Good day, ladies and gentlemen, and welcome to the Quarter 3 2014 Comstock Resources Earnings Conference Call. My name is Matthew, and I will be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. And now I would like to turn the call over to Mr. Jay Allison, Chairman and CEO. Please proceed, sir.

Matthew, thank you, and thank you for all the stakeholders that are joining us. I know there's a lot of competing conference calls during this hour, so thank you. I've got a few opening comments before we go through roughly 26 pages of slides, where we'll report our results for the quarter. We acknowledge that oil is going through an ugly cycle right now, and we don't nor does anyone else know when or where the cycle will bottom. So before Roland and Mark report, let me make some observations about Comstock. First, we are pleased to report strong growth in oil production, which drove grow revenue and cash flow growth for the quarter. Our [ph] shale drilling program in South Texas continues to be successful, and we are now derisking our 31,000 net acres in the Eagle Ford shale in East Texas. In fact we're extremely pleased that Apache, which has 8 rigs currently active in the play, may significantly increase their rig count. And Anadarko, along with partner KKR, about 10 days ago announcing that they may drill as many as 500 wells in a region that we're in. And we see Clayton Williams at Halcon continuing their drilling programs in the Eagle Ford shale and East Texas. All of that is good news for Comstock because we believe our 300-plus drilling locations in the region will be materially derisked earlier due to all the aggressive drilling in the Eagle Ford shale in East Texas. Our goal to you as a stakeholder -- we have several. We'll put them before you before we go over the results. One, we want to keep a low-cost structure; two, hopefully increase our EURs and IRRs of Eagle Ford wells with new completion designs Mark Williams will talk about in a moment;…

Thanks, Jay. On Slide 4, we recap our oil production growth, which has been driving the growth that we've had in revenues, cash flow and earnings this year so far. Our oil production increased to 12,200 barrels per day this quarter, which is flat to the second quarter rate. We've fallen behind in our new ventures area given the completion setbacks in Burleson County, and then we've had higher-than-expected shut-in activity and especially in the month of September for offset frac activity on 14 wells. Our oil production has increased 78% from the third quarter of 2013. The last quarter of this year, we're expecting oil production to average between 11,500 barrels to 13,500 barrels per day, and that rate will be very dependent on the timing of completions that we have planned for the fourth quarter. Overall, this would give us 83% to 91% growth over last year. Slide 5 shows our natural gas production, which continues to decline and was down 29% from the third quarter last year to 105 million cubic feet per day. With no natural gas-directed drilling taking place this year, we expect our natural gas production to decline further into the fourth quarter and to average around 96 million to 101 million per day. Slide 6 shows our realized oil prices this quarter. Oil price realizations as compared to WTI continued to improve in the third quarter of 2014 but were not as strong as they were last year. We realized $95.92 per barrel, down from the $104.83 per barrel we realized in the third quarter of 2013. Our realized price averaged 99% of the average benchmark at NYMEX-WTI price; 56% of our oil production was hedged in the quarter at a NYMEX-WTI price of $96.60 per barrel. So after our hedging program, our…

Thanks, Roland. Slide 20 shows our South Texas acreage and our 2013 and 2014 drilling activity. We have completed 181 wells so far on our South Texas Eagle Ford acreage through October of this year. Our wells have had an average per-well initial production rate of 736 barrels of oil equivalent per day. Wells reported this quarter averaged 792 BOE per day, higher than last year's average of 780 BOE per day. Slide 21 illustrates our well cost history in our South Texas Eagle Ford program. The cost of our Eagle Ford wells have decreased considerably since we started drilling in August of 2010. In 2010, our first 2 wells averaged $11.4 million. So far this year, we reduced our average well cost to $6.7 million. Faster drilling times, lower well stimulation costs and more efficient field operations account for much of the savings. Our joint venture further enhances our return as the effective average well cost in 2014 to Comstock on an 8-age [ph] basis improves to $5.7 million when that KKR spud fee is considered. Our next group of completions, we will reverse this trend with larger stimulation treatments. The larger frac jobs, which involve more stages, more proppant and more fluid, will increase costs by 20% to 25%. We expect to see improved IP rates and EURs of up to 30% based on this change. The net result could be up to a 50% improvement in well rate of return. Slide 22 shows the acreage we have accumulated in Burleson County, targeting the Eagle Ford shale. We are up to 31,000 net acres in this play. Slide 23 shows recent activity in the vicinity of our East Texas Eagle Ford acreage where we are currently operating 3 drilling rigs. Our first well, the Henry A #1, located…

All right. Thank you, Mark. And also thank you, Roland. On Slide 26, I'll summarize our outlook for the rest of the year. Growth in our oil production has more than offset the natural gas production declines that we have seen. Our oil made up 41% of our production this quarter as expected to increase 83% to 91% over last year. We're expanding our inventory of oil drilling locations by acquiring acreage in 2 emerging oil plays. We're excited about the level of activity in both of those plays as offset operators have had successful wells near our acreage, and we've now drilled our own successful wells in the middle of the new play in Burleson County. We think we've added over 300 locations in our inventory in Burleson County. We continue to have one of the lowest overall cost structures in the industry. In fact our new completion designs, as kind of Mark alluded to for our Eagle Ford wells, should increase our EURs and our IRRs. Larger fracs can result in 30% higher IP rates and 20% higher EURs. The result is a potential for a 50% improvement in the well's IRR, which could help offset lower realization of oil prices. Improved completion technology opens the door for our natural gas properties in the Haynesville. We have to have good returns even in the current natural gas pricing environment. The longer laterals and better fracs allow these wells to have much higher IRRs. We also have the potential to refrac our 135 producing Haynesville wells, which could increase gas production for a small capital investment. The most important message we want to deliver today is that we will maintain a strong balance sheet rolling into 2015 with the current oil and gas price uncertainty. We have around $400 million of current liquidity, and we'll be targeting our 2015 drilling program to stay close to the cash flow that we will generate. We have a lot of flexibility with our assets and can manage drilling obligations in 2015 with only a 2-rig program. Lastly, again, we currently plan to maintain our $0.50 annual dividend. So for the rest of the call, we'll take questions only from the research analysts who follow the stock. So Matthew, I'll turn it back over to you.

[Operator Instructions] And your first question comes from the line of Don Crist of Johnson Rice. Donald P. Crist - Johnson Rice & Company, L.L.C., Research Division: Starting in East Texas, Jay, can you talk about the current well cost? I mean, obviously, we know what the Mach costs with the write-down. But can you talk about what the Curington costs and what EURs you're are using for that and what you think that will go to with the enhanced completion?

Mark -- yes, I'll let Mark start it. And then, Don, I'll finish it.

Yes, Don, this is Mark. Our type curve has not changed for the area. We don't have enough information yet really to make a change to the type curves. I think our original type curve was around 400 MBO, and that's kind of what we're basing our economics on and our decision-making on. As far as well costs, our first 2 wells were pilot holes. Those costs you can kind of throw out the window with all the science and learning curve and everything else. Our Curington I think should run around 9.5 million, which is kind of what we expected these individual wells to cost with their -- with the original frac design. I think the Flencher was actually a little bit less than that even, probably average maybe in the 9 million range on those. And then the frac design change in this area is not quite as dramatic as it is in South Texas. So we're probably looking at about $1 million to $1.5 million increase in the frac design cost.

And Don, we've -- again, we've -- I think we're on our ninth well now in that East Texas Eagle Ford program. I know we're drilling on Platsach [ph] With 2 rigs. We have 3 rigs active there today. We've got a Helmerich & Payne rig that's kind of the roving rig, and it's drilling on all 4 to 6 sides of the acreage that we own, the 31,000 net acres. And then we're infill drilling the first Henry well that we drilled. We've got 2 rigs active infill drilling that. And again, if you -- I mentioned earlier that's -- kind of to the west and to the north of that is where Anadarko had announced their big program. We think with KKR and Apache it's like, I think, to the north of it. So -- now, and another thing I would comment on, the well spacing. The wells that we're drilling right now are anywhere from 800 to maybe 1,000 feet apart. We're going to drill probably 6 or 7 of those. I think some of the offset operators are drilling wells on 500-foot spacing, so we don't really know which is the best formula there. We're going to do both. And in the interim, we're going to drill, hopefully, on all 4 to 6 sides of our footprint and materially derisk that by year end. Our goal beginning of -- really the end of 2012, beginning of 2013 when we knew that we would monetize the Permian -- and if you think about the time frame on that, I think it was May of 2013 that we got the wire and we made the $231 million of profit. So we knew that by the end of this year, our South Texas program we would've drilled at least…

Yes, we have a rig on contract through November of 2015. We have another one August '15. We have another one December '14 and another one. The other 2 are kind of mid '15. So all of those, I mean, they're all in pretty good shape. If we wanted to drop a couple of rigs, we could have. We have a 5-rig program right now. We have 1 in South Texas, 3 in East Texas, 1 in the TMS. We do have a rig that is on order that we can bring in and either add it to the fleet or get rid of one that we have, but there's some flexibility in what we're doing. We don't have 2- and 3-year rig contracts at all. Mark may want to add some color to that, but that's what I know.

That's exactly right. Everything that we currently operate expires by the end of next year between now and -- between December 31 this year and the end of next year, so we have a lot of flexibility to reduce the rig count if we feel we need to.

And I think that going into the TMS, I mean, we're extremely positive about the TMS. I mean, we think the reserves are in place. The issue there is can you reduce the cost? And I think the other operators in that area have shown you that their EURs are exceptionally strong, and their drilling costs are coming down. Now the wells that we're drilling, I mean, we're going to spend probably 80 days or so drilling this well, maybe longer because it's the first well. We're drilling a pilot hole. We had to deepen it. We had to log it. We had to plug it back and then we had to -- and that's the well that we contribute the data to this consortium of companies. And so you -- we knew it'd be longer, take a longer time to drill it, but the question is can we drill those wells in the TMS in 35 days or less? And we think we can. But I think more important in the ugly oil cycle that we're in is do we have to drill any wells in the TMS to hold our 70,000, 75,000 net acres. And what we've looked at, right now we would keep this rig busy through the third well, which is the Meeks well. We'll drill the 2 Foster Creek wells. And again, the well we're drilling now in the TMS we're offsetting the single best well in the play, which is the Crosby well -- the Goodrich well. So we'll complete that. We'll drill another well pretty close to that. We'll drill the Meek well, and then at that point in time, with a low oil environment, we could shut the program down and -- I mean I don't think we'd lose any acreage in…

Your next question comes from the line of David Amoss of Iberia Capital.

Jay, I want to ask again on -- a follow-up on the refracs in the Haynesville. Do you guys have kind of an order of magnitude estimate on what that may cost? And then, how quickly can you get going on those? And when should we see the first flood [ph] of results from that program?

Yes, and again, I want to preface all this. This is kind of early innings, but I mean, we're super excited about it. But it is early innings, and what we don't want to do is go spend a whole lot of money and figure out it doesn't really work as we would project it to work, even though there's 2 or 3 companies out there doing it right now. So I mean, we're -- we always take that baby attitude; that's a little bitty baby step at a time. And if we see it works and we'll be a Michael Johnson and be a world-class sprinter but -- so with that, let me give it over to Mark, and he can give you the color that he wants to give you right now.

All right. Yes, David, this is Mark. As far as costs go, we think those costs will range between $1.5 million and $1.8 million per well to go [indiscernible]. We've got to remove the tubing, clean the well out, refrac it, reinstall the tubing, flow the well back, do all that to get them cleaned up. So that's kind of what we're looking at. We're screening candidates right now and plan to have something in place to -- kind of a pilot project on this about right around the end of the year. And then we'll look at those results and build the component of our budget next year based on those results. It'll probably be an add-on to the budget or a change in the budget sometime next year if we see the results are positive, but we're not talking about a big incremental change in budget dollars when you're talking about $1.5 million a well. And if you did 10 of them, you're -- it's $15 million, so it doesn't really move the needle much capital-wise. But results, we've heard anywhere from $1.5 million a day up to about $4 million a day, kind of on the high end is what we've been hearing from some of the other operators. We plan to try to share information with some of them to obtain more data on what they've done and what's been successful to help us along the way too. But right now, I'd call it kind of a pilot project and not really an implementation of something known. Kind of like Jay said, we want to prove to ourselves it works and then we'll look at implementing it on a grander scale.

Now in addition to that, we are thinking about redrilling -- drilling some of the Haynesville wells and drilling them out either 5,000-foot or 7,500-foot laterals. And with the new completion techniques that debuts in the Marcellus, elsewhere, you take that new-age technology in the Haynesville, I mean -- yes, the Marcellus is the #1 shale gas field in the world, but it had to jump over to Haynesville in 2012 to get there. And the Haynesville was developed with old completion technology. You add some of that in -- the new technology in today, and it's going to be pretty eye-opening we think. As far as the rate of return we might get at the Haynesville program, again, we've owned that acreage forever. It's been paid for forever, and we've only drilled 10% of our footprint. So we think there's a lot of upside, particularly gas is $4 today, and winter has just started. So we will take a hard look at that, and sometime in the middle of December, we'll come out with our 2015 budget. And if you need to know as a stakeholder, we have no hedges in play for oil or gas in 2015 right now. So we're going to take where the SRP [ph] is and work in a budget and see what that will allow us to spend in all of our areas knowing that the 2-rig program we can keep all of our acreage, but knowing that we need to grow our production. But more than grow it, we're going to look at rate of return. That's where we're going to be focused on.

Okay, got it. And then one more. In East Texas, some exciting results there. It sounds like you're increasing the rig count as we speak. Mark, can you kind of give us -- if you're in development in '15 and your pads, how quickly are you drilling those wells? And I guess, the number I'm really after is 3 rigs can drill how many wells in development mode in '15.

David, we've been drilling our wells -- our well time from spud to TD has been averaging about 19 days. So on -- pad to pad, you're looking at about 10 days. And on an existing pad, you're looking at about 5 days. So say, on average, about 26, 27 days. So you're looking at 13 wells per year per rig is about a pretty good average. Maybe 14 if we improve things a little bit.

Your next question comes from the line of Jeffrey Campbell of Thule Investment Research.

First thing I wanted to find-- this is -- not trying to kick you when you're down. I just want to kind of understand it better. Can you add some color on why you had the casing failures in East Texas and what you're doing differently to avoid it in the future? What you learned from it?

Yes, look. That's not kicking us when we're down. That's just a good, honest question, so we should be accountable for that. And I'll turn it over to Mark to be accountable. Mr. Williams?

Yes, Jeffrey. Yes, really we had 2 different issues on 2 different wells. The first one, the Mach, we kind of -- an issue where we perforated a little bit higher in the section than we really probably should have, and we had ended up resulting in a casing collapse above the last set of perforations. When you run the calculations on the strengths of materials and things like that, there's no reason it should do that, but it did. So it's -- one of the things we're doing there is we're going to be cognizant of that fact and be more careful to stay away from our intermediate streams, stay away from the upper part of the Eagle Ford down -- stay more down in the target window with our perforations and eliminate that issue in the future.

And even though we shouldn't have collapsed with the integrity of the casing, we did make a human error, and we completed it too far into a depleted formation. So it's a human error. We did that. That's a corporate failure. And we -- it is what is, so we don't color it any different.

On the second well, on the Flencher well, we had a casing obstruction after the sixth set of -- sixth frac stage when we went in to drill out the plugs. And we've looked at our frac data. We don't see any indication of that during the frac job. We believe that is probably a geologic hazard that we -- a small fault or some type of movement that we created with the high pressures of the frac job. We see that on a rare occasion in both the Haynesville and the Eagle Ford, and we hear about it in the other plays as well. It doesn't happen often. I mean, it's been much more prevalent in the TMS than it has been in the other plays. It doesn't happen very often, but it does happen. The main things you try to do there is you try to minimize drilling through any geohazard that you can see with any seismic that you have available. The other thing we did is we changed our casing design. We basically strengthened it one step up. And even though there, again, when you run the numbers, it shouldn't have come close to a failure point; but just to provide us more safety factor, we've increased that, and then we're looking for any geohazards on our steering plots. And if we see one, we'll adjust the perforations to try to avoid that a little bit more than we have in the past to try to minimize that risk of that happening in the future.

Okay, that was more forthright color. I appreciate it. You brought up the subject of TMS and cost, and I think it's pretty obvious that's what people care about because we're seeing good wells coming out and no one seems to care. Can you give us some kind of idea of what sort of combination of EUR and well cost you would need to get to, to be able to be able to make acceptable returns in the TMS if we stay in this sort of persistently low oil price for a while?

Well, I think what we look at initially, I mean, we were hoping we could have somewhere north of 500,000 recoverable EUR and -- I mean, I think Goodrich averages 500,000 to 600,000. I think that's very achievable. And I think even in Canada, they said 600,000 to 750,000. I mean, we -- when we went in the TMS -- you have to go back when we went in. And when we went in it, Encanca have not had the success they had this year. They had failures. Devon had had their failures. Halcon had had failures, and then they reentered it. Sanchez is not there, and Goodrich was struggling. In 2013, I think, there's 6, 7, 8 of the TMS wells may be drilling completed. This year maybe there's 50 or 60. And we went back in it geologically because our geological -- geophysical group felt like the oil was in place. So that's one of the big checks is if we can reduce the drilling and completion costs for the reserves there, we've got to let [ph] that work. That's why we've got that little stretch of property maybe 60 miles long, 20 miles wide or so. And then as Halcon comes back in and Encana has success and others have success, we say, "Wow, we think our geological group was right in the core." And then again, we -- the very first anchor that we put in the TMS was Wilkinson County because we wanted to -- the big old oak tree is the Crosby well, which Goodrich has, and we wanted to be near it. So we lease from the Crosby family that 33,000 net acres. So as it has been derisked, we said, "Well, okay, the reserves are there." The question is though, do you…

I can add a little bit to that, Jeffrey. Jay was accurate on the cost. I mean, our initial model was around $14 million for these first wells without problems. And then once we got into kind of drilling mode on single well pads, we're looking at about $13 million. And then our plan in kind of full a development mode with the efficiencies of scale, which should get cost down between $11 million and $12 million. So if you look at that at $80 oil and 600,000 to, say, a 500,000 MBO type curve, you're still looking at probably 25% to 30% IRR. If you're at a 600,000 MBO-type curve, like Encana and Goodrich, or projecting off their wells, you're probably still looking in between 30% and 45% IRRs. So I mean, it's an economic play. If you can eliminate the problems and get more consistent results. And obviously, with us, we just have to drill one well. So far, we don't have anything to make -- to talk about from a consistency point of view, but we're seeing it with Encana and Goodrich and Halcon in the field in terms of being able to drill the wells with many less problems than they were having early on and stimulate them and get them on production at pretty significant rates, and the wells are holding up. So we're pleased with everything we're seeing. We just need to get on that learner curve with those guys and prove we can do it.

Yes, that repeatability factor, that's what the play needs. It needs to be repeatable from 1 or 2 or 3 operators, including ourselves. And then you can structure in that cost and then -- I think the EURs are going to be really good. We would never worry about the EURs. We always worried about the costs.

I think that was a very helpful overview. If I can ask one last question. I was just wondering -- because we've talked about this before -- what's the current timeline to do a test of the wet gas in the East Texas acreage? And is that going to be delayed due to the current commodity prices? And that's it.

Now once the William well is KD'ed [ph], which the William I think we're 3,400-foot lateral right now, I think that well moves over to the Lewis. I may be wrong, and then the Lewis is kind of southeast. Is that right, Mark? Is that where it goes?

Yes.

And then that'll start testing -- again, the southeastern part, which is where we think we'll probably have 60%, 70% oil, and the rest gas. I mean it'll be...

Yes, I think we -- we're working our way down depth kind of as we built units and can get units put together. Texas is a much more difficult land situation to build long units than Mississippi and Louisiana or so it -- it just takes more work to do that. But I'll say this, we don't have any wet gas acreage that we -- as far as we understand it, we think we are either black oil or volatile oil. So I don't know that we're going to test the wet gas anywhere.

Yes. It -- I mean, we're as excited about that acreage as any of our acreage. And then we'll move that rig north, kind of northeast, and it's what's what we call the Kathy well. And that's an H&P rig. It's kind of the roaming rig that's drilling all 4 to 6 sides. And then we'll use a couple of rigs to drill these pad wells with the Henry, and they will come out in the middle of December with a budget for 2015.

Okay. That's helpful. And yes, we'll stand corrected and call it volatile oil from now on.

Your next question comes from the line of Sean Sneeden of Oppenheimer.

Roland, certainly appreciate the commentary on living within cash flow next year. Just assuming if you were to do that, what do you think your overall production decline profile might look like?

I think looking that we'll -- looking at next year's opportunities, that we won't have a production decline. We'll actually be able to -- if we add some -- a little capital toward the gas side, I think we'll be able to maybe have a little bit of growth in gas production and then have a -- we'll probably have a fairly low increase in oil production given that we ramped it up so much this year. So we're still looking at what and where we want to allocate the capital to, to generate the best type of production profile for next year. And given commodity prices are moving around a lot now, we'll make our final decisions in December. But I think by taking away the gas decline we've had this year I think our overall production probably won't be down next year like it is this year.

The models we've looked at right now -- we've got several different models,. We've already looked at them. We -- like Roland said, we'll have -- if you stay total within cash flow, we should have slight oil growth, and we could have -- depending [ph] upon how the wells turn out in the Haynesville, you could have some pretty decent growth in gas, and the numbers look pretty decent. And that, again, that's keeping our almost $400 million of liquidity. That's pretty phenomenal for a company like ours.

Sure. No, that's helpful. Maybe as a follow-up to that. If you were to kind of ballpark your current corporate PDP decline, where do you think that stands as we sit here today?

That's hard to gauge, but I think the gas is, obviously, a lot much more mature now and not near a lot of -- we don't have a lot of the -- the higher -- the early years that have the higher declines in the gas production. So it's probably 15% to 18% kind of base decline expected as we get beyond the fourth quarter.

Well, we've got a lot of new oil online, so I'm sure that GDP is fairly -- is still fairly high, over 50% type decline in our oil production with no new drilling.

Okay. No, that's helpful. Maybe just one last one on the balance sheet. In order to have -- how I should be thinking about next year, but would you say in broad strokes that your general goals is to maintain leverage under 3x and have a minimum of, call it, $150 million or so of liquidity? Or maybe talk to me -- talk a little bit about how you're thinking about that.

Yes, definitely. Those -- we would definitely want to exceed the 2 goals that you just said, both on the leverage -- our overall target is to stay at 2.5x, and that's been -- that's our -- one of our -- that's the number we feel like we should be -- try to keep the company around, so -- and then we'd like to have a little more liquidity than that, so at least a couple of hundred million, $250 million of liquidity that's just available that's not committed to a capital program. So yes, we really have more than that now, so it's really about what do we spending for next year. This year, we invested a lot in acreage. We don't really see a need to invest in acreage next year. We've got a lot of big portfolio projects to work on. So we'll see -- we'll just see maintenance costs to maintain our acreage next year and not the big investment there.

Well, I think with the derisking of our East Texas Eagle Ford footprint, I mean we're -- when you add that with the TMS, companywide we'll have never had more drilling locations, period. Plus we will have never had higher oil production rate. Plus we've never had a higher potential program in the Haynesville. When we first drilled the Haynesville in '08, '09, '10, '11, it was in the infancy of shale completions. I mean, I think we're sitting on a gold mine. So with a good balance sheet -- and all that was because we never really felt comfortable that oil is $100-plus commodity, and we made the greatest derisking move in our corporate history by selling the Permian and monetizing that. And like Roland said, then we spent -- out of our $231 million of profit from that, we spent about $175 million on the acreage position that we have in the TMS and East Texas Eagle Ford, and I think those were good bets. And we intentionally looked at how the leases were structured because we thought if oil prices collapsed which -- I've been doing this 20 -- 34 years and at least 6, 7, 8 of these horrible cycles -- and that's not only oil, it's gas too -- you have to prepare for some downtime. And we didn't want to monetize the Permian and get in trouble with lease obligations and get back in the same rut, and you can see today we're not in that rut. But that's -- a lot of that was -- most of that was intentional. Some good fortune, but it was intentional.

I now would like to turn the call over to Mr. Jay Allison for the closing remarks.

Matthew, again, I love your speech. I know you're not from Texas, and I'm so thankful that with the competitive companies that have the conference call between 10:00 and 11:00 those of you that chose to listen to this, I mean, we're going to work our hardest every day. We're not going to color something different than what it is. If it's really good, you'll know it. If it's really bad, you'll know it. And if we're in tents [ph] somewhere in between, you'll know that, too. We acknowledge that oil is in an ugly cycle, and we think it could get worse. Now I hope it doesn't. We hope gas stays at $4 or above. And our commitment to you is to not lose our liquidity and to manage this company as you would expect us to because you trust us if you're a stockholder. So with that, I'll adjourn the meeting. Thank you.

Thank you for joining today's conference, ladies and gentlemen. This concludes the presentation. You may now disconnect. Good day.