Battalion Oil Corporation (BATL) Q2 2017 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen and welcome to the Halcón Resources Second Quarter 2017 Earnings Conference Call. At this time, all participants are in a listen-only mode. [Operator Instructions] Later, we will conduct a question-and-answer session and instructions will follow at that time. As a reminder, today’s conference maybe 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 was 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, $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 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’s sell of El Halcón 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 sell of production associated with the El Halcón transaction in Q1. Overall our total current quarter operating cost adjusted for selected items was $18.58 per Boe looking forward and pro forma for the Williston Basin sales, we expect our overall operating cost metrics to improve as we transition from a higher operating cost environment and 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 second rig in the Williston Basin in April, we had two rigs running for the full year, Delaware. We also spend about $7 million on infrastructure and seismic in the current quarter. With regard to hedges, we realized the net gain unsettled derivative contracts of about $6 million during the second quarter versus $2 million, in the first quarter of 2017. For the last six months of 2017, we have 21,250 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 20,000 Mmbtu of gas hedge 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 will add hedges, 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 Shale. We had just under $700 million of liquidity, which consisted of cash on hand plus a new undrawn senior secured credit facility. We are 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 sale. 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 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. First operated well in Delaware Basin was drilled in the Southern tract of a 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 well on a 2 stream basis. Its 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 can easily 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 Monument Draw Prospect. We recently moved two operated rigs to Monument Draw from our Hackberry Draw area in Pecos County. We are currently drilling a vertical pilot on the Northern tract over acreage after which we’ll move the rig over to drill 10,000 foot lateral on our Northern acreage tract. Similar to what we did on our Southern tract assessment, we plan to run a series of logs reaching 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 ringing up on a location offsetting the CRMWD well in the southern tract of our Monument Draw acreage. We'll have these two rigs running for the rest of year in Monument Draw area in Ward County. We will spud seven additional horizontal wells during the second half of 2017 in this area and four of these wells will be put online prior to year-end. These 10,000 foot wells in this area are expected to cost around $10.5 million and should generate EURs 1.4 to 1.8 million Boe. We’ve started a constructive infrastructure require to adequately accommodate our activity in Monument Draw. We recently acquired surface acreage, which included two salt water disposal wells. We’ll drill two additional SWD wells this year and constructed 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 electric lines, the second half of 2017 and leading on to 2018. Now to our Hackberry Draw Prospect in Pecos County, we begin drilling, running two operated rigs here in March. We drill seven wells here as mentioned previously. 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 backlog of the 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 six additional wells will be on completion. All these wells are 10,000 foot laterals and represent a combination of Wolfcamp A and B wells. Another well that’s flowing back now is the Balbo Adrianna West 1H, which is Wolfcamp B well drilled in with 10,000 foot lateral. This well began flow back last week and is cleaning up. It's still in its early days we're excited about the results thus far given the pressures we're seeing. We expect to spud 11 gross wells in Hackberry Draw 2017 with seven of these wells put online before year-end. 10 of these of 11 will be 10,000 foot laterals with one 5,000 foot lateral. These wells will be a combination of Wolfcamp A, B and 1 Bone Spring well to be drilled as well. Our 10,000 foot wells in Hackberry Prospect cost around $9.5 million and are expect to generate EURs of 1.1 million to 1.3 million Boe. Similar to our efforts in Monument Draw with regard to infrastructure, we are 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 Delaware Basin. Thank you, Floyd?

Great, Jon. Thanks. So couple of comments, then we'll see if there’s any questions. If you have it or 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 delineate on the map. Of the 26,000, 27,000 acres that we have in that area, 21,000 are in north Hackberry Draw Prospect and a little over 5,000 in the south. These two 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 perspective than the other, I will say we have a lot less acreage in the south prospect. South it might be wonderful down there, just hasn't been any drilling. So I would again call your attention to the map. Also on that map, we do a weird looking figure and will change that because it's kind of disturbing but it's our view of the Wolfcamp deep sand potential here, its 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 the old technology, all vertical and we know for a fact that there is some good spots to drill, we can pick the spot well using the 3D seismic, so more to come on that. I’m not sure if 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 auction nature of what we negotiated there. We believe that they’re equivalent and both of the same exact [Audio Dip]. And again, I’m not sure that Jon pointed this out but there is a lot more to come over in this area, in terms of Bone Springs, more than one Bone Spring zone in Avalon. We've 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 for the fourth quarter, we’ll beat this it sets very conservative. He's going to put out – mentioned that we’ll put out formal guidance for 2018 later this year. I'll just tell you that I expect more than double nearly triple exit rates 2017 versus 2018 quarter-over-quarter and you can do with that what you care to. Our plan right now we're going to run three rigs, two now and one, that one 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 one or – even one but two would be the likely still generate significant growth. That takes us to where are we today and where we are is our balance sheets in great shape. We're 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 more then. And this all has 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 Fort. If you view that in contrast, we’ve already done out here in the Delaware Basin to 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 the great technical team, the technical team in outside with the liquidity and the balance sheet. And I think we're in a good shape to move forward we'll continue to look to ways to improve our asset base, improve it only mean additional properties it was as good as 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 drilled 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.

Good morning, guys. Just a couple of quick ones, I saw a Pecos start test in a several different zones, are you not going to do the same thing kind of immediately with these two rigs and then Ward County?

Initially, we are going to drill Wolfcamp wells but we are already planning to test more than one level in the Wolfcamp. I think we are planning on our Bone Springs well this year, are we?

In Pecos County?

Ward.

It will be considered an upper Wolfcamp?

Yes, we are going to drill the – I think 300 foot lateral interval above what people are call in 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 would be I think the three well pads it 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 really 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, 4Q to 4Q, is that on the three rig program or is that adding rigs next year.

It’s on a three rig program.

Okay, all right. That’s all I have. Thanks guys.

Our next question comes from Jason Wangler with Imperial Capital.

Good morning, maybe just a follow-up on that last question. You know as you look at the move the two rigs up to Ward and one coming into Pecos, how you see as you look at 2018 kind of the cadence of the rigs kind of where they are given how much – how many locations you have done in Pecos?

We actually have a full plan laid out for 2018. Jon and his staff has got that figured out, it's of course dependent upon results after frac and flow back 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 – the most bank for the buck and cruise up the most acreage. And right now I think it would be half and half, by the time the year's over.

Close to it.

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

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

Start to think of this is that Jason, what’s the…

If we look the model – as we start to model it without the Williston and without the non-op stuff and without the non-core stuff. So as we kind of think about it, past 2017 I guess because obviously there are so much in 2017…

I would have guessed with your – you would have their own model by now.

I think I do but you’re probably smarter than me. So I’m going with you.

I’m really not, but its probably sub $4 but we’ll say $4 maybe a little more but its sub $4 out there.

That’s helpful. Thank you.

Our next question comes from John White with Roth Capital.

Good morning and thanks for taking my question. 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 then, 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 seven wells in Pecos County that will be PDP put online for 2017. In Hackberry Draw area of Ward County, we’ll have a total of five wells that are put online or PDP.

All right, that’s helpful. And Floyd, I sense the either increased excitement or increased confidence, when you talked about the well, subsurface well control at Hackberry north is that correct?

Hackberry north and south, listen, that area is covered with old wells which 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 just – we have tons of control here which in most of the place that we started in, in the past we didn't have anything like that. So our confidence was high before we got going into this, we want to done it is 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.

Thank you. That sounds really, really great. On Slide 6 Hackberry Draw south, you talk about, yes, bullet points on the Wolfcamp B and one of the bullet points it says Sandstone targets, is it a real Sandstone?

Yes, it's not a shale that we're talking about this has been productive down there in the past. It's the sand and it's very porous and permeable compared to a shale, you could drill it horizontally though. But might not need to, just fine to drill vertical wells here and keep in mind the vertical wells called acreage just as easily as horizontal wells do it. So we have a way to utilize a drilling program throughout our acreage north and south to better be in 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 it deep test down there a fairly inexpensive vertical test, as a pilot of 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 the full modern suite of logs in the lower, in the upper Wolfcamp in that Hackberry Draw south. So we are 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 like old electric logs that you can work with on the Bone Spring.

Well, better than that. My comment was about Ward County. In particular, we have a wonderful Bone Springs 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 Springs horizontal well offsetting us its 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 three well it looks like as good as any Wolfcamp well in that region. So listen, we're very excited about the Bone Springs in both areas and in particular up in Ward County – several breaks in the Bone Springs and the Avalon. So again, there's a lot of work to be done on all of 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, its make sense with what the strip looks like.

That’s a great detail and very informative. And I appreciate it. Thank you.

Welcome.

Our next question comes from Stephane Aka with Seaport Global Securities.

Good morning, guys. Thanks for taking my questions. I was just wondering back on 2018 can you maybe help us think about how much now D&C CapEx, we should be thinking about?

It's not too much I think it's maybe $15 million. $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 take us the spine of it. In Ward as we drill, we’ll lay out on a spine up there a bigger pipe. So that in the future connections will be 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 in $30 million or $35 million for infrastructure.

Understood.

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 said today we have a lot of calls about it. The past we've done well by developing that ourselves at least in the initial stage – in the initial stages, we just have to see how that plays out here but it's an asset that is as I said already quite valuable.

Yes, absolutely. Thanks for that. And then maybe I was hoping could you maybe comment on just your cost where there 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 six and eight months in well cost out here, largely pumping cost and sand cost and whatnot. But generally speaking or traditionally speaking the trajectory should fall off the strip as it corrects itself. So the strip is not particularly constructive at the moment. So you wouldn't think that the trajectory of these would continue to be up and away. If rig count stabilizes or goes down significantly, you’re going to find those service costs will start to correct themselves as well. Jon, go ahead and you're on top of all that.

All right, Floyd, I think just to add to that. If you look at the trajectory over time, with our efficiency gains we see, you’ll see overall cost come down a lot of things equal. So that's what we're seeing, I'm always saw on the Bakken as well is that we went to full pad development we are able to take [indiscernible] of batch drilling or drilling side as well as construction on the facilities side which is generally in those cases, decreased our well cost 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.

Got it. Appreciate the color. Thank you.

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

Hey, guys. Thanks for taking the questions. As you look at some of the offset operators like Diamondback will also posted well results in Pecos County just curious on your thoughts on Pecos first county a little bit further west in the Delaware or counties in the Midland Basin and what you think it might take to really de-risk it in terms of folks perceptions 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 and 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 will take steps to correct that maybe starting today. Yes, listen, in the South part of that area, there's been so little drilling and even further West of us and South there's very little drilling. It's a normal thing for people to say drill – 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 divided them geologically and geophysically. So if you want to de-risk – if you want us to de-risk 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% de-risked everything that we call our Hackberry Draw north. And I said it's based on old well control 35 or more new horizontal wells by our predecessor, operator and others, and 3D seismic. So I mean that's – those are the things that we used to judge acreage on and I think that they'll catch up. So probably the answer to your questions is just based on drilling results oil in the tank.

Got it. And then given your 20 plus years of inventory at current rig counts, 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 outspend 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 is in very valuable we'd like to dispel those as quickly as you can. However, we're always interested in what's going on around us and we’ve had the same thought process as we've had in our entire careers, that we don't add anything unless it is good or better than what we already own. As we judge it, and we're very good judges of that new 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 it 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 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 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 little worried, because it has a lot of – there's a lot of grease out here. But we're heading right along and we're going to keep the balance sheet in line, got a lot of cash and somebody might think in my background that we just running out and spending best is not the case.

That's great. I think just as a quick follow-up – last question in terms of, if you're thinking kind of using that cash if develop here 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 three rig program, if in 2018, at kind of current prices?

We know exactly what it looks like if the strip.

Yes.

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

Yes, I got my math, I just wanted to confirm with you, may be with you guys, but that's great. Thank you so much, guys.

Our next question comes from Mary Willis with Johnson Rice.

Hi, good morning guys. All my questions have been answered. Thanks.

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

Hi guys, early July on your M&A call you guys have 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 or denominator smaller than it used to be. We have a target and being shown a number here, so won’t be – so this is way preliminary, we’re thinking it’s going to be between $6 and $8 a barrel.

$5 and $6.

No, why can’t we, $5 and $6 a barrel in 2018. I didn’t 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 is immensely important – G&A is 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 the focus of ours. I’m going to tell you, an additional immensely important focus is results.

Thank you.

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.

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