Battalion Oil Corporation (BATL) Q4 2014 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to your Halcón Resources 4Q 2014 and Full Year 2014 Earnings Conference. At this time, all participants are in a listen-only mode. Later, we'll have a question-and-answer session and instructions will be given at that time. I would now like to introduce your host for today's conference, Chairman and CEO, Floyd Wilson. Sir, you may begin. Floyd C. Wilson - Chairman & Chief Executive Officer: Thank you. Good morning. This conference call contains forward-looking statements. For a description of our disclaimer, see our earnings release issued yesterday afternoon and posted on our website. So from an operational standpoint, 2014 was another good year for Halcón. We consistently exceeded production expectations, despite through the second half of the year reducing rig count throughout. Proved reserves increased by 60% during the year and drill bit reserve replacement was 570%. We've reduced our 2015 drilling completion budget several times over the past few months. Service costs have come down significantly and continue to come down since the beginning of the year. Companywide, we currently have 26 operated wells being completed or waiting on completion. We're operating three rigs, two in the Williston and one at El Halcón in East Texas. Up in North Dakota, we had 57% production growth year-over-year in 2014. We will concentrate our two-rig drilling program during this year in our highest return area. And since it's only two rigs, there's minimal impact to our operated drilling inventory due to the low rig count. Completed well costs in this area have come down 25% since the fourth quarter of 2014; we expect to see more. The current AFE for wells drilled on acreage in the Fort Berthold area is less than $8.5 million. Wells we spud in that area continue to outperform our published 800,000 Boe type curve. Drilling and completion efficiencies are ongoing as always at Halcón. Our drilling cycle times spud to rig release improved by over 20% on the reservation and approximately 15% in Williams County last year. Our completion cycle times, rig release to the end of the completion improved by over 30% companywide. During 2014, up in North Dakota, we have been utilizing a modified or hybrid slickwater completion design in an effort to further decrease completed well costs and also the results have convinced us to move forward with this completion design on most wells. This frac job is designed to place the same amount of propppant, but use less water. We've also had some success in reducing operating costs, more efficient power sourcing, better produced water offloading solutions, better chemical programs and effectively managing our workover program, including offset frac preparation. We also continue to make progress in pipeline construction to increase gas capture. Approximately 84% of our gas produced in the Williston Basin is now being sold, which is well above the limits imposed by the NDIC. At El Halcón in East Texas, we have production growth of 136% year-over-year. We operated an average of three rigs in El Halcón during the fourth quarter, but we quickly dropped two of those rigs and we have one rig running there now. Our 2015 drilling program is designed to capture leases and hold acreage. We remain focused on identifying ways to reduce completed well costs. The current AFE for wells we drill in Halcón is approximately $8 million or about a little more than 20% lower than where we were for most of the fourth quarter. We anticipate completed well costs will decline by an additional 10% to 20% by midyear. Aside from the across-the-board service cost reductions, we're also insourcing certain items to reduce middlemen cost: some mud, directional work, several types of supervisor work brought in-house. On the completion side, we're looking to directly source materials for our frac jobs, plus we've been providing our own chemicals since December and this is going quite well. It's important to keep in mind that we're still in lease capture mode at El Halcón, which means we are only drilling one well pad per drilling spacing unit. This means that the current AFE includes full cost for location, tile opinion, production facilities, gathering tie and artificial lift expenditures, all charged to the first well. That's about $1.25 million on a per well basis that you would expect to see a reduction once we're in development mode. Drilling efficiencies continue to be realized. Our drilling cycle time for three-string wells improved by approximately 30% in the second half compared to the second half 2013. Our completion cycle times at El Halcón improved by more than 35% throughout the year. Bottom-line, we have 100,000 net acres in the core of this great oil play, and we'll keep that position vibrant. Mark, go ahead with the financial results. Mark J. Mize - Chief Financial Officer, Treasurer & Executive VP: Okay. Thanks, Floyd. I'll begin with a review of the full year 2014 results as compared to guidance and also touch on fourth quarter results. Production for the year came in above our guidance and averaged right at 42,107 barrels of oil equivalent a day. The production in the fourth quarter was 46,000 to 76,000 Boe a day, which is actually a record for the company. On the cost side, LOE was $9.52 per Boe in 2014, which is within our guidance range and about 20% lower than prior year. And then LOE was right at $9 per Boe for the fourth quarter. After adjusting for some selected items, cash G&A was $5.98 for the year. It came in well below guidance and about 33% lower than 2013. And then if you look at G&A for the fourth quarter, it came in about $4.80, representing about a 21% improvement quarter-over-quarter in the second half of 2014. Taxes other than income were $6.92 per Boe, which is in line with guidance. And so as you can see, overall operating cost across the board this past year have improved, and we'll continue to see some improvement in 2015. We did end the year with liquidity at about $553 million, which consisted of our undrawn revolver capacity plus cash on hand. And we were right at about $580 million of liquidity if you take into consideration the December hedge settlements that we collected in the first week of January. And as disclosed in our earnings release, the $1.05 billion borrowing base within our revolving credit agreement led by JPMorgan and Wells Fargo was recently reaffirmed in conjunction with our regular spring redetermination in this environment. That just further validates the quality of the core assets combined with the hedge book that we have in place. And this liquidity position clearly sets up the company nicely to fund its 2015 operations and well into 2016. With regards to D&C funding, we spent right at $1.2 billion last year, which was more or less in line with expectations. We're very focused on both capital discipline and efficiency in 2015 as indicated by our reduced 2015 capital budget. And our current D&C budget for this year of, call it, $350 million to $400 million is still going to translate into about 5% production growth. In addition to the reduced budget 2015, it puts our capital spend more in line with cash flow. We did recently reaffirm previously disclosed production and cost guidance for 2015 and provided first quarter 2015 production guidance in our earnings release issued yesterday. We expect production to be relatively flat the first half of the year, with an overall growth rate of 5%. And D&C CapEx will be front-end loaded, primarily due to the number of wells that are currently being completed or waiting on completion. And finally, with regards to our hedge portfolio, we did have a mark-to-market at right around $0.5 billion on our hedges. Today, we have about 31,332 barrels per day of oil hedged in 2015 at an average price of just over $90 a barrel. And for 2016 we have about 20,497 barrels of oil hedged at an average price of just under $85 a barrel. While our hedging for 2015 is complete, we'll continue to layer in additional hedges in 2016 to attempt to hedge about 80% of what we expect to produce at an average floor of no less than $80. With that, I'll turn the call back over to Floyd. Floyd C. Wilson - Chairman & Chief Executive Officer: Thanks, Mark. So here we are in middle of the quarter, first quarter of this year. Things have changed dramatically from last year, but they're changing all around the board, not just on oil prices. Costs are screaming down, and we're finding that we're targeting single well rate of return targets – single rate of return investments that are similar to what we had last summer with the lower cost. We're comfortable with our liquidity right now in this year's drilling program. Our strong hedge portfolio has positioned us well in this environment. Having said this, we're not the kind of company that sits around in hopes that things get better over time. We're constantly thinking about ways to strengthen our balance sheet, which in turn will put us in a better position to take advantage of opportunities in the areas that we care about. We've been through this before, and we'll be through it again sometime. So I think that's all I have to say. Operator, you can take a few questions if there are any.

Our first question comes from Neal Dingmann of SunTrust. Your line is open.

Good morning. Say, two questions. First, you previously mentioned in your prepared remarks about the Bakken well costs. I know those continue to come down for you. Could you discuss about as far as how much ceramic you use in the proppant. I'm just wondering there if you're pretty set in the current recipe or can you continue to cut costs with that? Floyd C. Wilson - Chairman & Chief Executive Officer: (11:14) I'll make a brief comment and then he'll really respond. Looks like we're going all the way to white sand. We've had enough wells and our peers up there have drilled enough wells with this. We haven't really seen a huge difference and it saves a lot of money per well, $0.5 million to $1 million, barrels, and it'll depend on which well you're on. So some of the cost reductions are due to different design, but a lot of the cost reductions is due to just lower service costs. Charles, would you add to that? Charles E. Cusack - Chief Operating Officer & Executive Vice President: That pretty well covers it. But the key is what Floyd says: going 100% white sand. And it cuts that $0.5 million or so off of it. And we have – with our large non-opposition we're in with a lot of other companies and there's enough production history now from wells that just have 100% white sand, (12:05) and we don't see any difference in the basin. So we're very confident going into that direction. Floyd C. Wilson - Chairman & Chief Executive Officer: Also Neal, in certain areas, putting some gel in a slickwater frac reduces the water requirement. And in the north, water is not quite expensive and down at Fort Berthold, it is quite expensive. So that's a big factor as well.

Yeah, great point. And then just one last follow-up, Floyd. Just wondered, you look at liquidity out there, obviously, you guys have no problems there. So just wondering, how do you view the M&A market or more specifically are there any bolt-on opportunities you have and any interest in doing any step-outs with this kind of macro environment? Floyd C. Wilson - Chairman & Chief Executive Officer: We're very comfortable with where we are. We'll continue to grow the company for the next few years and see what goes on. The M&A market seems to be a bit quiet right now. There's a lot of shock, and shock out there with how quickly things have moved. Historically, these times create opportunities and we certainly have our eyes open. We're very focused on quality in core area disciplines. So you wouldn't expect us to try to do anything that wouldn't follow those comments.

That makes sense. Thank you.

Our next question comes from the line of Ron Mills from Johnson Rice. Your line is open. Ronald E. Mills - Johnson Rice & Co. LLC: Hey, good morning, Floyd. Maybe for you or Charles, on the production history with the hybrid slickwater and/or the use of white sand versus the resin-coated sand, how much production history do you have on using those methods? Do you still feel comfortable that the wells are outperforming as we see in your new presentation? Charles E. Cusack - Chief Operating Officer & Executive Vice President: We have a about a year on three wells that are all white sand. The ceramic wells, we have a couple of years now, plus others. But in our non-op wells and wells around us there's a couple years on all of them. And we don't see any difference at all. The bigger differences are the amount of proppant and fluid or amount of proppant in place, not the type. Ronald E. Mills - Johnson Rice & Co. LLC: Okay. And then as you talk about self-sourcing portions of it, Floyd, I think you mentioned mud maybe even some proppant and chemicals, how much of that $1.5 million of cost savings so far do you think is related to the self-sourcing versus vendor pricing? Floyd C. Wilson - Chairman & Chief Executive Officer: There's some of all that in there. The self-sourcing is more along the lines of supervisory services, which we used to farm out a lot. We're trying to do as much of that in-house as we can, so it's a combination. But over time, we expect this in-house insourcing that we're doing to be quite a factor. And also, not that we weren't close, but keep us really close to exactly what's going on minute by minute. We stay close, as you can tell from our results, but we'll be even closer. Ronald E. Mills - Johnson Rice & Co. LLC: All right. And then, Mark, just on the hedging side. Obviously, 2015 looks like you're pretty much done. As you look to 2016, how dynamic has the hedge market been, given the volatility in this? In other words, ability to look out 12 to 18 months from now and what kind of structures allow you to meet kind of that $80 minimum floor? Mark J. Mize - Chief Financial Officer, Treasurer & Executive VP: There's been pockets of opportunity where we've been able to layer in some additional hedges. But really what we've been doing and are looking to continue to do is a slight bit of restructuring, where we can take some value out in the future year, kind of bring it forward and utilize it to maybe buy up a position whenever you get a little bit of a run in the oil market. So we have a plan where we think we are going to be able to it – depending obviously on what the markets do exactly – but we don't have that much further to go to reach our goal of about 80% of anticipated production hedged at around $80. Floyd C. Wilson - Chairman & Chief Executive Officer: That's for 2016, Ron. Mark J. Mize - Chief Financial Officer, Treasurer & Executive VP: Right. Floyd C. Wilson - Chairman & Chief Executive Officer: Keep in mind, it's not a – it takes two hands to clap, right. So it's not just the hedging. It's contango now, which is usually the signal you should be hedging, and costs have come screaming down. So it's a different scenario than it was before. So we have a group led by Mark and some others here that are constantly viewing almost minute-by-minute what's going on in the hedge markets. And we intend to continue to be very active in that. Ronald E. Mills - Johnson Rice & Co. LLC: All right. And then lastly, just on the production profile, Mark, for the year, or maybe Floyd, you plan on – is it expected to be pretty linear in terms of pace of completions through the year? Or is it going to be more concentrated in a particular period? Floyd C. Wilson - Chairman & Chief Executive Officer: Like much of the industry, we are working with service providers to get costs in appropriate level. And sometimes, regrettably, that requires waiting. So it's not exactly linear. We're pulling the trigger. Charles's group is pulling the trigger on frac jobs on a very specific basis based on how fair we think that the pricing is, given where we are in this cycle. So we clearly postponed some fracs and we cut rig count down. So I think you're going to see that we're going to try to manage that frac schedule so as to keep things sort of flattish for the year, while overall year-over-year we're going to be up, we think. But it's just – it's not perfect. You're doing pad drilling up in North Dakota and it's not like you can just give somebody one well because you need to frac all the wells that you've drilled on the pad at once. Down at El Halcón it's a little different. We're drilling single well pads for a few remaining lease capture items that we have on our tickets. So we intend to keep it a little flattish, but it's probably going to be a little lumpy just because we have to wait for our partners in the service industry to give us a hand here. Ronald E. Mills - Johnson Rice & Co. LLC: Great. Thank you.

Our next question comes from the line of Michael Rowe from Tudor, Pickering, Holt & Company. Your line is open. Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc.: Hi. Good morning. Floyd C. Wilson - Chairman & Chief Executive Officer: (19:18) Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc.: Wondering if you can maybe speak a little bit to where your corporate PDP decline rate is today? And given the reduced activity levels in 2015, how that could change as you enter into 2016? Floyd C. Wilson - Chairman & Chief Executive Officer: In a general sense – I don't have the exact numbers in front of me – the corporate decline rate when you're drilling more shale wells, more horizontal wells is higher. So it's going to be around 30% to 35%. When you're drilling fewer wells, the decline rate is lower. It's going to be closer to 25%. That's about where we're today. This can change. It all has to do about scheduling. So if you wanted to try to do to model this, if say we're going to grow 5% or 10% this year, we'll have to overcome a 25% decline as well. Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. That's helpful. And I guess you have quite a large acreage position at El Halcón. Given your size and current level of drilling activity, you're seeing some service cost reductions so far, but it's still awaiting to get full development, certainly bring those down more. So I'm just kind of wondering – and I know you don't have liquidity issues now, but have you considered partnering with (20:35) operators to try to fast track process to get the full development and bring down that cost structure further? Floyd C. Wilson - Chairman & Chief Executive Officer: Michael, at our company everything's on the table all the time. Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc.: Fair enough. Thank you.

Our next question comes from the line of James Spicer of Wells Fargo. Your line is open.

Yeah. Hi, good morning everybody. I've got a couple of quick questions on the balance sheet, probably for Mark. First of all, can you talk a little bit about how you view the appropriate level of leverage and/or absolute debt in the price environment that could be lower for an extended period of time? And as a follow-up to that, you mentioned that you're looking at some possible ways of strengthening the balance sheet. I'm wondering if you could elaborate on that a little bit? Mark J. Mize - Chief Financial Officer, Treasurer & Executive VP: Yeah. As we've indicated leverage is higher than we want it to be, of course. And it's something that we're focused on and there are some thoughts here in the company that we've been working on, on ways to bring that down. Obviously, we can't get into specifics on what may or may not happen in the future, but we're obviously very focused on it. And that's also reflected in what we've done with our 2015 capital spend to try to stay as close to within cash flow as possible so that that number doesn't continue to creep up too much on us. Floyd C. Wilson - Chairman & Chief Executive Officer: So look, appropriate level of leverage would be at least a third less than we have, but we don't have that right now. So we've backed off the spend. We've done a lot of hedging. We've made other reductions around the company so that we can get through this, and we will. Of course, it'd be lovely to have less leverage than we have right now. If you'd of called me a year ago and said that we're going to have this oil price, we would have less leverage than we have right now. But you didn't call me.

Okay. So it sounds like there's nothing that you can provide at this point in terms of additional detail on specifics about what you are looking at? Floyd C. Wilson - Chairman & Chief Executive Officer: No, not at this time, no. Thanks, though.

Okay. And the just one more question on the borrowing base redetermination. I thought that was great news that that was reaffirmed. Can you just clarify that you're in the clear now for the next six months as far as the borrowing base redetermination goes? And maybe a little bit about what drove the banks to ultimately reaffirm you guys at the current level? Floyd C. Wilson - Chairman & Chief Executive Officer: Look, Michael, that's sort of a Mark question. But let me just say, we have a long history with all of our banks. We have a long history of strong production reserve growth, which we delivered last year as well. And this weighs heavily into their thoughts. Our big hedge book also is a big factor for this because they're driven by their own price decks. So Mark got 100% of the banks in, and we're good until the next time of redetermination. And we'll see what goes on then, but I'd point out that we have a very strong hedge book at that moment too in the fall for this year and for 2016. So it's a combination of experience the banks have with us and Mark's foresight in making sure that we hedge.

All right. Thanks a lot, guys.

Our next question comes from the line of Chad Mabry of MLV & Company. Your line is open. Chad L. Mabry - MLV & Co. LLC: A question on reserves. Obviously, a strong reserve report that you put out last week. I was hoping to get a little color on your inventory up in the Bakken. Just curious how much Netherland, Sewell gave you credit for on the 660-foot downspacing? Any color you could give on the locations out there? Floyd C. Wilson - Chairman & Chief Executive Officer: Yeah. Obviously, the location count goes up and down with oil prices, and we have this five-year limitation within our estimates of those kinds of things. The great news – the sidelines or the bad news of low oil prices is that we're below rig count. We're barely touching our inventory of locations. The location spacing – and Charles is sitting here, I wanted to add, if I blow this question. But it's very dependent on where you are in the field. And we feel it's very dependent if you're drilling Three Forks wells, top bench Three Forks wells right underneath your Middle Bakken wells. So it's not just a question of, well, it's 660-foot or 800-foot or 1,000-foot. It's different across the field. And it's a highly technical discussion that leads us to draw our conclusions. There's clearly lots of the field that's good for 660-foot. And there's some of the field where the Three Forks is quite good, that you might not want to quite drill it that much or you might drill more Three Forks than you would and less Middle Bakken. So we don't really publish that inventory number. It's in the hundreds and hundreds and hundreds of wells. Charles, what else would you say? Charles E. Cusack - Chief Operating Officer & Executive Vice President: Yeah. Only general comment I'd say on that is NSA did not give us credit for as tight as we're actually drilling right now. And we are drilling everything on 660s-foot or 880s-foot, kind of depending on the existing wells that are in that unit already. But we have 20 operated DSUs, all in Fort Berthold that are already, what we call, downspacing tests. And they're not tests anymore because that's just – that's the norm these days. It's not just us. It's all the other operators in the basin as well. Chad L. Mabry - MLV & Co. LLC: That's very helpful. That's all I had. Thank you.

Our next question comes from the line of Gary Stromberg of Barclays. Your line is open.

Hi. Good morning. Just a follow-up, Mark, on the borrowing base question, when will the next borrowing base redetermination be? And do you have any expectations on where that could wind up? Mark J. Mize - Chief Financial Officer, Treasurer & Executive VP: Yeah, Gary, the next redetermination will be in the fall. We typically do that kind of in the October, maybe into early November timeframe. Where it's going to go clearly will be dependent of what commodity prices do. But again, with the hedges that we have in place, we'll have some protection there. And we're also going have the impact of drilling between now and then that will, of course, be beneficial to the redetermination.

And what... Floyd C. Wilson - Chairman & Chief Executive Officer: With our hedge book, I'd be surprised if it changes. But I could be wrong.

Okay. And do you know what price deck the banks use for the $1.05 billion borrowing base? Floyd C. Wilson - Chairman & Chief Executive Officer: It's varied. Mark J. Mize - Chief Financial Officer, Treasurer & Executive VP: Every bank, as you would expect, is a little different. The JPMorgan deck, I believe, starts in the – it was in the high $40s, and I think worked up to a long-term price in the $70 to $75, somewhere in that ballpark.

Okay. And then, Mark, on the budget $350 million to $400 million (29:07) doesn't include capitalized costs, how we should think about capitalized costs this year? Mark J. Mize - Chief Financial Officer, Treasurer & Executive VP: I believe probably up $150 million to $200 million.

Okay. That's all I had. Thank you.

Our next question comes from the line of Jason Gilbert of Goldman Sachs. Your line is open. Jason A. Gilbert - Goldman Sachs & Co.: Hey. Good morning, guys. Thanks for taking my questions. I guess sort of a production guidance question. I think you said the backlog on wells uncompleted right now was at 26 maybe. I was wondering where do you see that at year-end 2015? Where do you see the exit rate 2015 production versus where we were at year-end 2014? Floyd C. Wilson - Chairman & Chief Executive Officer: This current level has been driven by postponing frac jobs. Last year, at the end of 2013, we had 20 or 25 wells that were waiting on completion that were driven by a higher rig count. By the end of this year, assuming costs come to line, we would guess this inventory would be a bit smaller, but we'll still have an inventory by the end of the year. It's just timing and, particularly up in Fort Berthold, doing three and four and five fracs at a time on pads. It's inevitable we'll have some. It's not a matter of us not going to frac the wells. We're just trying to get the cost in sync with what the real-time oil prices are unhedged and that's coming into line. So we're about to release some new frac work, and we're bidding everything several times because it's changing for the service providers, too. So the inventory will be up and down a little bit during the year, but I'd say it'd be down by the end of the year a bit. We'll still have 10 or 20 wells by the end of this year though, 10 or 15 wells. We don't really project that right now. Jason A. Gilbert - Goldman Sachs & Co.: Okay. And also you mentioned the Fort Berthold wells were generally outperforming the type curve. Any thoughts on (30:23) type curve? Floyd C. Wilson - Chairman & Chief Executive Officer: Was that about changing the type curve, was it? Jason A. Gilbert - Goldman Sachs & Co.: Yeah. Floyd C. Wilson - Chairman & Chief Executive Officer: No, the data is out there. You can make a type curve that's a lot higher. We're doing a lot of million barrel wells, million-and-a-quarter barrel wells. No, I don't think so. Just accept that there's a lot of daylight there, and we'll come out with something sometime, but it just doesn't seem important right now. Jason A. Gilbert - Goldman Sachs & Co.: Okay. And then last one, if I might, what are your plans for the Utica (31:01)? Floyd C. Wilson - Chairman & Chief Executive Officer: What's the Utica? Jason A. Gilbert - Goldman Sachs & Co.: Yeah. Floyd C. Wilson - Chairman & Chief Executive Officer: Oh, the Utica. We have no plans this year for the Utica, the Northern Utica nor the TMS. We have some good land there. There's lots of gas up in the Utica and there's lots of oil in the TMS, but the prices and our concentration and our better targets that we have at El Halcón and North Dakota just demand that we don't do anything with those at this time. Jason A. Gilbert - Goldman Sachs & Co.: And I mean, will much of the inventory expire up there if you don't do drilling in the TMS or Utica? Floyd C. Wilson - Chairman & Chief Executive Officer: Hardly any. We have a pretty rigorous process, and we've winnowed that acreage down that we've kept on our books is valid acreage. So no, it wouldn't have hardly any expirations up there. Jason A. Gilbert - Goldman Sachs & Co.: Great. That's super helpful. Thank you.

Our next question comes from the line of Jason Wangler of Wunderlich Securities. Your line is open.

Good morning. Just at El Halcón, you talked about obviously just drilling the one well. And where are we in the lease capture side of this business? And is it next year when we're going to start looking at pads? And just kind of the cadence of that? Floyd C. Wilson - Chairman & Chief Executive Officer: Charles, can answer that. Charles E. Cusack - Chief Operating Officer & Executive Vice President: Yeah, that's our current plan right now. And like Floyd mentioned earlier, it's over a million dollars, $1.25 million less cost once you go in development mode. So that gives an extra 10% to 15% rate of return on top of that. Floyd C. Wilson - Chairman & Chief Executive Officer: We're probably around 75% or plus or minus of the lease capture. Some of the leases we don't care about because they're small chunks within units that we control. And it's just like the frac jobs. If you're going to re-lease something, you have to wait for the lease prices to get in sync with oil prices. And so you don't rush around to do anything. We'll hold all of the acreage that we really care about with our drilling program this year and the first part of the next. And we'll be into pad drilling sometime next year, towards the end of the year.

That's helpful. Thank you.

And we have no further questions in the queue. I would like to turn the call back to Mr. Floyd Wilson for closing remarks. Floyd C. Wilson - Chairman & Chief Executive Officer: Well, there are no remarks. Thanks for dialing in. And if you think of something we didn't answer, just give us a call. Thanks, operator.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the call. You may now disconnect. Everyone, have a wonderful day.