SilverBow Resources Inc (SBOW) 2017 Q2 法說會逐字稿

Good afternoon. My name is Phylis, and I will be your conference operator today. At this time, I would like to welcome everyone to the SilverBow Resources Second Quarter 2017 Earnings Conference Call. (Operator Instructions)

Thank you. I would now like to turn the call over to Doug Atkinson. Please go ahead.

Thank you, Phylis, and good morning, everyone. Thank you very much for joining us. Joining me on the call today are Sean Woolverton, our CEO; Bob Banks, our COO; and Gleeson Van Riet, our CFO. We posted an updated corporate presentation on to 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. We are pleased to report a strong quarter for the company. We continue to execute on our plan as all of our operational results either met or exceeded the high end of the guidance. In particular, our net production in the quarter was 146 million cubic feet equivalent per day, which was above the high-end of the guidance and was driven by our strong results from our capital programs during the first half of the year.

Additionally, our cost came in favorable to guidance as our teams continued to find ways to drive efficiencies in our business while lowering our cost structure despite the cost increases that we are seeing from service providers. This strong operational performance, of course, translates to an improved bottom line.

For the second quarter, we reported adjusted EBITDA of $27.2 million, which was a 26% increase from the first quarter. We are retaining our 2017 capital program of $190 million to $200 million. This budget provides for a balanced investment approach with drilling in all areas of our portfolio, testing of new areas, further drilling in the upper Eagle Ford as well as a strategic leasing program.

In the quarter, we completed our first well in Oro Grande. We'll be releasing results on our third quarter conference call, but we are encouraged by what we're seeing with our new completion design, which optimizes cluster spacing and increases our near wellbore connectivity with greater frac type and higher proppant volumes. The well is producing on a pressure-managed program.

Based on strong performance of our recent Fasken wells, we have decided to take the rig back to Webb County to expand our development of the Upper Eagle Ford during the third quarter.

We have tightened our full year production guidance to 148 million to 152 million cubic feet of natural gas equivalent per day. We also slightly adjusted the mix to reflect our change in drilling plans in the third and fourth quarter, which Bob will touch on a little bit later in the call.

As previously mentioned, we increased our revolver by $80 million in the second quarter. We also rebranded the company and relisted on the New York Stock Exchange under the ticker SBOW. Our focus continues to be growth with returns. To that end, we've been active in building the hedge position since our last conference call and we'll continue to layer on incremental hedges to [predict] our returns as price warrants it.

Before passing it over to Bob, I'll touch on our Eagle Ford expansion strategy. We get asked quite a bit about our leasing initiative and our thoughts on the M&A environment within the Eagle Ford.

We are using our in-basin knowledge and our large volume of subsurface data in order to high-grade and bolt on lease positions towards existing acreage. We are constantly assessing acreage packages and evaluating every deal within our core area as we actively seek to grow the company's Eagle Ford position. But we are focused on ensuring that, that growth is done in an accretive manner.

In the second quarter, we added approximately 13,500 net acres in an incremental 90 locations to our drilling inventory. Breaking it down by area, we added approximately 1,300 acres in Southwest Webb County near our Fasken operations; 10,000 acres in our AWP area in McMullen County; and approximately 2,300 acres in our Uno Mas area in Live Oak County. We will continue to be active on the leasing front as this will add high-quality locations to our inventory at favorable prices.

I'm pleased with the very productive quarter for the company. We are executing on our operations while expanding our inventory through leasing. We are in a great position to grow as a true Eagle Ford player. And with that, I'll hand it over to Bob.

Thanks, Sean. Our total net production for second quarter 2017 of 146 million cubic feet equivalent per day was driven mostly by accelerated performance in the Fasken and the 2 recent wells completed in AWP. Continued optimizations and declined mitigation initiatives at AWP and Artesia also contributed to our strong performance for the second quarter. This level of production represents growth of 8% over the first quarter.

We continue to set new technical limit in Fasken and now have successfully transferred these learnings and efficiencies to other areas in our portfolio, most recently, Artesia. Consequently, we feel like we are on track to achieve our recently tightened production guidance of 148 million to 152 million cubic feet of equivalent per day for the full year.

Moving on to the field-by-field performance, starting with our Fasken field in Webb County. Net production for Fasken in the quarter averaged 96 million cubic feet of natural gas per day, which represents approximately 65% of our total production.

As we noted on our last call, we continue to test different completion techniques to enhance our well performance, including newer landing points, frac designs and scale inhibitor methods. We tested these concepts in the last well drilled at Fasken before moving the rig. This last well, the Fasken 63H, was drilled as a hybrid well with a portion of the lateral in the Upper Eagle Ford and a portion of the well in the Lower Eagle Ford. This well continues to perform as well as the surrounding 100% Lower Eagle Ford wells and our tracer data suggests that we have production contribution from all frac stage intervals.

As such, we have moved the rig back to Fasken to conduct a more definitive Upper Eagle Ford program. We're now on a 3-well pad that includes 2 upper Eagle Ford wells and 1 lower Eagle Ford well. Through the work we've already done in the field, we believe that we can create a very economic upper Eagle Ford program. This is something we are calling Fasken 2.0.

Over at AWP field in McMullen County, our production for the quarter was approximately 38 million cubic feet of natural gas equivalent per day. The production mix out of AWP consisted of 51% gas, 29% natural gas liquids and 20% oil. We continued our manage pressure reservoir initiatives for our 2 new recent completions, the Bracken 21H and 22H, and are experiencing encouraging results.

At a normalized cumulative production volume of 200 million cubic feet, our new wells have 2,500 pounds of greater flowing bottom hole pressure than we were able to achieve in our earlier wells that were not pressure-managed. We'll have more results to share in these 2 wells with our next earnings conference call, but we continue to like what we see out of these 2 wells.

Concurrent with testing these new manage pressure concepts, we have been able to expand our leasing in the AWP area by adding approximately 10,000 acres that we believe will expand our inventory of economic wells within this gas and gas condensate window of the Eagle Ford.

Moving over to La Salle County. We initiated a liquids-rich drilling program in our Artesia area during the second quarter, which marked our return to this area for the first time since 2013 in an effort to deploy our new generation technology on drilling and completions.

Some of our key accomplishments to-date include, one, we achieved a company drilling record of best spud to total depth performance of 5 days on the Baetz 'A' 6H well; second, we lowered our average drilling costs from $3.2 million to $2 million for the first 4 wells; third, we lowered our average completion costs from $3.75 million to $2.951 million while increasing our proppant volumes by almost 75% and lastly, in July, we finished drilling the Carden-Baetz B 1H and set a new company record for lateral length of approximately 11,000 feet.

This improved performance of Artesia was achieved by executing our newest drilling and completions design, similar to what we have been utilizing in other parts of the Eagle Ford over the past few years.

For the quarter, we produced 10.4 million cubic feet equivalent per day in Artesia, which consisted of approximately 46% natural gas, 39% natural gas liquids and 15% oil.

At Oro Grande, also in La Salle County, we completed our first well, and the [Neaysys Minerals #1] and set a new company record for the amount of proppant pumped in a single well of about 26 million pounds. This well also has the highest bottom hole and surface pressure of any Eagle Ford well that the company has completed to date.

This has been a very important concept well for us, and we hope it will lead to full development to this large position following some additional delineation drilling work. This well, similar to our last 2 wells at AWP, is on a pressure-managed program. We believe this program will ultimately lead to higher ultimate reserve recoveries and better economics. We plan to drill and complete an additional well in Oro Grande later in the year.

Over in the Uno Mas area in Live Oak County, our plans call for drilling and completing our first well later in the year. We were also successful in bolting on an additional 2,300 acres in the area, bringing our total acreage in the Uno Mas area to approximately 4,800 acres.

As I touched on earlier, we have modified our drilling schedule for the third and fourth quarter. While our capital budget for 2017 remains $190 million to $200 million, it now provides for 27 completed wells. In lieu of drilling and completing wells in Northern AWP, which have a relatively oilier hydrocarbon mix, we're now going to drill 2 upper Eagle Ford wells and 1 lower Eagle Ford well in Fasken and 1 additional delineation well in Oro Grande.

We are making this change due to the encouraging results so far in the strategic opportunity this now provides us to add substantial high-quality drilling locations to our runway in both of these key areas.

Given this change in schedule, we have changed our hydrocarbon mix for our full year production. With that, I'll turn it over to Gleeson.

Thanks, Bob. Total oil and gas revenues for the quarter were $45.8 million with 77% of our revenues being derived from gas sales. Price risk management provide the benefit of roughly $5.1 million which primarily reflects the unrealized noncash change in the value of our hedge portfolio.

Our realized loss on hedge settlements during the quarter was $1.6 million in cash. Our average realized natural gas price, excluding hedging, was $3.16 per 1,000 cubic feet compared with $3.07 in the first quarter. Our differential is only $0.02 of Henry Hub and it illustrates why Eagle Ford is a great market for selling gas.

The Eagle Ford has significant existing midstream infrastructure and benefits from close proximity to the major demand centers of the Gulf Coast, petrochemical industry and expanding number of LNG facilities and the growing Mexican export market where we currently sell a portion of our gas.

Turning to liquids. Our average realized crude oils selling price, excluding hedging, was $46.82 per barrel, down from $49.26 in the first quarter. The average realized natural gas liquids selling price was $18.49 per barrel or roughly 38% of WTI price versus $20.33 in the prior quarter.

Moving to cost. Net G&A came in at $6.8 million, which compares favorably to the $9.8 million reported in the first quarter. As a reminder, our first quarter G&A was impacted by a number of onetime charges associated with our headquarters move and reduction in staff.

Our cash G&A for the first quarter was $5.2 million, and we are maintaining our full year guidance of $22 million to $24 million.

Cash interest came in at $2.2 million and we're guiding $3 million next quarter to reflect higher levels of borrowing on our credit facility. Our LOE for the quarter came in at $4.8 million or 38 -- sorry, $0.36 per 1,000 cubic feet equivalent, which compares very favorably to the guidance of $0.48 to $0.50, primarily due to compression optimization and streamlining of our field work force. Additionally, there are few onetime credits associated with our previous divestitures that carried through LOE in the second quarter primarily associated with insurance.

For the third quarter, we're expecting a slight uptick in LOE expense of $0.47 to $0.48, and some of these credits will not recur, and we will implement a scaled-up maintenance programs. For the full year, however, we reduced our LOE guidance to $0.43 to $0.46 primarily due to continued field optimizations and staff reductions.

Transportation and processing came in at $4.8 million or $0.36 per 1,000 cubic feet equivalent compared to guidance of $0.36 to $0.38. For the third quarter, we're guiding for $0.35 to $0.37 and slightly raised our full year guidance to $0.34 to $0.36 to reflect higher natural gas volumes associated with the revised drilling schedule in the back half of the year.

Adding our LOE and transportation processing together, we have a total cost of $0.72, which compares to $0.83 in the first quarter. We believe this cost structure compares very favorably to our peers.

Adjusted EBITDA was $27.2 million and our costs incurred for capital expenditures for the quarter were $58.7 million. Approximately $16 million or nearly 40% of our capital budget in the quarter was used for a strategic leasing program.

Finally, net income for the quarter was $16.2 million or $1.41 per diluted share, which includes the net gain on commodity derivatives of $5.1 million. As we mentioned on the last call, we increased our borrowing base by $80 million, reduced our interest rate, adjusted our credit agreement to current market terms and extended our maturity to April 2022.

This credit facility is the only debt we have with the company so we have a pretty straightforward capital structure of bank debt and public equity. We expect to fully fund 2017 capital program with cash generated from operations and borrowings on our credit facility.

At the end of the quarter, we were in full compliance with financial covenants and added significant headroom. As Sean mentioned, we maintain our capital program of between $190 million to $200 million for 2017 with about 70% of that allocated to drilling and completions. This program provides for 27 completed wells, which will drive 20% to 25% production growth throughout the course of the year.

With half the year behind us, we have narrowed our full year production guidance to 148,000 to 152,000 cubic feet equivalent per day -- sorry, and initiated third quarter production guidance of 154,000 to 160,000 cubic feet per day. For more details concerning our guidance, please see our latest corporate presentation.

Moving on to hedging. As of June 30, our unsettled swaps in collars covered approximately 97 million cubic feet a day of natural gas at an average fixed price of $3.06 and 950 barrels per day of crude oil at an average fixed price of $48.17. Using the midpoint of our full year 2017 production guidance, we are around 65% hedged for the remainder of this year.

For 2018, we have swaps covering approximately 71 million cubic feet per day of natural gas at an average fixed price of $3.06 and 684 barrels per day of crude oil at an average fixed price of $50.97. Additionally, we have 46 million cubic feet per day of natural gas hedged at an average fixed price of $3.12 for the first quarter of 2019.

We plan to continue opportunistically adding additional hedges in 2018 and 2019 to further protect our cash flows. Full details of our hedges are contained in our 10-Q. And with that, I'll turn it over to Sean to wrap up our prepared comments.

Thanks, Gleeson. So to summarize our call, we had a great quarter as all operational results met or exceeded the high end of our guidance. We added high-quality acreage to our portfolio, drilled and completed our first well at Oro Grande, successfully implemented our pressure management programs at AWP and set several new technical limits in Artesia.

Additionally, we have moved our rig back to Webb County to initiate an upper Eagle Ford development program in Fasken. Our goal in 2017 is to grow production by drilling wells with attractive rates of return and maximize our margins by leveraging our low operating cost while expanding our inventory through leasing and opportunistic acquisitions. Along with a clean balance sheet, simple capital structure, minimal debt and strong liquidity, we are well-positioned for strong growth over the coming years.

At this point, I'll turn it back to the operator for the Q&A portion of our call.

(Operator Instructions) Our first question comes from the line of Dustin Tillman with Wells Fargo.

So when you put out the capital budget for 2017 and you put in some estimated IRRs by area, we talked about last quarter that a lot of those areas haven't had recent wells drilled. I know it's early in the quarter but -- early in the production life of the some of these wells, but what are you seeing from the early wells at Oro Grande and Artesia? And how does that set up versus kind of the placeholder type curves that you've put out previously?

Dustin. This is Sean. Thanks for the question. You're right that it's still early on in many of those areas, but we're pleased with the results that we're seeing across the board. I mentioned that we're planning to go back to Oro Grande and drill a second well there, which will give us further insight into that acreage block in our AWP based upon the results that we're seeing there. We've expanded our acreage position significantly and look forward to future drilling and developing that block. In Artesia, like we mentioned, we hit on a number of operational records for the company so we're really pleased with the results we're seeing there. So at this point, I would tell you that the type curves that we have in the appendix of the presentation we're leaving as is, and we're not updating those yet. And of course, as we get more performance data in from those areas, we'll look to update those curves accordingly. But those type curves, we think, are still representative of what we're seeing in all areas of our asset base.

Yes, that makes sense. And then in terms of well costs that you had in that returns across the portfolio slide, are AFEs on recent wells kind of matching what you're showing there?

Yes. This is Bob. So like Fasken, our last campaign at Fasken, we were drilling, I think, around $5 million, which is under what we have in those type curves slides that you see in the corporate presentation. At Artesia, those first -- the first 2 wells came in under $5 million there, drilled and completed, so very good results there. I think at AWP, that $6.9 million that's in the corporate presentation. We actually feel fairly strongly that we can drive that down to about $6.2 million and hopefully combine that with increasing those EURs that you see in those type curves. That's our goal anyway. And then over at Oro Grande, I think what you see in there, after we get out of the phase of doing some of the evaluation work in the first well and recalibration of the seismic and the -- and all the pipeline tie-in and common infrastructure work, we think that around that $9 million range looks good as we move into pad development. And again, our goal is to try to get the best economics we can there. So our goal is to combine that cost structure with even better EURs. So I think hopefully that provides you a little color.

Yes, very good. And then one more question is kind of on leasing that was done. You updated location counts to the new deck to reflect the leasing. Was the acreage that was added in AWP, was that a re-addition of the acreage that had expired? Or is there something in addition to that?

Yes, it was a re-addition of what expired, and there was some more on top of that.

Great. And then the additional location at lower Eagle Ford and Fasken locations that were added, apologies, but is that additionally leasing or is that a view on down-spacing?

No, that's additionally leasing.

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

I had a follow-up on the hybrid Fasken test, the 63 well. That was really encouraging to hear that that trellis tracking pretty much in line with offset that was completely completed in the lower Eagle Ford. But I was curious in terms of the contribution from the upper Eagle Ford, I'm not sure if it's too early at this point, but I was wondering what the tracer data suggests is the contribution from the upper versus the lower? But it must be pretty encouraging if you're going back to drill 2 more tests, but I was wondering if you could possibly add a little bit more color there?

Yes, it's hard -- this is Bob, I'm sorry. It's hard to give you quantities, but we do see tracer from the tracer data, and we've done a lot of tracer work on the gas and the water. We do see contribution from every frac stage in the wellbore. And second, we do see separations of tracer data between the upper Eagle Ford and the lower Eagle Ford. So I mean, that's really the purpose of us going back into doing the next work where we drill 1 lower Eagle Ford and 2 upper Eagle Ford tests to really collaborate and prove up what we think we've proved up in this hybrid as well as the one earlier upper Eagle Ford test that we did.

Understood. That's really helpful. I appreciate that. My follow-up here is just in terms of organic leasing. I was maybe hoping you could possibly frame the remaining opportunity set out there. I mean, is it reasonable to think that you could add another 13,000 acres per quarter? And then I guess, more specifically, what does the opportunity look like at Fasken? How big do think you can ultimately get that position? Or I suppose, more specifically, is there a certain number of lower Eagle Ford locations you think you could add there in the near term?

Yes, John. This is Sean. Let me a field this call. I think as we look at the fairway of opportunity that we focused in, and that's really the gas, gas condensate window in the western portion of the Eagle Ford, we think we have a real competitive advantage with our history in that area, with the amount of subsurface data we have. And yes, we think there's more running room to capture. We are seeing increased competition on the leasing front in the area, so we're being very proactive in trying to expand that inventory as we think there's a window of opportunity here to add the inventory at a very favorable cost. So we're still progressing on that front with our strategic leasing program, and we'll do so as we think we're still adding inventory at a very favorable price. In terms of Fasken, that's an area that's obviously is well-known by the industry, generates some of the best returns in the Eagle Ford. So probably not as much runway there. We were very opportunistic to add the 1,300 acres that we did. You think about, from a percentage basis, that increased our position in our Fasken area by about 25% to 30%. So very opportunistic to grab that. We'll continue to look in that area, as we always have, just it's a very competitive area and not a lot of run room there - runway there. So we're happy to get what we've gotten. We'll keep an eye on it and see if anything else becomes available.

You have a follow-up question from the lineup Dustin Tillman with Wells Fargo.

Sorry. I come at you with 2 more. So there's been some chatter about potential assets for sale on the basin. There's a few transactions that have happened. Are looking at any of those? And if there was something to do in that, how would you intend to fund it?

Yes. Dustin, this is Sean again. Yes, we're being very proactive in looking at opportunities for growth. We do feel that the most economic full cycle makes sense to continue to pursue our leasing program as we think that grassroots leasing adds the best returns overall. But we're going to be opportunistic on the A&D front as well, and we're looking at all the opportunities that are coming to the market and being proactive on some other areas that aren't on the market as well. In terms of funding the opportunities, that's always a challenge. I'll tell you that we look at returns in total, what are you paying for the acreage and what's your cost of finance it. So we kind of marry those things together and say, hey, can we generate the returns here that add accretive value to the company when we look at the purchase price as well as the way to fund it. So we're laying groundwork across the board on talking with people for various ranges of funding levels from smaller package to package -- to larger packages and look forward to, sometime in the future, announcing an opportunity that comes to us.

Very good. And then maybe just one last question. When you look at your balance sheet and kind of the liquidity that you'd like to have going forward, do you expect that most of your additional liquidity will come from growing the borrowing base? And any other comments on the balance sheet?

Yes, Dustin. It's Gleeson here. Again, I appreciate the question. Yes, I think for us, yes, the bottom line is we're very successful in getting a redetermination of this past spring. Bumped our borrowing base $80 million. We have 12 banks there, 6 of them renewed. So all the investment we have been making thus far, as Sean and Bob mentioned, it's helped -- there's very good return and good results. So we think when we come this fall with all the growth we're having, that should increase our borrowing base. In addition, we think about acquisitions. We're opportunistic on that stuff. And we always have the funding in place before we announce any acquisition. So that's how we sort of think about acquisitions, as Sean mentioned married with financing. And maybe lastly, the majority of our capital spending -- capital expenditure is discretionary. So it's the leasing, whether it's kind of run-to-rig or -- and a rig contract goes at the end of the year, or indeed the completions, we've got a lot of discretion there. So I think we do feel comfortable with our existing RBL, and the bank rep supporting us in the growth we're seeing in our reserves. And then as we look forward to a number of different options, both in the acquisition front, organic leasing and the CapEx, especially going into 2018, which we're not going to give -- we'll come out with a new budget towards the end of the year, we think that's enough liquidity to fund kind of what we do. But if we want to accelerate or get something bigger, we'll add financing to that.

And at this time, there are no further questions. I will now like to turn the call over to Sean Woolverton.

Okay, thanks, Phylis. Hey, thanks, everyone, for joining our call this morning. Greatly appreciate your interest in the company. Reiterate that we're very pleased with the results for the quarter. We think we're executing on our plan, and look forward to talking to you in the future.

That does conclude today's conference. You may now disconnect.