Battalion Oil Corp (BATL) 2014 Q1 法說會逐字稿

Good day ladies and gentlemen and welcome to Halcon Resources first-quarter 2014 earnings conference call.

(Operator Instructions)

As a reminder, this conference call is being recorded.

I would now like to introduce the host for today's conference, Mr. Floyd Wilson, Chairman and CEO. Sir, you may begin.

Thanks. Good morning, everyone. I'm a little hoarse today, sorry.

This conference call contains forward-looking statements. For a detailed description of our disclaimer, see our earnings release issued yesterday afternoon.

First quarter results were solid despite some weather-related downtime and associated drilling completion delays experienced in the Williston basin. First quarter 2014 production was above the high end of the guidance. Our production guidance for the second quarter represents 20% quarter-over-quarter pro forma growth and takes into account the sale of our Woodbine assets. We expect to close that sale of about $450 million within the next day or two.

And as we've reported before, we are entirely comfortable with our liquidity position. We continue to evaluate all remaining non-core properties for future divestment. A lot of action going on at the Company. Company-wide we have 22 operated wells being completed or waiting on completion at this time. We're operating eight rigs, four in the Williston, three at El Halcon, and one in the TMS. We're adding the second rig in the TMS this month. Rig count in the TMS could easily double by early 2015 as we build a growth ramp there.

Current plans call for spending roughly the same amount on drilling and completion CapEx in 2015 as in 2014, about $1 billion.

Up in the Williston basin, production growth was fantastic, 73% quarter over quarter. We are currently producing about 25,000 barrels a day. That 73% was first quarter 2014 versus first quarter 2013, 7% versus first quarter 2014 as far as our guidance.

Activity in the Williston basin is back to normal after a very harsh winter. We were generally able to manage our way through this with a few delays, but not as nearly bad as it could have been. We continue to make progress towards realizing efficiencies associated with pad drilling, simultaneous operations and completion modifications.

We are on track for a 5% or more decrease in completed well costs by year-end 2014 up in the Bakken and Three Forks drilling program. More importantly, though, average IP, 30-day rates and EUR estimates continue to increase. At the Fort Berthold Indian reservation, we have a 10% improvement in average IP rate, first quarter versus fourth quarter of 2013. 30% improvement in average 30-day rates, which is a great number, first quarter versus fourth quarter 2013.

And on average, all Halcon-operated Bakken wells online in the Fort Berthold area completed the slickwater frac continued to outperform the 801 MBoe average type curve that we put out a few months ago. Testing is underway to determine if the use of slickwater fracs on Three Forks wells in the Fort Berthold may yield similar results, but initially we're thinking that hybrid fracs will work best in the Three Forks.

We're in the process of putting six new wells online that were drilled from a single pad and spaced 660 feet apart. The IP rate for one of those six wells is 4,225 BOE per day. That's a new Company record. Up in Williams County, we had some wells we drilled last year, finished up drilling early in the quarter. We completed seven wells up there using slickwater fracs during the quarter, and those wells are outperforming the 477 MBoe type curve for that area.

Keep in mind we have a very large development inventory at Williams County, although we don't intend to run any rigs there for the balance of this year. Downspacing tests continue to yield positive results and we are watching our -- of course our results and our peers' results all around the field, all around the basin. We're currently in various stages of downspacing tests on 16 pads; this is 50 Wells in the Fort Berthold area. And results are expected from several of those this quarter. Bottom-line results in the Williston basin continue to improve from their already excellent position.

In El Halcon in East Texas, production growth is almost exponential. It grew 843% versus the first quarter of 2013; sequential growth was very strong as well. Currently, we're producing over 10,000 BOE per day, nearly 50% more than our first-quarter average. While results continue to improve, average IP rates improved over 10%; average 30-day rates improved 15%.

We continue to make progress towards identifying the optimal well design. Keep in mind we only have on production 50 or 60 wells. It's early stage in a play of this nature. So testing is underway on a number of completion design variations to reduce cost, increase performance. These include increasing stage length while delivering the same amount of proppant per lateral foot, via tighter perf-cluster spacing; increasing the percentage of resin-coated sand relative to [sell] proppant; using different components within the frac fluid; and testing different frac assemblies. Also, several artificial lift modifications are being evaluated as we continue to work to find the most economic formula overall.

We're also working on trying to define that point of diminishing returns in terms of lateral length. Not quite there yet. We continue to feel that the longer lateral lengths are yielding the better results.

We expect well costs to decrease as we continue to transition to full-scale pad drilling. That's going on this year with a couple of our rigs. Another rig will still be drilling single-well tests here and there. Based on results from step-out wells drilled to the south of our initial position in Northwest Brazos, combined with results from other operators, our entire acreage position is being de-risked and we've declared it commercial.

In the TMS, we've added a few acres here and there. We now have over 316,000 net acres in the play. We're off to a solid start. Drilled our first TMS well in Wilkinson County, Mississippi, a bit ahead of schedule and in about 39 days. It was a 21,170-foot TD with a 7,751-foot lateral. Completion operations are currently underway. We're confident we can reduce the drilling days by year end by 15% to 20%. We're drilling our second well now, the Black Stone minerals well, and we're moving a second rig within 10 days or so.

We continue to evaluate joint venture or financing options for the TMS. This is 100% about balance sheet management and future rig count growth opportunities, as we and a few others guide this play into its place on the premier large-scale crude oil base resource place in the United States. Our excitement for the TMS continues to build.

Mark Mize will now go over our financial results for the quarter.

Thank you, Floyd.

Production for the quarter came in above guidance and averaged right at 36,622 barrels of oil equivalent a day. That's about 3% above street estimates -- and that is, as Floyd had touched on, despite some weather-related downtime and associated drilling incompletion delays in the Williston basin. LOE came in at $11.12 per BOE in the first quarter, which is 8% lower than the fourth quarter of 2013, although slightly higher than expected -- again, due to weather conditions in the Bakken this past winter.

After adjusting for some selected items that we have disclosed in a table in our press release, cash G&A expense for the quarter was $7.56 per BOE and taxes other than income came in at $7.33, with gathering coming in at $1.54. So we are on track to meet our previously issued cost guidance for the year.

During the first quarter, our borrowing base was increased to $800 million from $700 million in conjunction with our regular spring re-determination. We ended the quarter with undrawn revolver capacity and cash on hand totaling right at $452 million. And then, pro forma for the pending $450 million sale of East Texas assets that Floyd had touched on and associated $100 million reduction to the borrowing base, we had undrawn revolver capacity plus cash on hand of $802 million. We expect the borrowing base from our revolver to increase when we have our fall re-determination later this year. We would expect to have that done before the third-quarter earnings call.

We're comfortable with our liquidity position for the remainder of 2014 and going into 2015, and we do not anticipate any type of capital market transactions to fund any of our drilling activities. If we decide to bring in a financial partner to assist the financing or TMS activities, the liquidity would, of course, be further improved by that transaction.

A couple of comments on D&C. We did spend about $330 million during the first quarter. That's in line with our internal forecast that sets us up for solid production growth in the second quarter. According to our business plan, D&C will decrease quarterly throughout the remainder of the year as we continue to improve operational efficiencies, which allows us to decrease rig count in certain plays in the Company.

Lease acquisition, seismic, and infrastructure came in at $128 million for the quarter. Most of the spending was related to growing our acreage position in the TMS. We expect a lot of these figures to trend down significantly for the remainder of the year.

Finally, with regards to our hedge program, we continue to hedge solely to protect our cash flow so that we can execute our drilling program. We continue to target a hedge portfolio where we hedge about 80% of what we expect to produce over the next 18 to 24 months. Today we have about 27,600 barrels per day of oil hedge for the last nine months of 2014 at an average floor of just under $90. For 2015, we have about 26,300 barrels of oil hedged at an average price of right at about $89; and for 2016 we hedged about 6000 barrels.

We're going to continue to keep our eye on 2016 and then later and position those we can. While our hedging for 2014 is essentially complete, we are about 60% or 65% complete for 2015, and we'll continue to hedge to obtain our targeted levels.

With that, I'll turn the call back over to Floyd.

Thanks, Mark.

Hopefully, the takeaway from this call is that results are excellent on all the core areas. We're on track to deliver or beat our plan for 2014. In each of these core areas costs are under the microscope, and we will continue to reduce costs. However, the more important piece -- or pieces -- of the economic value equation are IPs and EURs. We are making massive strides in those areas. We build our pads and facilities for all-weather production and our weather-related production losses are minimal. Operational excellence will translate into value creation for all of our shareholders.

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

Thank you, sir.

(Operator Instructions)

Neal Dingmann, SunTrust.

Just based on obviously impressive results you've seen on that Horseshoe Hill on obviously drilling that [thing]. Your thoughts as far as timing just on wells going forward? I mean is that, you think going to see more like that or is that more of an aberration?

And your thoughts on costs on these wells? Has that changed, at least based on your initial estimates?

Aberration? You mean an aberration on the low side of high side?

Just how quickly you did it obviously.

Yes. You know, as we mentioned during the call, we fully expect to reduce drilling days, which is the first win in any of these horizontal plays by 15% or 20% through the course of the year. I noticed that one of our peers in the play has reported that they expect to drill their wells in less than 40 days, assuming no major trouble. We are planning on this sort of timing, but we would expect to beat it, of course.

On the cost side, we're walking into this thing, as we do any new play, with full analytical planning in place in terms of tools, log, pilot holes, whatever we think we require. Our initial feel for the play is that we'll drill most of our wells, first few wells for $13 million. We think we can get that down about $1 million a year, each year for the couple of years, and our thoughts haven't changed along those lines.

And then Floyd, what about how critical is the JV to either [accelling] -- [accel] the drilling dots there or potentially even adding more acreage? I don't know how many sizable leases are available, but your thoughts on how much that would play into what happens on the JV or in the near-term?

I might have mentioned it on a call, I'm not sure, but it's 100% about balance sheet management and about providing ourselves a sure path to future growth, meaning rig increases. So we decided to at least evaluate options at this moment, and it's not a critical item to us. We would only do a deal that's attractive to us, and it's just one of the things that we have determined that would be appropriate for us to review for this play.

Our plans for 2014 and our current plan for 2015 will be unchanged in the absence of any kind of a new JV or some sort of financing of that type. The only thing that might happen, we might ramp up a bit quicker at the end of the year and in through 2015, and that's just -- and by the way, that's all based more on results than it is on money.

We are well equipped right now financially to deal with this play, and we're well experienced, in this kind of thing, so the results are the first thing. We got plenty of money right now. Ramping up is an objective, but it's an objective based on results.

Last one if I could Floyd. Just obvious on the El Halcon, the results continue to improve there nicely. Your thoughts about how they trend versus the type curve and thoughts about maybe even bringing that type curve of?

No, we try not to move these type curves around too often. However, there's a clear trend as you move somewhat down-dip for higher IPs and higher 30-day IPs and these typically translate into faster payouts and higher EURs.

As we get a little bit more seasoning in the south end of the play, we're only about, I don't know, about 10% of our wells have even been drilled so far, not even 10%, we'll consider moving the type curve. We would move the type curve for the play for sort of the public consumption. It's clear to us we'll end up with probably three kind of regional type curves for our acreage, and right now the trend would be to be dramatically higher towards the south.

Brian Corales, Howard Weil.

And Floyd, just another question on El Halcon. You talked about going longer laterals. Can you maybe talk about your standard lateral and what you've been testing and kind of the result differences?

We don't know that we're shooting for longer laterals. I think we drilled a couple at 9,000 feet, and we tested a few shorter laterals at 5,000, 5,500, 6000. I think our standard design calls for a 7,500. Charles correct me there. Is it 7,200 or 7,500?

7,500.

7,500.

[Averaging] 7,900 the rest of the year.

Okay. You don't quite know if that's perfect. It might be perfect for it to be 300 feet longer or shorter and depending on the cost. Our calculations yield that, that length is about the right length, and we also, keep in mind in East Texas, we are constrained by the shapes of leases to some extent, and it's harder to put together units there across boundaries, much harder there than almost in any other area.

Just into the Bakken, obviously slickwater, both you and others, I think this earnings season, have talked about success. Is that going to -- do you think that's probably going to become a norm going forward and is there a big cost difference?

I'd like Charles to pipe in here, but it's certainly a norm for us in the middle Bakken. It will not be a norm for us at this stage in our thinking in the [pitches] of the Three Forks. The lithology is a bit different.

As far as the norm for the industry, we are all a bunch of stubborn bastards in our business, as you know, and some of us are -- like me, you have to get hit right between the eyes with things sometimes to make a change. Charles, what you think?

Yes. The results are in the pudding. We've had excellent results with slickwater, that being said, that modified hybrid design with more slickwater up-front is working great also. That's what our last well is, 4,225 barrels a day is. We're going to keep going with what works best. We're never going to stick with one thing and say we have the absolute answer. (multiple speakers)

What about cost?

It's a little higher because of the water costs and depends where you are in the basin in general, but that's a problem you're always try to solve to get water cheaper and find it in better places. And that is a limiting factor for some people in some places, why you might not see as many slick water jobs, also.

Jason Wangler, Wunderlich.

I just wanted to double check and make sure still with the TMS stuff really heating up that, that's not part of your production guidance and obviously you're doing a pretty good job of first-quarter. I just wanted to make sure that anything there would be kind of incremental?

Mark, you might have to help me on that one, but we might have a tiny slice of production in our 2014 plan. If we do, it's something we wouldn't notice whether it's there or not. Is that about right Mark?

Yes. It's probably 500 barrels or something along those lines.

Okay, so pretty negligible.

Yes. Not much. (multiple speakers ) We [daily] exceed that though.

Right. And that was kind of my angle there. And then just curious with the couple wells that you've drilled and starting to drill, are there a lot of changes that you are looking to make as you drill these or are they all kind of going to go down the same ways and then learn from these as you kind of get up the learning curve? Just curious if there's any differences that you're setting up to make as you get into the play?

Of course were going to learn as we go. Charles will make a comment here. There are some variabilities over the expanse of this very large footprint play, some geologic changes that we take note of and manage our way through. Charles, go ahead and respond.

There have been a lot of wells drilled already and we have the benefit of the learning curve that they've gone through. So right now we feel like we have a good recipe down on the drilling side and others do, also.

You're seeing every month people come out with record drilling days for time for drilling days. We're right there with them, and we expect that trend will continue, but we don't see any radical changes in the overall design of where you're setting casing and what you're targeting. That's kind of getting locked in for everybody right now.

The completion side, like all these places, probably where you have a little more to tweak the designs a little bit to get better and better results.

Ron Mills, Johnson Rice.

Floyd or Charles, talk about how in El Halcon and the drilling experience there over the last 15 to 18 months and how that may have helped you in the TMS versus kind of associated with that I guess, on the completion side you talk about tighter perf-clusters but also resin coated sands. Are those concepts also expected to be tested over in the TMS?

I'm going to let Charles answer most of that. I will say that in a general sense, and we've said this before, that El Halcon, the El Halcon area is the closest comp in the United States to the TMS of Eastern Mississippi and Eastern Louisiana and Western Mississippi, and we've had it -- we've been able to gather a tremendous amount of knowledge from working in that very similar same-aged, very similar lithology section. So that has been -- along with as Charles mentioned earlier, the results from the other operators in the plays has been a tremendous help for us to get off the ground running. What else there, Charles, is there important?

No. That's exactly right. We've taken what we've learned there. In fact, we took one of our best rigs from there and moved it down there, flex rig, and that crew, so we've had all the learnings. We train them over year of drilling with that crew, the way we like things done and do things in a safe and in a first-class manner. And so drilling there, combined with our experience of drilling 20,000, 21,000-foot wells every day in the Bakken. So those two backgrounds are a perfect fit for the drilling in the TMS.

And then on the completion side yet, it is similar to what we're doing over there also, and so we're taking that learning, combined with all of our hundreds and hundreds of wells we've previously did in the Eagle Ford throughout the whole [trim] and we expect to hit the ground running on that front with this first well

Ron, in all these plays it turns over time that targeting is tremendously important. At El Halcon we have a very tight area to land and then be able to initiate your fracs, and we're well benefited by having that kind of experience and using it from the very first well on, in the TMS. Because there's certainly a need for very tight targeting in the TMS.

On El Halcon, you talked about the appreciable improvement as you moved south from the southern Brazos County to Burleson County, if you look at your 100,000 acres that de-risked now, how is that acreage broken out from the type wells up in northern Brazos County versus what you and industry are starting to see further south in the play?

We haven't really broken that out, we're still leasing. In fact, we've added significant acreage over the past month or two.

A significant portion of our acreage is in the southern end of the play. At least 50%. Let me just leave it at that.

And now it's not just south. It's also down-dip in Brazos County, so one of our very best wells, and maybe the best one in the play, I don't know, the Reveille, is in the south part of Brazos County down near the line. And as you move east there, you can stay in Brazos County, but go down-dip a little bit.

So you got quite a wide swath of opportunities there that rather than define them as a county kind of a thing or across the river, whatever, we define them geologically, and we have a really large swath of acreage that we feel is going to be somewhat better than that core place we started up in Northeast Brazos County. Which has worked out great, by the way, but -- so we're still in a competitive situation there, and we're not really talking exact spots or anything like that.

And then lastly, on the rig count. You moved one rig from El Halcon over to TMS. Would the plan be to really stay at three, maybe sometimes four rigs at El Halcon?

And just add an incremental rig in the TMS? And then in the Bakken is that three to four rigs versus the current four rigs, is that just driven by efficiencies and managing to that plus or minus $1 billion D&C budget?

It's somewhat managing to the budget, of course. But probably overlaying that, and again, Charles could add to this, but we're finding that with these reduction in rig days per well and drilling these laterals in ever quicker time increments, we're drilling the same number of wells or more wells with fewer rigs as the year progresses, which sets you up for being able to drop a rig and, but still plan on the same number or more of frac jobs, which leads to production growth. Charles, what else is at play there?

Yes. That's exactly right. That's the whole answer right there.

Dan McSpirit, BMO Capital.

Turning to the TMS, can you sketch for us what terms of deal with a financial partner could look like should you go that route? Not talking about amounts so much, but about structure?

Not really. The kind of transactions that you could do along those lines, there's probably 10 or 12 different constructs that are been used in the industry all the way from traditional JVs to just financial placements. And, we would look to do something that suits our needs and suits our thoughts in terms of partner compatibility and cost of capital, and we would look for the cheapest cost of capital with a compatible partner that allows us to increase our targets there, not maintain them because we're already in position to maintain.

So I hate to give you such a weenie answer, but there's so many different -- if and when we do run, we'll report the major components of it, and you'll find that if we do run it'll be a nice addition to whatever we are doing.

Okay. And sticking with the TMS, can you share any expectations on early results from these early wells, including the Horseshoe Hill well? That is, what do you need to see in rate or pressure or other measure to confirm the investment was the right move?

You're looking for big-ass results. I don't know what else to say. We've programmed the drilling and the completion for optimal at this stage of the game, optimal IPs, and frack jobs that last, and we've equipped the wells appropriately, so we don't really have a formula. It seems to be that with the lateral this length and absent any completion problems, we should expect a really attractive -- certainly an IP, and a 30-day IP, but it's -- gosh, it's a little bit out in front of us here.

To meet the tight curves that we proposed, and to meet the type curves that some of our industry partners are using, you need a fairly stout start to make those work, and others are doing it, and we expect to meet or beat our own expectations.

And lastly here on another asset sales, how much production is associated with those assets? Again, these are contemplated asset sales above and beyond what you've done, and where the estimated proceeds to be raised?

We don't really have a ton of other targets. We have some other non-core production, and I think Steve's there, but Steve, is that a couple thousand barrels a day of non-core production that's not associated with the current core areas?

Yes. That's right.

Okay. And those are, I think, largely in Texas, is that right, Steve?

Yes. It's mostly in Texas and in a couple areas in [Austin-shock], and it's mostly actually gassy.

It's good production though. It's really good and that's why we've kept it, and may yet keep it, but it's not troublesome. It got good [op-cost] plenty of drilling opportunities there although we're not spending any money drilling them.

So there's some, and if we decide to cut a little bit deeper, there's some more. Everything else that we own on any significant production is quite good. And that's what we try to do with our planning is to get down to the best of the best and get rid of any thing else.

Robert Bellinski, Morningstar.

Switching back to the Bakken, given these ongoing improvements in performance for these Bakken Wells, is switching from ceramic to proppant to sand an option to save costs at this point or are there any other leverage you're considering to pull to consider that cost improvement?

Charles, why don't you take that one?

Yes. We are starting to phase in some sand and going with mixtures right now, so we are going that direction, and that definitely will save costs, as long as we keep getting the ERs, that is definitely a lever we are looking at very hard.

And then, the drilling in the Bakken was exclusively in Fort Berthold this quarter. Looking beyond the next couple of quarters, is what you're continuing to learn there something that you can use to add rigs to your acreage in Williams County, and maybe drill simultaneously? Or, is Williams County now a second stage of development after Fort Berthold is pretty much drilled up?

Go ahead, Charles.

Like Floyd said, those wells that we just brought on came on great in Williams, and those are downspacing tests. Those are really our first test and their hanging in better than that type curves even though they are downspaced.

That's very encouraging for us, and right now we're putting the rigs where you do get your best bang for your buck. We haven't put out next year's yet but we'll probably be back up in Williams County, I would think with a certain percentage of our rig fleet.

Keep it in mind, Robert, that when you're doing pad drilling, you use a lot of your rig resource on one pad, since we're doing all pad drilling, we intend to maintain that this year and it makes no sense just to drag one of those rigs away. And it also makes no sense for us to try to raise our budget right now because were doing such great work own in Fort Berthold. So there's a time and a place for those Williams County wells and results are good and we're really grateful that we own those assets and we'll be up there probably, as you said, sometime within the next few quarters, maybe 2015.

Steve Berman, Canaccord.

Several companies have been in early stage of testing what they're calling an Upper Eagle Ford and different parts of the plays as it's possible separate reservoirs. Just wondering if at El Halcon that might be something you could have there, if not that, then any other formations you might look to go after somewhere down the road?

Charles, why don't you take that one?

We do have an upper section that has [pay] in it. We think we're fracking into it from where we are, and we don't really plan on changing what we're doing. We're in the sweet spot of the zone and it's repeatable across the entire acreage position, so we're not really interested in going after some other hit or miss type objectives. We're going to stay with what's working well.

One maybe for Mark. Can you talk about the differentials in the Williston basin, the first quarter and maybe what they're currently running?

Let me -- Q1 in the Bakken, we were running close to 90%, and then for the overall company, we were running about 93%, and that is for oil. NGLs were about close to 60% and about 50% for the overall company, but obviously that's a very small part of our production portfolio.

And have those Bakken differentials narrowed at all as we've moved into the second quarter here?

We're probably about the same.

[John Steven], Oppenheimer.

Could you maybe talk about your plans for leasing for the rest of the year? I think in the past you had talked about the most acreage was already taken at this point.

We, of course, have an ongoing lease project in any court area where we try to block up working interest, and in some areas that involves trading around with offset operators and in some areas we're picking up kind of cleanup leasing.

In terms of large leasing ambitions, we don't really have any right now. We're looking for that elusive large deal that's right in the exact spot that we want, but so is everyone else.

So we don't have a huge expectation of anything significant this year. We're just running our programs and picking up things that are strategic in nature.

That's helpful. And I don't know if I missed this in your release, but the $500 million or so of CapEx in Q1, can you break out how much of that was (technical difficulty)?

Mark, you got that?

Yes. We had the amount that we've spent on the TMS, [about] $63 million, and then we did break out in the press release the total was about $100 million, a little over $113 million.

So it's $113 million out of how much, Mark, $500 million?

Yes. Out of the $513 million or so. And I will also point out that, that, full number, the $513 million or so does include an amount for capitalized interest in G&A of about $55 million.

So that boils down to about $345 million for drilling and completion CapEx?

Yes. About $330 million for D&C.

$330 million? Okay.

Yes.

Andrew Coleman, Raymond James.

Kind of thinking about the other non-core assets that you have, I know in the past you all had a couple of -- a piece there associated with the Mississippi line and that was a small acreage block, do you all still have that? Is that something you all at [divesting] or has that acreage expired?

Steve, do you want to respond?

Yes. We still have that acreage in Osage County, Mississippi line area, and that may be something that we could do something with later this year. We're considering it.

Stepping up to the Bakken, the last couple of questions that were there, a couple -- a few minutes ago, I guess -- have you all looked at [coil] across your completions or just slickwater at this point?

Go ahead, Charles.

I think you're probably talking about the system-wide [infusion]? We're looking at that. Like we're looking at everything, we don't see a big cost difference, and right now the guys are doing a great job. We're not going to change anything radically right now. We don't see -- our results are dictating no need to right now.

Thank you very much for your time and good quarter.

Well thank you. Thanks everyone for dialing in. If something didn't get asked or we didn't cover, if there's anything like that, just give us a ring, and we'll talk to you again soon. Thank you.

Ladies and gentlemen, thank you for participating in today's conference. This concludes the program.