Battalion Oil Corporation (BATL) Q3 2013 Earnings Report, Transcript and Summary

Good day, ladies gentlemen and welcome to the Halcón Resources Third Quarter 2013 Earnings Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference, Floyd Wilson, Chairman and CEO. Sir, you may begin.

Good morning, and thanks for joining the call today. This call contains forward-looking statements. For a detailed description of our disclaimer, see our earnings release issued yesterday afternoon. So third quarter results were driven by strong contributions from our Williston Basin and El Halcón assets. We expect this trend to continue and be augmented by contributions from our other activities. During the quarter, production increased by 30%, that's quarter-over-quarter. We continue to optimize drilling completion techniques in all areas, and we have made significant progress in our continued divestment of non-core assets. Through that last part of this year, we significantly reduced our rig count as we prepare for 2014. And another year of strong growth with a smaller spend. In the Williston basin, we'll run about 5 rigs for the balance of this year and next. We're drilling all wells using modified drilling completion techniques, which have proven to be game changers for Halcón. All current wells are dramatically outperforming well drilling completed using previous methods and drilled by previous operators. Most of all -- most all of our 2014 wells will be drilled from pads. Cost reductions should continue. At Fort Berthold, and this is really important news to us, that Fort Berthold downspacing results have been positive -- early but positive. 3 Middle Bakken wells drilled on 660-foot spacing came in at nearly 2,700 barrels of oil equivalent per day average per well. And after several weeks, those wells are holding up as expected, with that IP rate as a start. Another side at Fort Berthold, we set a new company record IP rate of over 3,900 barrel of oil equivalent per day. At South Fort Berthold, our first slickwater fracs were a significant improvement over nearby wells on a 60-day rate basis. They were nearly 60% better than the nearby wells over the first 60 days. At North Fort Berthold, our first slickwater-frac-ed well was a 30% improvement over nearby wells. So this slickwater technique and this concentration of proppant and more complex fracturing, which is our target and others' targets here, seems to be working. The downspacing issues in the Williston basin could be really important for our company and others. Our total location inventory in the basin could be nearly 1,000 if Middle Bakken and Three Forks downspacing testing continues to be fruitful. At EL Halcón in East Texas, production more than tripled quarter-over-quarter. We'll run 3 rigs there for the balance of this year and most of next. We've nearly reached our goal of 100,000 net tier 1 acres in the play. The pattern of significant improvements in drilling and completion design is just beginning in El Halcón. Today, well spacing and frac design go hand-in-hand, as we search for the most economic combination. Drilling laterals, most all of them are 7,500 to 8,000 foot. We're quickly transitioning to full-scale pad drilling. During the quarter, we set several records in terms of spud to rig release, and I'm talking less than 2 weeks. El Halcón is proving to be a scalable, high-quality Eagle Ford shale play for our company. In Ohio, we recently spud out the -- an offset to our Kibler #1 well. We used the slickwater frac to complete this well. That will be the first for us in this area, and our current plans include slickwater fracs on all wells going forward. Our plans for that area involve 1 rig for the next few quarters. All drilling would be concentrated on our southern acreage, were we have hundreds of locations. Mark Mize will now go over our third quarter financial results.

Okay. Thank you, Floyd. From a financing perspective during the third quarter, we received net proceeds from a common stock and a senior notes offering of right at $607 million. Those proceeds were used to repay a portion of what was outstanding on our senior secured revolving credit facility. In October, our borrowing base was increased from $710 million to $850 million in conjunction with our regular fall redetermination. Additionally, we recently closed on 2 of 3 previously disclosed divestitures of certain non-core conventional assets, and we expect to close on the third package by the end of the year for total consideration right at $300 million. Note that our borrowing base, we have agreed with the bank group that the borrowing base will be reduced by $50 million, so it will go from $850 million to $800 million, upon the closing of the third non-core divestiture. And pro forma for the borrowing base redetermination and the non-core divestitures, liquidity at September 30 was right at about $870 million. We produced an average of almost 38,000 BOE a day, which was 5% above the high end of our guidance and almost 10% above consensus estimates. We still expect to be within our full year range 2013 guidance of 30,000 to 34,000 despite the impact of -- on fourth quarter production from the non-core divestitures. looking ahead, we provided production spending guidance for 2014 in the earnings release that was published yesterday. And to put our 2014 production guidance into perspective on an equivalent basis pro forma for acquisition and divestiture activity that we had in 2013, we're projecting year-over-year production growth in 2014 of greater than 40%, keeping in mind that the 38,000 to 42,000 BOE a day of production guidance for next year excludes the 4,000 BOE of production that is being sold with the asset package that we just mentioned. We expect to generate strong production growth in 2014, despite reducing our drilling and completion CapEx guidance by approximately 20% year-over-year, down to $1.2 billion. With regards to 2013 drilling and completion CapEx, we did spend $1.2 billion through the third quarter of this year, and we are still on track to come in right at about $1.4 billion as we round out the 2013 capital program. We're currently running fewer rigs, and the timing of well completion also impacts the spend here in the fourth quarter. Operating expenses continue to trend lower on a per BOE basis. Lease operating expense came in at $10.82 per BOE in the third quarter, which represents a decline of about 22% versus the comparable period of the prior year and about a 10% decline compared to the second quarter of this year. We expect lease operating expense to continue to improve on a per unit basis as we become -- continue to become more efficient, divest of more conventional properties that have higher operating cost and continue to grow production. We're projecting LOE of between $8 and $10 per BOE in 2014. And for the third quarter, cash G&A expense of $8.14 per BOE, which was adjusted for the noncash share-based comp charge and some acquisition and merger-related transaction costs, was about 40% lower than the same period of 2012 and 25% lower than the second quarter of this year. G&A expense on a per BOE basis should continue to improve, and we're guiding full year 2014 to between $7 and $9 BOE. Taxes other than income came in at $7.67 per BOE in Q3, and we're projecting that metric in 2014 to be between $6 and $8 BOE. Gathering transportation and other came in at $1.09, and we're projecting that to be between $1 and $2 in 2014. With regards to the $1.2 billion in noncash impairment charges booked in the current quarter, most of those charges were related to a full-cost pool impairment. A contributing factor was the transfer of a significant amount of unevaluated property costs to the full cost pool in the current quarter, with little to no proved reserves being added associated with those leasehold transfers. The unevaluated property cost transfer to the full-cost pool were primarily related, so some of the Woodbine acreage in East Texas and a certain portion of the Utica/Point Pleasant acreage. The other part of the charge, the impairment of our goodwill related to the acquisition of GeoResources in 2012. Note that the noncash impairment charges had no impact on proved reserves, or debar [ph] the borrowing base, which was increased with the redetermination we just went through. Further, these transfers, they did result in a spike in our DD&A rate in the current quarter. But we would expect a decline in our rate going forward, since the depletable pace has been reduced by the amount of the impairment. Finally, a brief comment on the hedging program. We continue to target a hedged portfolio where we look to hedge 80% of our expected production over the next 18 to 24 months. As we sit here today, we have about 26,000 barrels a day of oil hedged for the remainder of 2013, at an average floor of just over $90 a barrel for 20 -- that's 2013. For 2014, we have about 27,000 barrels a day hedged at a average floor of right at $90 a barrel. And in 2015, we're still building a hedge position there, but we currently have 7,000 barrels a day hedged at an average floor of just under $90 a barrel. And with that, I'll turn the call back over to Floyd.

Thanks, Mark. So we've reduced capital spending substantially as we reached the -- near the end of this year, and we're projecting to substantially decrease capital spending in 2014 as compared to 2013. At the same time, we intend to meet the aggressive growth targets set out today. Our CapEx projection for 2014 includes significant capital concentration in the Williston Basin and at El Halcón. It also includes a measured spend in some of -- on some of our other activities. We have time for some questions, operator, if there are any.

[Operator Instructions] Our first question comes from Neal Dingmann of SunTrust.

Say, while you mentioned on the El Halcón being scalable there, just your thoughts. As far I know, you've kind of laid out the rig program, but are you going to go after some more, as far as different formations there? Kind of -- if you could give me some color, number one, on different formations? And then two, I know you've picked up a little more acreage there, and I know Steve had mentioned there's not a ton of acreage available, just your thoughts on maybe trying to pick up more.

Sure. Second part first, it's a very tight area. It was tight before we started leasing with mature production holding much of the acreage in the area. Several other operators are in the play along with us, although we clearly are running most rigs and have got a bit of a head start on the technology. But it's -- we're looking all the time, but it's very hard to add there. In terms of scalable, I was really -- we're really talking about scalable in the Eagle Ford. However, there's plenty of spots to drill other sort of localized accumulations of crude throughout the area, but our initial push will be to drill these horizontal Eagle Ford wells. But there's Buda and there's Austin Chalk, there's plenty of places to drill other wells, and we fully intend to be doing that over time, if that's helpful.

That's okay. And then your thoughts, I know you shared some seismic on the Woodbine. But kind of on the remainder of the year, into next year, what are your thoughts on the Woodbine going forward?

Well, listen. We have a process here. We're not looking to spend money in the next 2 or 3 years somewhere. We tend to -- the -- our accounting process tends to move that acreage into either a low-value or no-value category. We're shooting a large seismic program there. We'll have some early information from it this year, but the full load of data won't be on our -- in our mailbox here until first quarter. And so we're working the area. The acreage has significant value. As you know, there's several other really top-flight operators drilling around us. We've just diverted our attention and our capital to El Halcón and the Eagle Ford, the horizontal Eagle Ford shale wells, for now.

Okay. And then last one, if I could. I know, Floyd, you and Mark and the guys and Steve are always very inquisitive looking at everything out there. Just your thoughts as far as when you see kind of M&A activity. I mean, is there a number of still-attractive deals that you're seeing? And then maybe a question more for Mark. If you do see something to have post any sort of [Audio gap]-- you certainly have enough liquidity now. Your sought -- your thoughts on how you would finance something or kind of the, I guess, better way to say it, kind of the debt metrics you would like to continue to have post any sort of deal [ph].

So the question is, how would be finance something that we have no design to buy right now? That's kind of a hard one to answer. I'd like Mark to address the leverage question in a general sense. We're quickly growing into our leverage. We would appreciate being slightly less levered than we are. We're putting all of the money to good use. I don't know what you -- if you want to add to that, Mark?

The only thing I would add -- I mean, we're continuing down the path that we've stated here recently, which is that we're as levered as we want to be. So anything that we are looking at, we're looking for it to either be leverage neutral or more preferably deleveraging to the company. So you know where we are as we sit today, getting down to somewhere 4x levered. Or maybe something under that would -- is where we would want to be as we move forward and grow into what we have.

Our next question comes from Steve Berman of Canaccord.

Floyd, in the Utica. Other than the first slickwater frac you're going to drill, any other initiatives different there going forward?

Well, we won't drill any more wells near the s***** ones we drilled already. That's one major initiative. We'll concentrate all of our drilling in the south part of our acreage, we have lots of room. We fully intend to evaluate different completion techniques, as you know, as many others in the play are doing as well. So I think that's our -- our main initiative up there is to consolidate our position in the southern end and drill a bunch of wells down there over time. But the midstream business, get back on track after the fire at the processing plant and just move ahead. We are, of course, more cautious than we were, and we were cautious before. But we've had a lot of drilling results from these wildcat wells, and our focus will be on the south end of the play at this time.

And where do you stand on infrastructure, particularly down in the south there, southern portion of the play?

It's interesting. In the north end, the infrastructure spend was going to be enormous with literally 50 and maybe 80 miles of large pipe being needed to be laid across inhospitable areas in terms of culture and surface and wetlands and whatnot. Down in Southern Mahoning and Trumbull County -- and Northern Mahoning, Southern Trumbull County, there's some infrastructure in place down there. There's a lot of mature production, not so much that the pipes are all that viable, but the right of ways and the pathways for egress are there. So our infrastructure spend is going to be dramatically less down there, where all of our future drilling is situated than it would have been up in the wildcat areas.

A quick question for Mark on the the DD&A. Do you see it getting back to, say, the mid-30s per BOE like it was in the first half of the year, or something different than that?

That is a tough number to, I guess, guide to. And that's one reason we don't do it. But I think for modeling purposes, if you used about a $3 rate reduction, you'd probably be pretty close.

Our next question comes from Robert Bellinski of Morningstar.

I was just wondering, when do you think we could expect updated type curves for Fort Berthold and Williams County?

The improvements have been coming so fast and furious, we really can't keep up with it. We tend to not put out updated type curves until we have significant history on a well. So certainly, some time over the next couple of quarters. But that field, as you know, has been so drilled in every area that you need type curves in every area. And for our company, we probably have about 6 or 7 type curves. But then we'd have to start looking at type curves with slickwater fracs and without slickwater fracs, and type curves where you have tight spacing and type curves where you don't have tight spacing. What I can say is that the initial wave of completion design modifications that we've done from the north end of the field doubled our IPs and our 30-day rates, and down the south end, increased them by 30% to 50%. That should yield a much higher type curve, but we're just not prepared to put those out there. You can take our old type curves and just assume that the new ones will be higher. [indiscernible] the next couple of quarters.

Great. And then shifting to the Tuscaloosa, 2 other firms announced some pretty sizable capital spend numbers for next year. I was just wondering what are you seeing. Is there anything that would make you want to increase activity in that play at this point?

We are watching that play extremely closely. We're very pleased and happy with the progress that these operators have made, and it's a bright spot on our radar screen for sure.

Our next question comes from Ron Mills of Johnson Rice & Company. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: A question. Your very last prepared remark was talking about the 2014 CapEx being really focused on the Bakken and El Halcón. I know those 2 areas were about 90% of your expected second half drilling CapEx. Is that the kind of rate that you would expect to spend next year? Or can the D&C capital be even more concentrated than that 90% level?

I doubt it will be any more concentrated. And as you know, that's an early estimate. With the rig counts that we see now, we'll definitely spend 85% or thereabouts, maybe 90% in 2014. But those rig counts are subject to change. We intend to or we hoped to, and evidently we didn't a very good job of highlighting the fact that we can -- we project that we can grow the company dramatically year-over-year while spending a lot less money in 2014 than we did in 2013. So we're taking CapEx down 20% or 30%, raising -- we're increasing production 20% to 30%, and we expect to lower unit production costs by 20% or more. So we're looking for quite a nice confluence of things for next year. We have a little money in the budget for other activities, as we always do, but the bulk of the money will be spent in East Texas and up the Williston Basin: East Texas being the Eagle Ford Shale, and the Williston Basin will be Middle Bakken Three Forks. And I think I neglected to mention, we're drilling our first second-bench Three Forks test as we speak, at North Fort Berthold. The downspacing Middle Bakken test that we drilled also included a brand-new Three Forks well that was in the slot between the 660 well, so it's even a higher concentration of downspacing than we reported this morning. And that well came in really strong, too, I think at 2,500, 2,700 barrels a day or so. So we have extremely high expectations and confidence in what we're doing up there. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And just as to -- to keep going on the Williston, the downspacing you're looking at the Fort Berthold area, you're looking like -- it looks like plus or minus 8 Bakken wells per 1,280. You're just starting the Three Forks analysis. With between what you're doing in the Three Forks and your participation in Continental's downspacing tests, is that something that, by the middle part of 2014, you would hope to have a better sense as the spacing potential in the Three Forks as well? And is it -- would it vary much in either the Bakken or Three Forks, as you move from Fort Berthold up to Williams?

So as we mentioned earlier that there -- you need to have several different type curves as you go across the Williston Basin, which is a very large basin, the Three Forks is clearly not going to be exactly the same across the basin. We're actually seeing some areas where the second bench of the Three Forks will be superior to the first bench. Most areas where the Three Forks is good, it looks like the first bench is the higher quality. However, in some areas, the second might be higher. Up in Williams County, it's somewhat TBD. Our concentration of our activity up there now is to decide how close we can drill the Middle Bakken wells without killing the economics. And as you know, Ron, as I mentioned in the -- about El Halcón, it's the same thing in Williston Basin. Your frac job, however your frac job is designed, it goes hand in hand with spacing. So all of us in the business are solving for -- how can you get a more complex near-wellbore frac without killing your economics. So you can drill your wells more closely and end up recovering more of the crude from a given container, or in this case, a drilling spacing unit, up in the Williston Basin with more wells. We're looking at 660-foot Middle Bakken wells. We're looking at lease-line wells wherever possible, so you don't leave that oil behind. We're looking at full development of the first bench of the Three Forks and all the areas that we think it's good. And we're looking at significant second bench development in those areas that we think it's good. And those areas where we think it's good are being augmented daily by information from other operators, because everybody is solving for the same thing. And that basin is -- it's growing dramatically, and it sounds like it's going to keep roaring for a while to us. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And then the last one for me, and it's also on the Williston, you talked about longer laterals and more proppants as part of your completion design change. And then also the implementation of the slickwater fracs, you're now using it not just up in Williams to make that play a lot better than it was under the prior operator's operatorship, but also now in what is some of the best rock in Fort Berthold. Is slickwater something that looks like it will be applicable across the whole part of the Williston Basin? And is that the primary driver behind the improvements, or is it -- is there also some of the longer laterals, more intense fracs?

I'd like Charles to speak here, but we haven't said anything about longer laterals up there yet. We're watching closely what EOG has announced and maybe a few others. But at this time, we're situating all of our laterals within drilling spacing units. But go ahead, Charles and...

Yes. So the lateral -- our DSUs are all HBP'd at this point, so we're confined to our units as far as lateral length. So 10,000 feet or so on our lateral length. We have only done 3 slickwater fracs on the reservation so far, and the results are very encouraging, but need a little more of a data set before we start going full scale in the direction to see if that is really is an improvement over the ERs. It's a great area. But the real focus -- we're going to keep doing that, but this downspacing is our real focus right now. We're, in essence, doubling our number of locations.

Our next question comes from Brian Velie of Capital One Securities.

Just a quick question on spending for next year. The D&C guidance for 2014 is $1.1 billion to $1.2 billion. Can you add any color on what the kind of fully loaded CapEx number might be for next year to include things like seismic infrastructure and some of the other stuff?

We have a very small seismic program expected for next year. I don't think it's more than $25 million or $30 million, it's something like that. And as I said, up in the Utica, we don't have much of an infrastructure requirement in the south end of our acreage. It's not substantial. In the Williston Basin, we're all covered up there where everything is on production, so it's nominal. Especially with pad drilling, it becomes even more nominal. At El Halcón, there's a lot of infrastructure. So really, what our infrastructure crew is doing there is putting an adjunct to the drilling program. So we're just getting our gas into the pipelines as quickly as we can, so that we can produce the crude oil. So while I can't give you a firm number or anything for infrastructure, it's well less than $50 million right now in our expectation.

Our next question comes from Amir Arif with Stifel. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Just a broader question. Just with your increasing inventory in the Bakken and your acreage position in El Halcón, do you feel as the -- at the corporate level that you have enough internal drilling opportunities now? Or is your acquisition appetite still to grow to a larger base?

We're extremely happy with the outlook for the next multiple years in the Williston Basin and El Halcón. In fact, we've just scratched the surface at El Halcón. I don't even know if we've drilled 50 wells yet there, maybe 40 or so, and 2/3 of those have been frac-ed thereabouts. We have room for 1,000 or more wells there, so we just scratched the surface. And with this downspacing in the Williston Basin, as Charles mentioned, perhaps doubling our potential -- doubling our potential location count up there, it's -- we have a lot. We have a few other activities that we're doing. We don't have any huge appetites anywhere. But we can make our growth initiatives and ambitions on all the things that we have in hand already. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. So and then in terms of -- I mean, I understand in terms of hitting everything with what you have in hand. But in terms of your acquisition appetite, in general, is it -- would it be if it was a new area? Or would it just be for bolt-ons at this point?

Well, right now, we are certainly looking at what you call bolt-ons in our existing areas, and everyone else is looking for those as well. So they're really hard to get. So I think -- listen, we have a long history. We have an exploration group. We're always looking, if nothing else, to make sure we keep abreast of the technology and the similarities and differences between the different resource-style plays. We don't have anything on the drawing boards right now that you haven't already heard about, though.

Our next question comes from James Spicer of Wells Fargo.

A question on the funding side. You talked a little bit about some additional non-core divestitures into 2014. Just wondering if you can comment at all on what those might include or if you have any sort of sense as to what you might want to raise there.

We don't have a target cash-wise. We have a process that we sell everything that either is mature, no future upside. We sell things that we don't intend to concentrate capital in. And we sell everything but our core plays. And we're -- we've been in the process of that for the whole time the company has been around, and we'll continue to do that. So while we don't have a target, you could expect another several hundred million dollars next year in the general sense of additional divestments.

So with the redeployment of capital away from the Woodbine, would the Woodbine be on that list, do you think?

Well, everything is on that list, so at all times. The Woodbine has been a really good play for us up in Leon County. We, in fact, we just drilled a record-setting well up there. We drilled a well for $5 million, where some of the wells were costing twice that, and it's producing at about the same level early-stage as the more expensive wells were. So that provides for quite a few extra locations up there. Whether we drill them or somebody else, I can't say. But it's a very valuable property and it's making a lot of crude oil right now. But again, it's not our style of property where we have a limited view of how many future places to drill wells.

Okay. Okay, understand. And then the second one for me is just on the write down during the quarter. I was wondering if you could comment on the portion that was attributed to the goodwill at GeoResources and also in the Utica. Was that tied to specific acreage? And if so, can you comment on what that acreage was?

So I'm waiving at Mark, because I don't know s*** about any of that. So I'd like Mark to answer that, please.

Just real quick, on the goodwill, we did break that out separately on the face of the income statement in the Q. That was $229 million. That was all the goodwill that we were carrying, and it was 100% associated with the GeoResources transaction back in 2012. And then with full-cost accounting, you can't really separately identify cost and carve up your pool. But a portion of the full cost impairment was associated with some of the Utica acreage.

Okay. And I assume that was your sort of -- the Pennsylvania, the Northwest Pennsylvania acreage?

It's fair to say that it was a portion of our northern acreage that we've tested, and decided we wouldn't do any drilling there any time soon, any additional drilling.

Our next question comes from Kyle Rhodes of RBC.

Just wondering if you could comment on the current well cost at El Halcón. And any preliminary thoughts on EURs there?

Well, our target starting out was $9 million to $10 million, 400,000 to 500,000 barrels. We're getting down to the low end of that cost side. We drilled a few wells in the mid-$8 million so far. Our EURs have steadily been getting better or higher in our more current wells. That's a combination of longer laterals and better targeting. In other words, staying in-zone for most all of your lateral lengths as opposed to having a bit of your wellbore out of zone. It's all within the Eagle Ford, but we have a landing zone there that's quite useful in initiating frac jobs. So, we try to stay in this fairly tight area with the lateral. So we're targeting -- we're still targeting wells. We've had several wells that will be well beyond 0.5 million barrels. But it looks like our average is certainly in that 400,000 to 500,000 barrel range with well cost trending down to around $9 million or thereabouts.

That's helpful. And then can you speak to some of your new ventures areas? I think you guys were completing a few Louisiana Wilcox wells in third quarter. Just -- I'm wondering if you had any results there, and then if you were kind of picking up any additional acreage in the PMS?

We don't have anything additional in the Wilcox, that's likely. It's been really good. It's fine, but it's not very large for us. That's likely a divestment candidate for 2014. I don't think Steve's decided that for sure yet, but probably. We're just not talking about any other areas at this time. Operator, I think that's all the questions. Thanks, everybody, for joining. And if there's something else, just give us a call here at the company. Thanks.

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