig back to Oro Grande during the third quarter and recently finished drilling and completing the NMC 2H, approximately 2 miles east of the NMC 1. Our plans for additional delineation well -- we plan to drill an additional delineation well in early 2018 as we start to move the drilling in this acreage block from assessment to delineation.

Current gross production from the NMC 1H well is roughly 10 million cubic feet equivalent per day with approximately 5,700 psi of flowing tubing pressure under our detailed pressure management program. As a reminder, we have a 100% working interest with a 75% revenue -- 75% net revenue interest in this area. Production mix consisted of 100% natural gas.

Finally, over at Uno Mas in Live Oak County, we are currently drilling our first assessment well with plans to complete it later in the fourth quarter. From a geologic perspective, we like what we see at Uno Mas, and we are excited to appraise this area in the fourth quarter. We'll discuss results from this well on our fourth quarter earnings conference call.

And with that, I'll turn it over to Gleeson.

Thanks, Sean. In my comments today, I'll highlight our third quarter financial results as well as our operating costs, hedging program and capital structure. Production averaged 156 million cubic feet equivalent per day, which represents a 6.8% increase from the second quarter, driven by turning 5 new wells online on or ahead of schedule.

Total revenue was $49 million, with natural gas representing 82% of our production and 72% of our revenues. Our average realized natural gas price excluding hedging was $3.01 per 1,000 cubic feet compared with $3.16 in the second quarter. Our differential was $0.01 above Henry Hub and illustrates why the Eagle Ford is such a great market for selling gas.

Turning to liquids. Our average realized crude oil selling price excluding hedging was $46.93 per barrel, up about $0.11 from the second quarter. The average realized NGL selling price increased $3.18 to $21.67 per barrel or roughly 45% of WTI. That is a meaningful increase relative to WTI and a result of increases in propane, butane and isobutane prices relative to relatively flat WTI prices for the quarter.

While we added significantly to our hedge book in the quarter and now have hedges extending into the first quarter of 2020, hedging loss in the quarter was de minimis at $63,000. That said, a disciplined hedging program is integral to how we manage risks to plan to continue opportunistically adding additional hedges to further protect our cash flows. Indeed, we even entered into some NGL hedges after the quarter for the first time in the company's history.

Turning to cost. LOE was up slightly to $0.41 per 1,000 cubic feet equivalent due to a scaled up maintenance program and a roll-off of some onetime credits that positively impacted the second quarter. For the fourth quarter, we are guiding our LOE expense to approximately $0.38 to $0.42 per 1,000 cubic feet equivalent.

Adding our LOE and T&P together, we have a total cost of roughly $0.75 per 1,000 cubic feet equivalent, which we believe compares favorably to our peers. Cash G&A declined to $4.6 million, a reduction of approximately $550,000 or 10% from the second quarter. We're guiding to a slight increase for the fourth quarter as we incur some severance costs related to the addition of our new COO and other adjustments to our officer group. We've reduced our officer group from 5 -- to 5 people from 7 previously as we continue to streamline our operations team and the company's overall G&A.

Our strong production growth and continued cost focus drove a 15% sequential increase in adjusted EBITDA to $31.1 million.

Moving to capital expenditures. We spent $61 million on CapEx in the quarter. Approximately $13 million or 20% of that amount was used for a strategic leasing program, where we captured another 15,000 acres in the Eagle Ford.

As Sean mentioned, we increased our 2017 capital program to $205 million to $215 million, primarily due to the ongoing success of our strategic leasing program. This program provides for 24 completed wells, which will drive 25% to 30% production growth throughout the course of the year.

On that note, we have updated our corporate presentation to include fourth quarter 2017 guidance, so please refer to it for our latest expectations.

We ended the quarter with liquidity of approximately $90 million, consisting of $13 million in cash and $77 million available under our bank credit facility. We're currently completing our borrowing base redetermination, and our banks have approved a $40 million increase in our RBL to $370 million in total. This will further boost our liquidity to approximately $130 million. While the banks' price decks are a little lower than last spring, our strong drilling results, robust hedging strategy and disciplined cost [mitigating] initiatives have underpinned our profitable reserve growth. It's a testament to our entire team's efforts, and I would like to thank our banking syndicate for their continued support. This credit facility is the only debt we have in the company, so we have a pretty straightforward capital structure of bank debt and public equity. We expect to fully fund our 2017 capital program with cash generated from operations and borrowings on our credit facility. At the end of the quarter, we are in full compliance with all our 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, we had a great quarter, and we are setting ourselves up to end the year on a high note. We expanded our inventory through a successful drilling and delineation campaign with success at every field in our portfolio, save, for Uno Mas, where we just TD-ed our first assessment well. And we'll have more to report on our next earnings call. We've also increased our acreage by another 20%, and we are closing in on 100,000 net acres in the Eagle Ford.

In addition, we have grown production over 20%, and increased adjusted EBITDA by 50% since the fourth quarter of 2016. Furthermore, with our fourth quarter guidance, we are now estimating production growth of 25% to 30% for this year. As we start to look towards 2018, our goal remains to grow production by drilling wells with attractive rate of return and maximizing our margins by leveraging our low operating costs while expanding our inventory through leasing and opportunistic acquisitions. Along with a clean balance sheet, simple capital structure and strong liquidity, we are well positioned for continued growth over the coming years.

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 the line of Jeff Grampp with Northland Capital Management.

Just kind of thinking about -- with the extra incremental leases that you guys have acquired here and the extended inventory, kind of how you think about potentially adding a second rig, especially with commodity prices kind of firming up here. Just kind of hoping to get some updated thoughts on 1 versus 2 rigs going forward.

Yes, I appreciate the question. I do think we're in a good position now to start thinking about accelerating our inventory that we've put in place and with the success of the delineation wells that we've drilled this year. So we're right in the middle of working through our 2018 budget, so not quite prepared yet to say what we are going to do. But that's definitely an option that we're considering. And of course, as we contemplate that, we think about managing our balance sheet and how we fund that second rig going forward. But we think it's definitely an option for us.

And Jeff, it's Gleeson. As Sean mentioned, we'll be in a position sometime in the Q1 -- probably early Q1 to come out with a kind of a revised budget. So I think it's part of that. We're going through all the different machinations, to make sure our balance sheet works, et cetera. But early in Q1, expect us to come out with something more definitive, about our plans for next year.

Okay, perfect. And then just on the leasing front. I guess it's, personally, pretty surprising how much success you guys have been having here with the leases. Just kind of wondering how much more runway is there. Is that something that's still interesting to you guys and potentially having a decent amount of land budget allocated in '18 if you continue to see some opportunities? Just kind of wanted your thoughts there.

Yes. We've been very pleased with our success as well, like we disclosed on the call. The reason for increasing our budget was to capture the acreage that is available. Going forward, we do think there's still more opportunities to lease. Will it be to this level next year? Probably not, but we continue to work the area, uncover new areas to lease. And so we'll just continue to assess that as we move into next year. We are seeing more competition come into the area as well, so starting to see more pressure on the competition front also. So very pleased that we're aggressive this year to take this approach to expand our inventory at very favorable cost.

Your next question comes from the line of Ben Wyatt with Stephens.

If we can maybe stay on the acreage that you guys picked up. Just curious kind of -- really kind of what's going on there. You guys are kind of filling in holes. Are you increasing your working interest? Are you kind of going out and extending the area -- extent of each of these areas? Just any more color on kind of what this acreage looks like that you're picking up.

Yes. I would tell you that we've added to our acreage position across all of our operating areas. So it's really been an effort to expand and build on our block [key] positions that we already have so that we can take advantage of optimized development infrastructure in place -- or new infrastructure that will be put in place. So we've added to our positions across all areas. We have started to also try to pick up working interest within certain blocks. So we're trying to pick up and add to our working interest positions as well. So I guess to summarize that, we've been adding across our positions, really trying to build bigger blocks that we really think ties into a more optimized development long term.

Got it. That's helpful. And then my next one -- and I don't know if this is a fair question, Sean. But Steve in there just a couple of days, any kind of tweaks we should expect on the drill and completion side, I mean, whether that's land and laterals, whether that's completion design? Anything that you guys will do a little different that's drastically different? Or are you guys kind of on the same page there as far as how you guys are operating right now?

Yes, yes. I think that we really see the company pivoting to a new phase, where we're highly concentrated on executing on the development of this acreage position that we've put together. In bringing Steve on board, with his extensive experience, we really think that there's more opportunity to optimize completion designs, which will hopefully enhance well performance as well as bring down costs. So that's definitely our plan, to really bring him in, to leverage his extensive experience in the play to optimize our asset base even further. And we really look forward to giving you some updates on progress made on that front over the next quarter or 2.

(Operator Instructions) Your next question comes from the line of John Aschenbeck with Seaport Global.

I had a follow-up on 2018. I was hoping to get an idea of capital allocation and where you'd be inclined to focus activity across your various operating areas and how that decision will change if you added a second rig to the mix.

Yes. We like the results that we're seeing across all of our areas, so we will look to continue to allocate the capital in all 5 of our existing areas. In terms of how we'll manage that, if we do add a second rig, I'd say it's probably a little premature for me to speak to that.

Okay, appreciate that. And then a follow-up there on the decision to potentially add a second rig in '18. I was wondering how that decision to move forward with the second rig is influenced by your success on the monetization of your legacy assets. I'm not sure if I'm reading too much into it, but it seems like that's setting up to be a compound decision, where the monetization gets done, then you announce the second rig. So I was just curious to get your thoughts there.

Yes. I would tell you that monetization of our Olmos assets is probably independent of our capital funding decision. Really, since emerging from bankruptcy last year, the company has been very focused on streamlining and upgrading its portfolio, and so our exit out of Louisiana was a big step in doing that. And now we're essentially finishing up that cleanup of the portfolio by divesting of these legacy assets that just don't fit our go-forward model. They're a little bit more inefficient than what we want. So we're looking to lower our operating cost by divesting the properties as well as bringing up our staff to focus on assets that move the needle more.

And it's Gleeson here. Maybe just to give you a little more color on that Olmos divestiture. I mean, we're talking about we have -- if we have, [round numbers], 700 wells, about 500 of them almost is an Olmos thing. So it's a huge amount of our wells, but it is 10 million cubic feet a day, roughly speaking, of gas. So it's one Oro Grande well to us, but it takes up -- it just touches a whole bunch of people in the organization with this time -- I mean, it is time better spent if we could divest that and streamline our portfolio. So I don't think it's a dollar mover thing that's -- take 10 million and put whatever multiple you want to put on it. I mean it's not a huge amount of money for us that's enough to boost a second rig. It's more the, as Sean said, streamlining our portfolio, just getting it more efficient. That's a pretty high LOE, too, so I think it will bring our LOE down and show be more reflective of what our real run rate is. I think as Sean said, it's really -- we're talking with the board and have a lot of scenarios going on. I think early next year, we'll be able to give people kind of probably where we'll land with the board on rig count and all that for next year.

You do have a follow-up from the line of Ben Wyatt with Stephens.

Gleeson, you just hit on one of them on kind of maybe how we should think of potential proceeds. So it sounds like it's just a flowing number we should throw on that 10 million a day. A couple other housekeeping, though. How are you guys thinking about NGLs, maybe modeling NGLs for the next quarter and maybe even into '18, Gleeson?

Well, again, we've seen a nice bump in the quarter. I think we're kind of, round numbers, kind of 40% of WTI in Q2. We bumped to 45%. That's pretty good. As mentioned, we've put on -- that's really driven by 2, 3, 4 price bumps relative to WTI. So as mentioned, we've put on some of our first-ever NGL hedges post-quarter close. As far as when we look out into the future, what does it mean and what not, again, we don't really put guidance out there. But I'm happy to -- if you want to do a follow-up call later on separately, just some of my marketing guys and have a chat with what we see going on. But we like the balance. We locked some of them with a hedge, so we continue to try and lock in a good price when we see them.

And at this time, there are no further questions. Ladies and gentlemen, that does conclude today's conference call. We thank you for your participation, and you may now disconnect.