Battalion Oil Corp (BATL) 2016 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Halcon Resources fourth-quarter 2016 earnings conference call. (Operator Instructions). As a reminder, today's conference may be recorded.

I would like to introduce your host for today's conference, Mr. Mark Mize, Chief Financial Officer. Sir, please go ahead.

Okay, thank you. Good morning. 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 fourth quarter, which can also be accessed on our website.

I'll start the call with a few comments on our financial performance for the fourth quarter, then I'll turn the call over to Floyd to discuss A&D activities and operations.

Production for the fourth quarter averaged 38,620 barrels of oil equivalent per day, which was in line with our guidance range of 38,000 to 39,000 for the quarter. Our realized fourth-quarter oil differential of 89% of NYMEX was in line with differentials in the third quarter. Our fourth-quarter natural gas differentials improved over the previous quarter, and came in at about 80% of NYMEX.

For 2017, we do expect our differentials to be approximately 90% for oil and 85% for gas. That is based on the current strip.

LOE expense was $5.23 per BOE in the fourth quarter which was -- compares to about $5.17 per BOE in the third quarter of 2016. And taxes other than income came in at $2.87 per BOE during the fourth quarter versus $3.06 during the third quarter. Gathering and other, after adjusting for selected items, came in at $2.54. G&A came in right at $3.96 per BOE in the fourth quarter versus $4.21 in the third quarter of 2016.

Overall, total operating cost, after adjusting for some selected items, was $17.06 per BOE in the fourth quarter versus $17.33 in the third.

With respect to D&C CapEx, we incurred approximately $44 million during the fourth quarter, bringing our total 2016 D&C spend to $175 million. We did bring on 16 operated wells in the Williston Basin in the third quarter with an average D&C cost of $5.5 million per well, which does compare favorably to the type curve D&C cost estimate of $5.9 million.

Regarding hedges, we realized a net gain on settled derivative contracts of $62 million this quarter. For 2017 we have 18,750 barrels per day of oil hedged at an average price of just over $55 a barrel. For 2018, we have right at 4,000 barrels a day of oil hedged at an average price of $55.25 per barrel. We will continue to monitor the strip in 2017 and 2018, and we'll periodically add hedges for the next rolling 18 to 24 months of expected production.

As of December 31, and pro forma for our recent A&D and capital market activities that we've previously announced, we have right at $700 million of liquidity. Our next borrowing base redetermination is scheduled for May of this year, and we expect that our borrowing base will increase from current levels.

We continue to target a leverage profile of less than 3 times EBITDA, and we expect to achieve that leverage level by the end of 2018, based on current strip prices.

Our earnings release issued yesterday provided some comprehensive financial and operational guidance for 2017. I will highlight, as one would expect, that there will be a production decline going into the second quarter of 2017, driven by the sale of El Halcon which produces right at 5,500 BOE a day. That transaction will close in early March. And the production ramp from the Delaware Basin program will start to replace this production in the second half of this year.

We'll also ramp up completions in the Williston Basin in the second half of this year as weather conditions improve. And based on this back-end-weighted completion schedule, we expect to exit 2017 with production in excess of 42,000 BOE a day, which will set the Company up very nicely for production growth in 2018.

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

Thanks, Mark. So fourth-quarter 2016 was a quarter where we were quite busy setting our plans in motion for 2017 and beyond. Just to recap a little bit: in just a few months we have transformed our financial setting at Halcon, so much so that today we have an undrawn $600 million revolver and $100 million in cash. We have pushed our maturities out a number of years.

In just a few months, we've transformed our operational setting also. We've left one basin and we have entered another, and we are already drilling in our new basin, the Delaware. We've acquired three high-potential Permian blocks and dramatically added to our inventory.

Now for some actual exciting news. In Ward County in the Delaware Basin, we finished our first well, a vertical well in the southern end of our acreage. The only thing surprising about that well is that it had -- it has four strong pay zones, all much better than we expected, and our expectations were high. There are several other zones of interest as well.

We are already drilling the horizontal well from the same location, our [CRM WD79-1H]. This well will go in production during the second quarter. It's going to be a 5,000 foot lateral targeting the Wolfcamp at about 10,800 feet. As in much of the Delaware Basin, the upper section of the Wolfcamp is not geomechanically separated. So in about 650 feet of Wolfcamp at this place in our acreage, we have three distinct landing zones. These are dependent on spacing and pad design, of course.

We also found about 300 feet of high-quality third Bone Springs. So one landing zone there, and we have several opportunities up-hole from the third Bone. Our Wolfcamp and third Bone zones all look equally as good. I expect our CRM WD79-1H to be one of the best wells in this part of the basin.

If you think about what we've got here, think about 200 to 400 locations that at today's strip provide up to $10 million of PV10 per well. This is an exciting inventory add. We will drill our first well in the northern part of our acreage next quarter.

Over in Pecos County, we've acquired over $750 million worth of high-potential acreage. In fact, we closed on this yesterday. We're making locations a day and we are moving two rigs in next Wednesday. Who does that? So in Pecos County, it's full speed ahead. We are moving two rigs on our first two locations next week. Both are planned to be 10,000 foot laterals: one targeting what we'll call the Wolfcamp A, and one targeting the Wolfcamp B. Again, the Wolfcamp is not geomechanically separate in this area, so this A and B business is for convenience.

We have another Wolfcamp landing zone here between the two zones I just mentioned, as well as several opportunities in the Bone Springs. Hundreds and hundreds of great development locations ahead of us here. We plan to run two rigs drilling horizontal wells in the Delaware Basin for the balance of this year, and add two rigs in 2018 for a total of four. We will include several Bone Springs wells in our schedule this year in both Pecos and Ward Counties.

We also have exciting news in the Williston Basin. The news is that -- this news is that our results continue to be uniformly awesome. We are drilling some of the best wells we've ever drilled. In fact, we have one area in the Williston Basin we have not drilled any new generation wells due to the limited natural gas takeaway. We have about 40 locations in this area where we think each well will make 1.5 million barrels.

As we work on infrastructure, you may see us re-injecting gas in this area to jump-start development.

We currently have one rig running in North Dakota. We plan to add a rig early in Q2, and continue with two rigs for the balance of 2017 and throughout 2018. This is a wonderful, steady asset, with wells economically competitive with any other basin. And we are drilling our wells there today for about $5.5 million apiece.

Our overall strategy is unchanged. We'll grow our core acreage position substantially as we continue to develop a large inventory of de-risked, highly economic drill sites; drill sites, important to us, that compete economically with one another. At some point in the future, we'll look to find a home for our wonderful assets of our Company in a larger entity at an attractive level for our stakeholders. But that's in the future.

For now, we'll add a few rigs here and there. We'll aim to grow production to over 60,000 barrels by year-end 2019, all from our current assets; and we'll be cash flow sufficient by then also. We have a solid five-year plan that takes us to levels well beyond today. We'll continue to focus on cost and economic returns. We've put in the press release we are raising our estimate of CapEx slightly for this year to $300 million. We've slipped a few extra wells into our schedule.

By the way, our proved reserves at year-end 2016 figured on the strip price at 1-31-17 are 10% higher by volume, and the PV10 is double the year-end SEC number.

You should look for us to grow production and revenue rapidly, continue to build our hedge book, and carry on with acquisitions that make sense to us, and look for us to do all of this at hawk speed.

Operator, we are ready for questions now, if there are any.

(Operator Instructions). Will Green, Stephens.

Thanks and good morning. I know it's early days in the Delaware, and you guys are still just getting going there. But obviously just as -- just the production, the extra production volumes help. But as this gets going and if it works to your expectation, is this potentially something that drives these unit costs down, even on an apples-to-apples basis?

I guess what I'm getting at is, do you expect this is going to be a less costly basin to maintain production on, going forward? And do you have the G&A already in the system to kind of maintain a much bigger rig count down there?

Taking that second part first, we've got plenty of staff to do what we need to do there. In fact, we are doing it now. We are already planning for the rigs for 2018. And we're making everything -- we're making sure that we are sufficient for that, and we are. Cost; you are talking about cost in the Delaware Basin. Our first few wells are all going to be $8 million to $9 million.

Yes, costs will go down over time. Drill -- rig days will go down. Some other costs will go up, and we are keeping a steady finger on that pulse. I think that over time, the history of all the basins and certainly anywhere that we've worked has been a steady improvement in cost metrics. We would expect that here as well. I don't think with just running a couple of rigs, it will happen overnight. But certainly by year-end 2017, we should be looking at a different AFE than we are looking at today.

Great. And then just on the LOE side, obviously the production volumes help as you guys add extra production on. But on just a straight apples-to-apples basis, LOE, do you expect that this is a less costly basin to maintain going forward on an LOE basis?

Yes. And it's easy to figure. First off, I'll tell you that Mark and the guys here, a bunch of crazy sandbaggers, will beat that number. Second, the Williston Basin is more mature. All the wells are on [rod lift] by now -- not all of them, but almost all of them. Early days in any new basin, the operating costs are quite a bit lower.

The difference in the Delaware is that you have a little more water than you do in some shale plays in the beginning. So you do have a component there that's quite different from other areas that you have to keep track of. But, yes, you would expect this to be, as we shift from heavily weighted Williston production to heavily weighted Delaware production over a couple of years here, you will find that the LOE will track down dramatically.

Great. And then I wanted to get your take on some of the improvements. A number of other operators are seeing up in the Bakken -- it does look like you guys are doing -- I guess you guys are calling it an optimized completion test over in Williams. I wonder if you could update us on what exactly you are doing. I think you are already at kind of 500 pounds per foot, but we've seen a lot bigger tests in the basin. I wonder if you could just give us some additional color on what you think -- what's going on in the basin, and how you see it playing out for you guys.

Let's start with -- we started optimizing completions a few years ago. Many of our great peers are sort of just getting into that now. And just to keep it clear, we make better wells than anybody in the basin, period. And we have been for a long time. The difference between how much proppant you use has to be a strict calculation. The economic calculation is based on diminishing returns. And the rest of it is based on experience and history of what's going on.

So we've done plenty of frac jobs at 1,000 pounds. We've done them at 750 pounds. We've done them at 500; we've done some at over 1,000 pounds. So far, we're finding that we're making great wells in great rock with less expense in these lower levels. And I don't want to say too much, but some of the huge volume of sand that we've seen require an unusually robust B factor to achieve the results that some people are hoping for. And, history will tell on that. So this whole business of economic returns has to do a lot with how much proppant you are going to use, and so on, in the early days.

So while we don't know that 500 is the perfect number; and like I said, we've done a lot of wells at 1,000, a few wells at more than that, we'll continue to watch all of our great peers there and take information from them and share our information with them. And ours will continue to progress. But as I said, we are making wells that are basically carbon copies of each other at 1 million barrels like every day. It's hard to kind of -- hard for me to assess our ability to really improve that a lot. It's possible.

I appreciate that color. Maybe just one more. Do you feel like -- in the same line of thinking -- do you think that changes kind of the infill opportunity for you guys versus another operator that may be putting a more intense frac on these?

I don't know about that. Again, if, in the past, you spent more money on a well than you needed to spend but you still have a good well, that's kind of in the past. So there's always, when a new person comes in on an asset on some properties, there is always some opportunity to do things a little bit differently, and hopefully to improve things. As far as giving us an advantage or whatever, we'd like to think so. But listen, the people that drill in the core of the field up there are all doing really good work. It's just that we do really good work ourselves.

Great. Thanks for all the color, guys.

Jason Wangler, Wunderlich.

I noticed the two wells added onto the CapEx is side. I was also curious because you were able to pick up some acreage as you look at drilling some longer lateral wells. Was that just a shift in where or what you want to drill? Or did that help from the acreage pickup?

It helped a little bit from the acreage pickup in Pecos County. And Jon is on the call here. But he planned and we plan to drill 10,000 foot laterals right out of the box, everywhere we can. It didn't line up that properly to do that in Ward County. But our next well will be 10,000 feet for sure in Ward County. So we are planning on drilling 10,000 foot laterals everywhere we can. As you know, we drill them every day up in the Williston Basin with great results, and we don't see that that's going to be a big issue for us.

Okay. And maybe just kind of a side question. You have some standby costs on the rigs but obviously you are adding some rigs here. Will we see those come down or maybe even go away, going forward, as you pick up these rigs and get back to work with -- especially as you go for the Williston more?

I'm trying to remember if we've revised. I think we're getting some of that standby money back as we bring new rigs on. I don't know if it's 25%, 30% of the standby money, something like that. Those rigs that are -- we are paying standby money on were commissioned in 2013 and early 2014. And so we are paying standby money and we're getting some of it back.

But the new rig rate is $10,000 to $13,000 per day less than it was then. So we are getting that -- that is a differential. I think we ran out of all the standby stuff this year, right?

Very little in 2018.

Maybe a little bit in the first few months of 2018, but all of it is running out this year.

Okay, great. I'll turn it back. Thank you for the color.

John White, ROTH Capital.

Good morning, and congratulations on your Ward County pilot well. I wondered -- in the press release, you called the third Bone Springs a carbonate. Is it a true carbonate or is it shaly carbonate? If you could give us a little more on the lithology I'd appreciate it.

John, I didn't write that press release.

Jon Wright, why don't you address that? Thank you.

Thanks for the question, John. It's a carbonate. There is also shale intervals as well. So, it's not much different than what you'd see outside of Ward County or the Delaware. In the zone.

Okay. All right. Thank you very much.

Vivek Pal, Seaport Global.

I was looking at your cost structure. And it seems like, based on your guidance, your unit costs are going to go up to $21 from roughly $17 in 2016. And I'm assuming half of it is because of higher production taxes because of higher commodity prices. But still the $2 that you are seeing increase year-over-year -- whereas in the industry most of the people are seeing costs flat to slightly down -- is because of what gathering contracts and higher LOEs if I'm -- is that a fair assumption?

Yes. It's a couple of things. Number one, we do have a pretty flat year-over-year production profile. So versus our peer group who have most -- because of the disposition of the Eagle Ford assets, our production year-over-year is flat. So we are not getting the benefit of a large ramp year-over-year in production that a lot of our peers are that drive down the per-unit costs on LOE and other items.

The other thing I'd say is the way that we structure our gathering, transportation, and operating line item is dependent on how the oil is gathered in the field. And some of those contracts changed late in 2016, whereas before we would've captured that as a differential cost, meaning a reduction to our revenue. Looking forward into 2017, it's going to be captured on the line item gathering, transportation, and other. And that's about $1 per barrel.

So, it's a net zero impact because our differentials will be about $1 higher. Our GTO will be about $1 higher. So, the net impact on our cash flow and revenue and profitability is negligible. It's just an accounting kind of adjustment going forward.

So the $1 increase in GTO is offset by a higher realization in Bakken. Is that what it is?

Exactly.

Okay. And the LOE is just higher because of you spending more in Delaware, is that what it is? As you mentioned earlier?

Again, as Floyd mentioned earlier, our Bakken asset is a mature asset. There's a lot of workover expense in that asset. And so in 2018 and 2019, we expect LOE to come down by more a barrel as we grow our production in the Delaware.

And now based on your equity issuance, you have the option to take out one-third of your still outstanding 12% second lien notes, right? I think the total is $113 million is outstanding. Are you still planning to do that, or are you going to use that money to buy that option that you have?

We haven't fully come to that conclusion. We do have that ability, and we are thinking through it. It's not a troublesome piece of paper. It's quite small. And we are quite intent on adding assets in this great basin in the Permian and the Delaware Basin.

Okay. All right. Thank you very much.

Sean Sneeden, Oppenheimer.

Floyd, I know you had mentioned that the general plan is to run four rigs in the Permian. But could you help us maybe think about how you are approaching the Williston next year? Is the [gold] going to run 1.5 again next year going to keep the Williston flat? Or how are you thinking about that?

Williston will continue to grow. We'll have two rigs running for most of next year and a lot of this year. So, the Williston will continue to grow from its current level of around 30,000 net barrels a day for the next several years. It's -- a lot of people don't really think about it, but it's an awesome asset. And with just a very lightweight capital intensity, we can keep that growing. So we could shift money from there to the Delaware as we get into a more mature development drilling situation there, because we have no lease expirations or any fear of losing any lands in the Williston Basin.

Right now, next year we'll be at four rigs in Delaware and two rigs in the Williston. But plans are made to be broken by opportunities. And we are going to be super highly focused on where the best money can be spent. Right now, it's four and two. We'll see what really goes on as we get through this year.

Okay. That's helpful. When you think about funding for next year, I think previously you had hoped to try to run relatively free cash flow neutral. Just given the four and two plan there, the expectation at this point you are going to use some of the dry powder on the revolver. Or how do you guys think about funding any deficit in that sense?

Through all this business that we've done this quarter of repositioning the Company financially, we provided enough flexibility within our capital structure to take care of our deficit for the next few years. The deficit is relatively small, anyway. Depending on which year you are looking at, it's $50 million to $100 million in a given year. So we are good to go with that sort of requirement. Higher prices will make that better, and we're doing a lot of hedging.

So, we don't expect to be cash flow neutral until 2019. Not next year; but I think what we said was we've provided enough money to take care of our deficits for several years.

Now if there is an acquisition or something that comes up, yes, we'll be needing to fund it through the revolver or through some other means. But we've just closed one yesterday and we're closing another one, a sale, soon. So we'll let these things mature for a few days before we start talking about new ideas.

That's fair enough. Would the goal -- just kind of conceptually as you look to perhaps exploit some opportunities around your area, especially within the Permian -- would the goal, from a funding perspective, be similar to what you guys were able to do on the most recent Pecos deal?

The goal would be to block up our acreage to where we could drill 10,000 foot laterals everywhere we drill a well. And that is a little bit of adding and trading going on around both in Ward County and Pecos County. And we have plenty of flexibility for that kind of activity. Any large acquisition would require a new thought of how to fund it. Because as Mark said, our goal is pretty -- it's not pretty -- it's very firm on taking leverage from where it is today down under 3 times EBITDA within the next two years. And we're going to keep that as a guiding light in terms of how we comport ourselves financially.

Okay, that's helpful. And maybe just one last one. Mark, feel free to jump in. But on the borrowing base, I know you talked about it being flat to maybe slightly up for the spring. Does that include the benefit of the Pecos and Ward assets? Or is that really all being driven by the Williston?

Well, the drilling program in Delaware will really ramp up in the second quarter of this year. But of course we'll take all activities into consideration, leading right up to the redetermination that we do in May, or we might even accelerate it a little bit if we decide to.

Well let's think about it, though. We just sold 5,500 barrels a day and our borrowing base didn't go down. So trust me; that's growth rate there. We expect it to grow in the spring a bit and in the fall a bit, just by hard work. So our outlook there is very -- really good. And we keep -- Mark keeps in constant touch with our banks. And their outlook for what I've just outlined is very positive as well.

Okay. That's helpful. Thank you very much.

Kevin MacCurdy, Heikkinen.

Your guidance seems to imply a higher oil percentage for the remainder of the year compared to current levels. Just kind of curious on what you are seeing that made you comfortable with that. Maybe does the Williston have a higher oil mix than previously?

No; nothing's changed in the Williston. If there is a higher oil mix in our numbers, it's a bear. It's modest. We are still going to be about where we've been. The trade-off of the El Halcon for Delaware barrels is kind of similar in terms of makeup of the product stream. A few more NGLs out there; but the areas that we are working in are heavily oil weighted in the Delaware Basin.

Okay, that's it for me. Thanks, guys.

(Operator Instructions). Jacob Gomolinski, Morgan Stanley.

Just wanted to confirm: are you saying that the PV10 at strip is about $1.6 billion? And is that including El Halcon or the Delaware?

Is that pro forma? Let me make sure of that. We're flipping a couple of sheets here.

That's pro forma.

That's pro forma what we've done, but it was based on the strip at 1-31. So that's ex-the Eagle Ford and plus the few barrels we are picking up at the point of acquisition in the Delaware.

Got it, that's helpful. Thank you. And then just on hedging, it looks like as a percentage of production, it was a little bit less hedged in 2017 and 2018 than you used to do historically. Does that sort of represent a shift in the strategy? Or is it more just a reflection of your view on current oil prices?

As you might guess, it's really paid off to be not hitting the hedge markets at a full speed earlier. Right now, our financial objectives are well met by anything in the $50 to $60 per barrel range. So we'll be adding to the hedges, even though I'm constructive on oil prices. But as I always say, I don't really have a freaking clue where they are really going to go. But I'm kind of constructive on them.

But we'll keep hedging because that band of $50 to $60 serves us quite well in terms of our business plan and revenue that we need, and so on and so forth. We are still targeting to be 70% or 80% hedged for 2 to 3 years in advance. So we are working it. But again, it's been -- it's paid off to kind of ride this wave a little bit.

Definitely. All right, well, that's it for me. Thanks very much.

Zachary Bader, Reorg Research.

I just wanted to ask you guys about your liquidity position. You mentioned in the press release a total of $699 million. I was just wondering how much of that is cash, and how much of that is undrawn availability on your RBL.

On that number, on that -- when we've stated that, it's $600 million undrawn RBL, and $100 million of cash.

Okay great. And just on the acquisition front, is there any way you can guide us to the size of any potential acquisition that you might transact on in the future??

Not really. Anything that we do that anybody -- that you would call kind of blocking and tackling around our current positions would be things that we can do within our own capacity. Anything larger than that, which we don't have any projections on, would require a whole -- a financing plan of separate from where we are today. Listen, we are ambitious; but we're also pretty focused on leverage and liquidity, and so on. So we have to balance those things.

Okay, great. Thank you.

Thank you. And I'm showing no further questions at this time. I would like to turn the conference back over to Mr. Floyd Wilson for any further remarks.

Well, anyway, thanks for calling in today. If there's something that you think of we didn't cover, just give us a call. Thanks.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Everyone have a great day.