Battalion Oil Corp (BATL) 2013 Q3 法說會逐字稿

Good day ladies and gentlemen and welcome to the Halcon 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 Halcon assets. We expect this trend to continue and be augmented by contributions from our other activities. During the quarter production increased by 30%, that is quarter-over-quarter. We continue to optimize drilling completion techniques and all areas and we have made significant progress in our continued divestment of noncore assets.

The last part of this year we have significantly reduced 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 five rigs for the balance of this year and next. We are drilling all wells using modified drilling completion techniques which have proven to be game changers for Halcon. All current wells are dramatically outperforming wells drilled and completed using previous methods and drilled by previous operators. Most all of our 2014 wells will be drilled from pads cost reduction should continue.

At Fort Berthoud -- and this is some really important news to us. At Fort Berthoud, downspacing results have been positive -- early but positive. Three 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. On another side at Fort Berthoud we set a new Company record IP rate of over 3,900 barrel of oil equivalent per day.

At South Fort Berthoud our first thick water fracs were a significant improvement over nearby wells on 60-day rate basis. They were nearly 60% better than the nearby wells for the first 60 days. At North Fort Berthoud our first thick water fracked well was a 30% improvement over nearby wells. So this thick water technique and this concentration of proppant and more complex fracturing which is our target and other 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 the Three Forks downspacing testing continues to be fruitful.

At El Halcon in East Texas production more than tripled quarter-over-quarter. We'll run three 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 at El Halcon. 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 are quickly transitioning to full scale pad drilling. During the quarter we set several records in terms of spud-to-rig release and I am talking less than 2 weeks. El Halcon has proven to be a scaleable, high-quality Eagle Ford shale play for our Company.

In Ohio we recently spud our out the -- an offset to our Kibler #1 well. We'll use a slick water frac to complete this well. That will be the first for us in the area and our current plans include slick water fracs on all wells going forward. Our plans for that area involved one rig for the next few quarters. All drilling will be concentrated on our southern acreage where we have hundreds of locations. Mark Mize will now go over our third quarter financial results.

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've recently closed on two of the three previously disclosed divestitures of certain, noncore, conventional assets and we expect to close on the third package by the end of the year for a total consideration of right at $300 million. Note that our borrowing base, we have agreed with the bank group that the borrowing base will reduced by $50 million. So it will go from $850 million to $800 million upon the closing of the third, noncore divestiture. And pro forma for the borrowing base redetermination and the noncore the vestiges liquidity of September 30 was right at about $870 million.

We've reached an average of almost 38,000 Boe a day which was 5% above the high end of our guidance at almost 10% above consensus estimates. We still expect to be within our full-year range 2013 guidance of 30,000 to 34,000 Boe despite the impact on the fourth quarter production from the noncore divestitures. Looking ahead we've provided production spending guidance for 2014 in the earnings release that was published yesterday. And to put our 2014 production guidance into perspective on a 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 now that we just mentioned.

We expect to generate strong production growth in the 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 are currently running fewer rigs and the timing of well completion also impacts the spend here in the fourth quarter.

Operating expenses continue to trend well, we're 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 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 since we continue to become more efficient divest of more conventional properties that have higher operating cost and continue to grow production.

We are projecting LOE of between $8 and $10 per Boe in 2014. For the third quarter, cash G&A expense of $8.14 per Boe which was adjusted for the non-cash 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 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 of Boe. Taxes other than income that came in at $7.67 per Boe and Q3. We are projecting that metric in 2014 to be between $6 and $8 Boe. Gathering, transportation and other came in at $1.09. We're projecting that to be between $1 and $2 in 2014.

With regards to the $1.2 billion in the non-cash 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 cost 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 transferred into the full cost pool were primarily related to 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 non-cash impairment charges have no impact on proved reserves are [before] 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 hedge 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 --that's 2013. For 2014 we have about 27,000 barrels a day hedged at an 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 hedge at an average floor of just under $90 a barrel. With that I'll turn the call back over to Floyd.

Thanks, Mark. So we've reduced capital spending substantially as we reach 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 target set out today. Our CapEx projection for 2014 includes significant capital concentration in the Williston Basin and at El Halcon. It also includes measured spend on some of our other activities. We have time for some questions, operator if there are any.

(Operator Instructions)

Neal Dingmann, SunTrust

Good morning, guys. Floyd, you mentioned on the EL Halcon to being scalable there. Just your thoughts as far as I know you've kind of laid out the rig program but are you going to go after some more as far as the different formations there?

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 ran the most rigs and have got a bit of a head start on the technology. But we're looking all the time, it's very hard to add there.

In terms of scalable, we're really talking about scalable in the Eagle Ford. However, there is plenty of spots to drill other, localized accumulations of crude throughout the area. But our initial push will be to drill these horizontal Eagle Ford wells. But there is a Buddha, and there is 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.

Okay. And then, your thoughts (inaudible) I know you were shooting some [size-buck] on the Woodbine on a remainder of the year -- or in the next year. Floyd, your thoughts on the Woodbine going forward.

Well, listen, we have a process here. If we're not looking to spend money in the next two or three years somewhere, our accounting process tends to move that acreage into either 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 in our mailbox here until the first quarter. And so, we are working the area.

The acreage has significant value. As you know there are several other really top-flight operators drilling around us. We've just diverted our attention and our capital to El Halcon and 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 M&A activity, is there a number of still attractive deals that you are seeing. And then maybe a question more for Mark, if you do see something, you certainly have enough liquidity now. Your thoughts on how you would finance something or the better way to say it the debt metrics you would like to continue to have post any sort of deal.

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

The only thing I would add, we are continuing down the path that we have stated here recently which is that we are as levered as we want to be. So anything that we are looking at, we are looking for it to either be leveraged neutral or more preferably deleveraging to the Company. So you know where we are as we sit today, getting down to somewhere four times levered or maybe something under that is where we would want to be as we move forward and grow into what we have.

Perfect. Thanks, guys.

Steve Berman, Canaccord.

Thanks. Good morning. Floyd, in the Utica, other than the first (inaudible) quarter frac you are going to drill any other initiatives different there going forward?

Well, we won't drill any more wells near the (expletive) ones we drilled already. That's one major initiative. We will concentrate all of our drilling in the south part of rigs. 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 is our main initiative up there is to consolidate our position on the southern end and drill a bunch of wells down there over time.

Let 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 this 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?

You know, it is 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 northern Mahoney and southern Trimble County there is some infrastructure in place down there. There is a lot of mature production.

Not so much that the pipe is all that viable but the right of ways and the pathways for egress are there. Our infrastructure spend is going to be dramatically less down there were all of our future drilling is situated than it would have been up in the wildcat areas.

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

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

Great. Thanks, guys.

Robert Bellinski, Morningstar.

Thanks for taking my call everybody. I was just wondering when do you think we could expect updated type curves for Fort Berthold and Williams County?

You know, 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 sometime 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'd probably have about six or seven type curves.

But that we would have to start looking at type curves like sick water fraction. Without slick water fraction type curves where you have tight spacing and type curves where we don't have tight spacing. What I can say is that the initial wave of completion design modifications that we've done up in the north end of the field, doubled our IPs and our 30 day rates and down on 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. (multiple speakers)

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

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

Okay. Thanks, guys.

Ron Mills, Johnson Rice & Company.

Good morning, Floyd. Question, your very last prepared remark was talking about the 2014 CapEx being really focused on the Bakken in El Halcon. I know those two 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. As you know that is an early estimate. With the recount that we see now, we will definitely spend 85% or thereabouts, maybe 90% in 2014. But those rig counts are subject to change.

We intend to, we hope to -- evidently we didn't do a very good job of highlighting the fact that 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 are taking CapEx down 20% or 30%. We're raising -- we're increasing production 20% or 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 at the Williston Basin.

East Texas being the Eagleford Shale and the Williston Basin will be Middle Bakken Three Forks. And I think I neglected to mention we are drilling our first second bench Three Forks test as we speak at Northfork 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 is even a higher concentration of downspacing then we reported this morning. That well came in really strong to I think at 2500, 2700 barrels a day. So we have extremely high expectations and confidence in what we are doing up there.

Just as to keep going on the Williston and the downspacing, you know you are looking at the Fort Berthold area it is looking like plus or minus 8 Bakken wells per 1280. You are just starting the Three Forks analysis. Between what you are doing in the Three Forks and your participation in Continental's downspacing test, is that something that by the middle part of 2014 you would hope to have a better sense of spacing potential in the Three Forks as well? And 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 have actually seen 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 is 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 about El Halcon, it's the same thing in the Williston basis.

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 well bore frac without killing your economics so you can drill your wells more closely and end up recovering more of the crude from given container or in this case a drilling spacing unit up in the Williston Basin with more wells? So we are looking at 660 Middle Bakken wells.

We are looking at lease line wells wherever possible so that you don't leave that oil behind. We're looking at full development of the first bench of the Three Forks in all of the areas that we think it is good. And we're looking at significant second bench development in areas where we think it is good. And those areas were we think it is good are being augmented daily by information from other operators because everybody is solving for the same thing. And that basin -- it is growing dramatically, and it sounds like it's going keep roaring for a while to us.

And the last one for me, and it is also on the Williston. You talked about longer laterals and more prop ends as part of your completion design change and then also the implementation of the slick water fracs. You are now using it not just up in Williams to make that play a lot better than it was under the prior operators; the operator ship, but also now and what is some of the best rock in Fort Berthold.

Is slick water something that it looks like will be applicable across the whole part of the Williston basin, and is that the primary driver behind the improvements, or is there also some of the longer laterals and more intense fracs?

I would like Charles to speak here, but we have not 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.

So our DSUs are all HBPd at this point. So we are confined to our units as far as lateral lengths so 10,000 feet or so on our lateral lengths.

We have only done the three slick water 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 that direction. That really is an improvement over the EURs. It's a great area. But the real focus --we are going to keep doing that but this downspacing is our real focus right now. We are in essence doubling our number of locations.

Perfect. Thank you, guys.

[Brian Ely], 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 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 is more than $25 million or $30 million, something like that. As I said up in the Utica, we don't have much of an infrastructure requirements in the south end of our acreage. It is not substantial.

In the Williston Basin, we are all covered up there. Everything is on production, so it is nominal, especially with pad drilling it becomes even more nominal. The El Halcon there is a lot of infrastructure, so really what our infrastructure crew is doing there is really an adjunct to the drilling program. So we are just getting our gas into the pipelines as quickly as we can so that we can produce the crude oil. While I cannot give you a firm number or anything for infrastructure, it is well less than $50 million right now in our expectation.

That is very helpful, thank you very much.

Amir Arif, Stifel.

Just a broader question. With your increasing inventory in the Bakken and your acreage position in El Halcon, do you feel at the corporate level that you have enough internal drilling opportunities now, or is your acquisition appetite still to grow to a larger base quite

We are extremely happy with the outlook for the next multiple years in the Williston Basin and El Halcon. In fact we have just scratched the surface at El Halcon. I don't even know if we drilled 50 wells there yet. Maybe 40 or so and two thirds of those have been frac-ed thereabouts. We have room for a thousand or more wells there so we just scratched the surface. With this downspacing in the Williston Basin, as Charles mentioned, perhaps doubling our potential location count up there. We have a lot. We have a few other activities that we are doing. We don't have any huge appetites anywhere, but we can make our growth initiatives and ambitions on all of the things that we have in hand already.

Okay. And terms of -- 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 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 are really hard to get. So I think -- listen, we have a long history. We have an exploration group. We are always looking if nothing else to make sure we keep abreast of the technology and similarities and differences between the different resource style plays. We don't have anything on the drawing boards right now that you have not already heard about, though.

Okay. Thank you.

James Spicer, 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, you know with no future upside. We sell everything that we don't intend to concentrate capital in, and we sell everything but our core plays. And we have been in the process of that for the whole time the Company has been around, and we will continue to do that. 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. 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 is 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 cannot say, but it is a very valuable property, and it is making a lot of crude oil right now. But again it is not our style of property where we have limited view of how many future places to drill wells.

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

So I am waving at Mark because I don't know (expletive) about any of that. I would 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 of the goodwill that we were carrying, and it was 100% associated with the Geo Resources transaction back in 2012. And then with full cost accounting you cannot really separately identify costs to carve up your pool. But a portion of the full cost impairment was associated with some of the Utica acreage.

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

It is fair to say that it was a portion of our northern acreage that we have tested and decided we would not do any drilling there anytime soon -- any additional drilling.

Okay. Great. Thanks, guys.

Kyle Rhodes, RBC

Just wondering if you could comment on current well cost at El Halcon 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 are 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 is a combination of longer laterals and better targeting. In other words staying in zone.

For most all of your lateral length as opposed to having a bit of your well bore out of zone. It is all within the Eagleford, but we have a landing zone there that is quite useful in initiating frac jobs. So we try to stay in this fairly tight area with the lateral. So we are targeting -- we are still targeting wells. We have had several wells that will be well beyond 0.5 million barrels, but it looks like our average is certainly and that 400,000 to 500,000 barrel range with well costs trending down to $9 million or thereabouts.

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

We don't have anything additional in the Wilcox. That is likely, it has been really good. It is fine, but it is not a very large for us. That's likely a divestment candidates for 2014. I don't think Steve decided that for sure yet but probably. We are just not talking about any other areas at this time.

Thanks, guys.

Operator, I think that is all of the questions. Thank you everybody for joining and if there is 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.