Battalion Oil Corp (BATL) 2017 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Halcon Resources Second Quarter 2017 Earnings Conference Call. (Operator Instructions) As a reminder, today's conference may be recorded.

I'd now like to introduce your host for today's conference, Mr. Mark Mize, Executive Vice President and Chief Financial Officer. Sir, please go ahead.

Okay, good morning and thank you. This conference call contains forward-looking statements. For a detailed description of our disclaimer, see our earnings release issued yesterday and posted on our website. We've also updated our investor presentation for the second quarter and certain other items, and you can access that presentation on our website as well.

I'll begin with a few financial comments then turn the call over to Jon Wright, followed by Floyd.

Production for the second quarter averaged 36,308 barrels of oil equivalent per day, which is above the high end of our guidance range of 33,000 to 35,000. The outperformance was driven by a combination of strong PDP production in the Delaware as well as PDP outperformance in the Williston Basin. LOE expense was $6.17 per Boe in the second quarter, which was roughly consistent with the $5.96 per Boe in the first quarter. Workover expense was down materially in the second quarter at $2.16 per Boe versus $3.30 per Boe in the first quarter. The reduction of workover expense was driven by operational efficiencies, which required less workover activity.

Taxes other than income came in at $3.25 during the second quarter, which was slightly lower than in the first quarter, which was $3.34, and that was driven by changes in commodity prices in the second versus the first quarter. Gathering, transportation and other after adjusting for some selected items came in at $3.02 per Boe versus $2.66 in the first quarter, and this increase was driven by the company sale of El Halcon in the first quarter of 2017, which had lower transportation and gathering expenses than in the Williston Basin.

After adjusting for selected items, G&A expense was $3.98 per Boe in the second quarter versus $3.44 in the first quarter. And this slight uptick in G&A was primarily driven by the sale of production associated with the El Halcon transaction in Q1.

Overall, our total current quarter operating cost adjusted for selected items was $18.58 per Boe. Looking forward in pro forma for the Williston Basin sell, we expect our overall operating cost metrics to improve as we transition from a higher operating cost environment in the Williston Basin to a lower operating cost environment in the Delaware.

With respect to D&C CapEx, we incurred right at $103 million during the second quarter. The capital spend was higher as we added -- in the first quarter as we added a second rig in the Williston Basin in April. We had 2 rigs running for the full quarter in Delaware. We also spent about $7 million on infrastructure and seismic in the current quarter.

With regard to hedges, we realized a net gain on settled derivative contracts of $6 million during the second quarter versus $2 million in the first quarter of 2017. For the last 6 months of 2017, we have 21,250 barrels per day of oil hedged at an average price of $54.84 a barrel. For 2018, we currently have 7,750 barrels a day of oil hedged at an average price of $52.57 a barrel.

On the gas side, we have 27,000 MMBtu of gas hedged for the remainder of 2017 at $3.33. And we also have 10,000 MMBtu a day of gas hedged in 2018 at an average price of $3.16. As always, we'll continue to watch and monitor the strip in the next 24 months or so and we'll add hedges when it's appropriate to do so.

As of June 30, 2017, and pro forma for the announced asset divestitures, debt repurchases and the estimated borrowing base reduction associated with the Bakken sell. We had just under $700 million of liquidity, which consisted of cash on hand plus a new undrawn senior secured credit facility. We're currently working with our bank group to replace our existing credit facility and expect that process to conclude concurrent with the closing of the Williston Basin asset sell. Needless to say, we have a very strong current and projected leverage and liquidity, which allows us to execute our growth plans in the Delaware basin over the next several years.

In conclusion, I do want to point out that our earnings call issued yesterday provided some changes to certain financial and operational guidance for the fourth quarter and the full year of 2017 and we do plan to issue formal 2018 guidance later this year.

And with that, I'll turn the call over to Jon.

Thanks, Mark. I'll start with our Monument Draw prospect in Ward County. The first operated well in Delaware Basin was drilled in the Southern Tract of our Monument Draw area. This well, the CRMWD 79-1H, continues to perform exceptionally well. Our estimated recovery, ultimate recovery on this well is about 1.1 million Boe, consisting of 81% of oil on a 2-stream basis. It's one of the best wells in the area of the basin on an EUR per foot basis at about 212 Boe per foot. When you consider our standard development plan of 10,000 foot laterals, we could easily be talking about an EUR in excess of 2 million barrels equivalent in this area. Needless to say, given the success of our CRMWD 79-1H well, another strong performance in the area, we are allocating more of our second half 2017 drilling and capital to the Monument Draw prospect.

We recently moved 2 operated rigs to Monument Draw from our Hackberry Draw area in Pecos County. We are currently drilling a vertical pilot on the northern track of our acreage after which we will move the rig over to drill a 10,000 foot lateral on our northern acreage track. Similar to what we did on our Southern Tract assessment, we plan to run a series of log sweeps in this pilot to evaluate geologic and petrophysical properties in this area.

Our second operated rig, which recently finished drilling our seventh well in Pecos County, is rigging up on a location offsetting the CRMWD well in the Southern Tract of our Monument Draw acreage. We'll have these 2 rigs running for the rest of the year in Monument Draw area in Ward County. We will spud 7 additional horizontal wells during the second half of 2017 in this area and 4 of these wells will be put on line prior to year-end. These 10,000-foot wells in this area are expected to cost around $10.5 million. It should generate EURs of 1.4 million to 1.8 million Boe.

We have started the construction of an infrastructure required to adequately accommodate our activity in Monument Draw. We recently acquired surface acreage, which included 2 saltwater disposal wells. We'll drill 2 additional SWD wells this year and construct a water-recycling facility similar to our Prickly Pear facility in Pecos County. We are also planning to construct water and gas gathering lines in addition to electrical lines the second half of 2017 and lead again to '18.

Now to our Hackberry Draw prospect in Pecos County. We began drilling -- running 2 operated rigs here in mid-March. We drilled 7 wells here as mentioned previously and we have moved both of these rigs to our Monument Draw area in Ward County. Accordingly, we'll have a pause in our drilling in Pecos as our frac crew works on the backlog of wells drilled here over the last few months. We will bring a third operated rig back to Hackberry Draw area in Pecos County in October, and this rig will remain in this area for the remainder of 2017.

We currently have our first operated well flowing back after completion, with 6 additional wells waiting on completion. All these wells are 10,000-foot laterals and represent a combination of Wolfcamp A and B wells.

On the well that's flowing back now is the Balbo Adrianna West 1H, which is Wolfcamp B well drilled with a 10,000-foot lateral. This well began flowback last week and is cleaning up. It's still in its early days, but we're excited about the results thus far and given the pressures we're seeing. We expect to spud 11 gross wells in Hackberry Draw in 2017, with 7 of these wells put online before year-end. 10 of these 11 will be 10,000-foot laterals, with 1 5,000-foot lateral. These wells will be a combination of Wolfcamp A, B, and one Bone Spring well to be drilled as well. Our 10,000-foot wells in Hackberry prospect costs around $9.5 million and are expected to generate EURs of 1.1 million to 1.3 million Boe.

Similar to our efforts in Monument Draw with regard to infrastructure, we're constructing a second water-recycling facility here and continue to build out water and gas gathering lines. We have a long history of successfully building infrastructure and believe our expertise will serve us well as we develop our position in the Delaware Basin.

Thank you. Floyd?

Good, Jon, thanks. So a couple comments then we'll see if there's any questions. If you have it or you can get it later, I draw your attention to Page 6 of the presentation posted last evening. This concerns the Pecos County acreage, which we have called the Hackberry Draw prospect. We have north and south delineated on the map of the 26,000, 27,000 acres that we have in that area. 21,000 were in the north, Hackberry Draw project -- prospect and a little over 5,000 in the south. These 2 areas are divided based on geologic control that old wells, new horizontal wells and 3D seismic. So it's not to say that one is less prospective than the other. I will say we have a lot less acreage in the south prospect. It might be wonderful down there. There hasn't been any drilling. So I would, again, call your attention to the map.

Also on that map, we drew a weird looking figure and we'll change that because it's kind of disturbing, but it's the -- our view of the Wolfcamp deep sand potential here. It's about 1,000-foot deeper than the upper part of the Wolfcamp and sometimes a little more than that. It was widely developed in the past. A lot of really good wells. Important to note that these wells were drilled using old technology, all vertical, and we know for a fact that there's some good spots to drill, we can pick these spots well, using the 3D seismic. So more to come on that.

I'm not sure if the Jon mentioned it, but switching to Ward County for just a second, our Monument Draw prospect, we have also divided it to north and south. We've only done this, mainly because of the option nature of what we negotiated there. We believe that they're equivalent and both of the same exact quality. And again, I'm not sure if Jon pointed this out, but there's a lot more to come over in this area in terms of Bone Spring's, more than 1 Bone Spring zone in Avalon. We got a lot of work to do over here and we've seen some really good thick zones over there with -- they're just full of hydrocarbons. So there's more to come on that.

In terms of the future, Mark mentioned, we're guiding to 11,000 to 14,000 barrels(sic-see press release "11,000 to 14,000 boe/d") for the fourth quarter. We'll beat this. It's very conservative. But I'll mention that we'll put out formal guidance for 2018 later this year. I'll just tell you that I expect to more than double, nearly triple, exit rates '17 versus '18 quarter-over-quarter and you can do with that which you care to.

Our plan right now, we're going to run 3 rigs. 2 now and 1 -- add 1, as Jon mentioned, in the fourth quarter. The company will grow substantially with that and if we find that the crude prices drift down, we can grow the company substantially with fewer rigs, even 1 but 2 would be the most likely,and still generate significant growth.

That takes us to where we are today and where we are is our balance sheet's in great shape. We are on schedule to close this nice trade that we made on the majority of our Williston Basin property. We'll have significant liquidity here in a few weeks. We have plenty right now but we'll have many more then. And this has always been in a series of planned and disciplined steps to move our company to a basin -- from a different basin. The one basin, the Williston is one of the best in the world. We had great success there. I believe we led the league in terms of efficiencies and per-well production stats.

We had a significant backlog of Class A locations there, a couple of hundred on the fourth. If you view that in contrast with what we've already done out here in the Delaware Basin, it's nearly 2,000 Class A locations and we're not even counting all the spots that you probably will be drilling based on frac efficiencies and studies that are done in terms of recoveries and whatnot. So you pair the upside with a great technical team. You pair the technical team and upside with the liquidity in the balance sheet, and I think, we're in good shape to move forward. We'll continue to look for ways to improve our asset base. Improvement only mean, additional properties, it was as good or better than what we own, but we're in no hurry, we have no need to do, we have quite a bit of acreage now and right now, I think it's our job to execute on what we have and report that and see what we can do in terms of fine-tuning the thought process around how to complete these wells and how many wells to drill in a certain spot. I say, my opinion, it's a great time to think about our stock and that's all I need to say about that.

Operator, if there's any questions, we have time for some at this time.

(Operator Instructions) Our first question comes from the line of Brian Corales with Howard Weil.

Just a couple of quick ones. I saw at Pecos you tested several different zones. Are you all going to do the same thing kind of immediately with these 2 rigs in Ward County?

Initially, we're going to drill Wolfcamp wells, but we're already planning to test more than 1 level in the Wolfcamp. I think, we're planning on our Bone Spring's well this year, are we or -- in Pecos County? Ward?

It will be considered an upper Wolfcamp.

So yes, we're going to drill the, I think, 300 foot interval above what people are calling the Wolfcamp A and we'll drill wells in both the Wolfcamp A and B. One of our test, just north of our first well will be, I think, a 3-well pad that will have 660-foot spacing in the lower part of the A with a well 400-foot above it in the upper part of the A and that will be a real great test for us to see -- talk about, think about drainage and frac efficiency and so on.

Okay. And Floyd, you made some comments, double or triple the 4Q-to-4Q. Is that on a 3-rig program? Or is that adding rigs next year?

It's on a 3-rig program.

Our next question comes from Jason Wangler with Imperial Capital.

Maybe just a follow-up on that last question. As you look at the move, the 2 rigs up to Ward and 1 coming in to Pecos, how do you see as you head out into 2018 kind of a cadence of the rigs, kind of where they are, given how much how many locations you have down in Pecos?

We actually have a full plan laid out for '18. Jon and his staff have got that figured out. It's of course, dependent upon results after frac and flowback. But we do have some lease capture requirements down in Pecos County. They don't require a lot of rig activity. We're going to go to the area that does the best for -- most bang for the buck and proves up the most acreage. And right now, I think it would be half-and-half by the time the year's over.

Plus 2.

There might be 2 wells in Ward -- 2 rigs in Ward for a while and only 1 in Pecos. And there might be couple in Pecos and only one in Ward. They're very close together so we can -- that's an easy logistical thing to create a backlog of permits, which we already have and then we can just easily move from Pecos toward our back and have all rigs in one -- in either county at any one time. And we might find ourselves wanting to do that if we drill more pad wells.

That's helpful. And just curious, as we start to kind of think of it as more of pure play in the Delaware Basin, do you have an idea of what the LOE costs are down there? Just kind of -- just in the Delaware now and where you see those going as you start to get the infrastructure built out and the scale up?

So start to think of it as that, Jason, what's the holdup?

Well, I just mean that as we look to model -- as we start to model it without the Williston and without the nonop stuff and without the noncore stuff, so as we kind of think about it, past 2017, I guess, because obviously there's so much production in 2017 (inaudible)

I would have guessed, with your, how smart are you, you would have that all modeled by now but...

Well, I think I do, but you're probably smarter than me so I'm going with you.

No, I'm really not but it's probably sub-$4, but we'll say $4, maybe a little more, but it's sub-$4 out there.

Our next question comes from John White with Roth Capital.

If you don't want to get this specific at this point in time, I certainly understand, but would you be prepared to say how many wells you have at December 31 at Hackberry and Monument that have been drilled, completed, flowed back and would be called PDP well?

We can give you a pretty close estimate of that. It's always based on things somewhat out of our control, but Jon's got some numbers for that right in front of him.

John, so we'll have 7 wells in Pecos County. It will be PDP put online in -- for 2017. In Hackberry Draw area of Ward County, we'll have a total of 5 wells that are put on line for PDP.

Planning to drill.

We're planning to drill.

All right, that's helpful. And Floyd, I sensed either increased excitement or increased confidence when you talk about the subsurface well control at Hackberry North, is that correct?

Hackberry North and South, listen, that area is covered with old wells. We're surrounded by well over 30 newer horizontal wells. We have 3D seismic. We've got deep test and deep production down at the end of that sandstone in the deeper part of the Wolfcamp. So we have tons of control here, which in most other plays that we started in the past, we didn't have anything like that. So our confidence was high before we got going into this or we wouldn't have done it. It's higher now than ever. And I'm just feeling really good about our capacity now to move our technical prowess and our attention to this basin that we're confident, that we're going to do quite well in.

That sounds really great. On Slide 6, in Hackberry Draw South, you talked about -- you have bullet points on the Wolfcamp Deep. And one of the bullet points, it says sandstone targets. Is it a real sandstone?

Yes, it is not a shale that we're talking about that's been producted down there in the past. It's a sand and it's very porous and permeable compared to a shale. You could drill it horizontally though, but you might not need to, it might just be fine to drill vertical wells there. And keep in mind that vertical wells,hold acreage is easily as horizontal wells do. So we have a way to utilize a drilling program throughout our acreage, North and South, to better the entire package. In the South, since there's been so little drilling down there in the upper part of the Wolfcamp, we can utilize the deep test down there, a fairly inexpensive vertical test as a pilot well in the upper Wolfcamp, which we just don't have down there. We've got the logs but we don't have a modern pilot well with a full modern suite of logs in the lower -- in the upper Wolfcamp and that Hackberry Draw South. So we're pretty excited about the way this is all turning out.

Well, it gets better with every question I asked. So the Bone Spring play, I inferred from your previous comments, there's a bunch of vertical wells and old electric log that you can work with on the Bone Spring?

Well, better than that, and my comment was about Ward County, in particular, we have a wonderful Bone Spring's section, which is basically round top of the Wolfcamp. You can't really tell it apart. But down here in Pecos County, we've got a Bone Spring's horizontal well offsetting this. It's been there for a few years. There's a brand-new well drilled by one of our great peer operators, a little bit north of us, I think about 3 wells, it looks like it's as good as any Wolfcamp well in that region. So listen, we're very excited about the Bone Spring's in both areas. And in particular up in Ward County, there's Bone -- several breaks in the Bone Spring's and the Avalon. So again, there's a lot of work to be done in all that. It's a large inventory of ideas and places to go and since we're basically somewhat constrained by oil prices. This will have to take a pace and a cadence that makes sense with -- where the strip looks -- what the strip looks like.

Our next question comes from Vivek Pal with Seaport Global Securities.

I was just wondering, back on 2018, can you maybe help us think about how much non-D&C CapEx we should be thinking about?

It's not too much. I think, it's maybe $15 million or -- $15 million for seismic and -- it's $45 million or $50 million all in. There's some seismic and some other stuff, infrastructure and keep in mind, that our infrastructure is largely laid out in Pecos the spine of it. In Ward, we're -- as we drill, we'll lay out a spine up there, a bigger pipe, so that then in the future, connections will be less -- not that expensive, once we do that heavy lifting in the early stage of the development of the field. So there's $15 million or so for seismic maybe and $30 million or $35 million for infrastructure.

That infrastructure is a major opportunity for us too, by the way. There's a lot of interest in that. It's valuable even as we sit today, we have a lot of calls about it. In the past, we've done well by developing that ourselves, at least, in the initial stages. We'll just have to see how that plays out here. But it's an asset that is, as I've said, already quite valuable.

Yes, yes, absolutely. And then maybe, I was hoping, can you maybe comment on just your well costs where they are right now and kind of what that trajectory looks like as you get into more sort of full development mode?

I'd like Jon to comment on that, but we've certainly seen some large increases over the past 6 and 8 months and well costs out here largely pumping costs and sand costs and whatnot, but the trajectory, generally speaking or traditionally speaking, the trajectory should follow the strip as it corrects itself. So the strip is not particularly constructed at the moment so you wouldn't think that the trajectory of these to be up, up and away if rig count stabilizes or goes down significantly. You're going to find that those service costs will start to correct themselves as well. Jon, go ahead. You're on top of that.

All right. Floyd, I think just to add to that, if you look at the trajectory over time, with our efficiencies gain -- efficiency gains, you always see -- you'll see overall costs come down, all other things equal. So that's what we're seeing. And what we saw in the Bakken as well is that they went to full pad development. We're able to take a pinch and see a batch drilling on our drilling side as well as the infrastructure on the facility side, which generally, in those cases, decreased our well costs roughly $1 million. So there's going to be a lot of gains here on the drilling side as we become more efficient. Already, we've seen our significant gains in the last few months in our -- with our drilling times as they've come down. We'll have other efficiencies come into play when we go to pad drilling. So we're excited about that just as any play when it's -- we're working through a learning curve and just as the industry is and you'll see costs come down all other things equal.

Our next question comes from the line of Jacob Gomolinski-Ekel from Morgan Stanley.

So as you look at some of the offset operators like Diamondback, who also posted well results, in Pecos County, just curious on your thoughts on Pecos first county a little bit further west in Delaware or counties in the Midland Basin, and what you think it might take to really derisk it in terms of folks' perception of the acreage really similar to what you're highlighting in Slide 14?

Derisk it in terms of our acreage?

Yes, and then, basically, outsiders' perception of that acreage quality. I mean, I think it's reflected in what you're pointing out in Slide 14.

Yes, I haven't really noticed that slide before. It seems like a travesty as I look at it right now. In fact, I hope that you'll take steps to correct that maybe starting today. Yes, just in the south part of that area, there's been so little drilling and even further west of us in south, there's very little drilling. It's a normal thing for people to say, drills, let's get some wells in there, and that's how we feel too. As I point out, the bulk of our acreage there is in the northern section and we didn't divide those by mathematically we divided them geologically and geophysically. So if you want to derisk, if you want us to derisk that other, that 5,000 acres in the south, we will do that, and we're highly confident it will be good. But our opinion is we've 100% derisk everything that we call our Hackberry Draw north, and I said that's based on old well control, 35 or more new horizontal wells by our predecessor operators and others and 3D seismic. So I mean that's -- those are the things that we use to judge acreage on and, I think, that will catch up. So probably the answer to question is, just do some drilling results, oil in the tanks.

Got it. And then, given your 20-plus years of inventory at current rig count, you've also -- but then you've also got the $567 million of cash, just curious how you think about the cash with respect to asset purchases or uses like funding cash outspent as you develop your existing acreage?

Well, at this moment, we believe our job is to bear down on what we own and get oil in the tanks, as I said. And if there is some thoughts out there that some of our acreage isn't very valuable, we like to dispel those as quickly as we can. However, we're always interested in what's going on around us and we've had the same, same thought process as we've had in our entire careers that we don't add anything unless it's as good or better than what we already own as we judge it. And we're very good judges of that, we use science, not land maps or road maps like some guy said, try to put in their presentations. So right now, we're going to focus on taking our technical skills to this area, which we already have done and doing well. And we're going to keep looking. We do have capacity and we'll just see how that goes. But right now we're going to do what we're doing here and that's drill good wells and build our production quickly and dramatically and hedge along the way, because we still don't have a clue about the world and all this supply/demand. I read that the Permian basin is now the driver of global crude oil prices. If that's really the case, I'm really worried because there's a lot of grease out here. But we're hedging right along and we're going to keep the balance sheet in line. We've got a lot of cash, and somebody might think in my background that's we're just run out and spend it. This is not the case.

Got it. That 's great. I think, just as a quick follow-up, last question. In terms of if you are thinking kind of using that cash to develop what you got and maybe it's a question for November, but do you have a sense of what the cash outspend might look like on a 3-rig program if in 2018 at kind of current prices?

We know exactly what it looks like, if the strip...

Yes, strip.

We know exactly what our spend will be within probably 5% or 10%, but we're not putting those numbers out right now. The run rate of the fourth quarter would answer your question, should be...

Yes. Yes, I got my math. I just wanted to confirm maybe with you guys, but that's great.

Our next question comes from Mary Willis with Johnson Rice.

All my questions have been answered. Thanks.

Our next question comes from the line of David Epstein with Cowen.

Early July, on your M&A call, you guys had given a little color about G&A coming down. Just as you guys have sort of updated how active you're going to be. Any new thoughts on what your total G&A and maybe your unit cost G&A will be for next year?

Listen, we're clearly, we're a smaller -- our denominator is smaller than it used to be. We have a target -- I'm being shown a number here, so it won't be -- that's when -- so this is way preliminary. We're thinking it's going to be between $6 and $8 a barrel. Oh no, well, I can't read. $5 and $6 a barrel in '18. I hate to call that guidance because it is way preliminary. We're making some adjustments as we speak. Our adjustments are a little different than some people. G&A's immensely important. But to us well results and technology and science and the digestion of the science and keeping your coverage ahead of your rigs, that's tremendously more important to me. So we're making adjustments. We'll get the G&A down, it's happening as we speak. It will be reasonably in line for next year. And it is a focus of our -- I tell you, an additional, immensely important focus is results.

And I'm showing no further questions in queue at this time. I'd like to turn the call back to Mr. Wilson for any closing remarks.

Well, listen, those are actually some really good questions and thanks for dialing in and we're here if you need to talk to us about something else.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the program, and you may now disconnect. Everyone, have a great day.