Greetings. And welcome to the Ring Energy First Quarter 2016 Financial and Operating Results Conference Call. At this time all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions]. As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Mr. Tim Rochford, Chairman of the Board of Directors for Ring Energy. Thank you. You may begin.

Thank you, Mellissa, and welcome all listeners to our first quarter financial and operations conference call for Ring Energy, Inc. Again, my name is Tim Rochford, Chairman of the Board. Joining me on the call of course is our CEO, Kelly Hoffman; our President, David Fowler; our CFO, Randy Broaddrick; and Executive VP in charge of all operations, Danny Wilson. So, today, we're going to cover the financial and operations for the first quarter ended 31 or March 31, 2016. We will review our results and provide some insight as to the current progress as we go into the second quarter of 2016. And then at the conclusion of the first quarter review, we're going to turn it back to the operator and open it up for any calls that you may have. So, with that, I'm going to ask Randy Broaddrick to review the first quarter financials. Randy?

Thank you, Tim. Before we begin, I would like to make reference that any forward-looking statements, which may be made during this call, are within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. For a complete explanation, I would refer you to our release issued Monday, May 9. If you do not have a copy of the release, one will be posted on the company's website at www.ringenergy.com. For the three months ended March 31, 2016, the company had oil and gas revenues of $6.1 million and a net loss of $15.3 million as compared to revenues of $6 million and a net loss of $1 million in the first quarter of 2015. The dramatic change in the loss was driven primarily by $21.4 million pre-tax write-down of our asset based on the ceiling test calculation. This additional write-down was the result of a change in the PV-10 value of our reserves from year-end based solely on commodity prices. If prices remain at these levels, we'll drop further, we could be required to write-down additional amount in the second quarter of 2016, and beyond. Our revenues between the periods were comparable, despite a 67% increase in our sales volume on a per BOE basis. For the three months ended March 31, 2016, our oil price received was $29.20 per barrel, a decrease of 33% from 2015 and our gas price received was $1.97 per MCF, a 17% decrease from the first quarter of 2015. On a per BOE basis, the first quarter 2016 price received was $26.02, a decrease of 40% from the 2015 price. Production cost per BOE for the three months ended March 31, 2016 decreased to $10.64 as compared to $13.30 in 2015. The primary reason behind the decrease…

Thanks, Randy. I think we'll go ahead and start with Kelly, and Kelly if you'd be kind enough to give us a recap on first quarter operations.

Sure. Thanks, Tim. And welcome, everyone to the call today. In the first quarter, we joined or we drilled rather one well and continued to make improvements to our leasehold infrastructures. We also continued to work on both the saltwater disposal systems in the Central Basin Platform, as well as the Delaware Basin Platform. In the first quarter, we sold about 234,168 barrels of oil equivalent and that is a 67% increase over the same period in 2015, and a 10% increase over the fourth quarter of 2015. We averaged 2,573 barrels of oil equivalent per day and we received approximately $26.02 per barrel in the first quarter compared to $43.06 in 2015 and that's a 40% decrease in price. We've finished our horizontal study in the first quarter on the Central Basin Platform, and we made that public. Also subsequent to the end of the first quarter, as you heard our CFO just a moment ago, Randy Broaddrick mentioned we completed a stock offering allowing us to pay down all of the debt and it left us with a surplus of capital, which we will fund our drilling program for 2016. So having said that, I'm going – I don't want to steal any of the thunder that we're going to hear here a moment from Danny Wilson, and again an update from David Fowler. So I'm going to pass it back – I'm just going to introduce David here. David?

Thank you very much, Kelly. I'll give you just kind of a quick overview of our business development areas of interest. We continue to monitor M&A opportunities on The Street with a desire of finding one or maybe two that might meet our buying criteria, but it remains few and far between We do, however, continue to report behind the scene on internally generated acquisition opportunities that really aren't in the public domain at this time. Our primary focus right now is drilling and expanding our current acreage footprint of both the Platform and the Delaware Basin areas through an organic process. This was evidenced by our land department's continued progress towards increasing our net mineral ownership on a Platform in areas where we don't have a 100% lease, as well as pursue new leases in designated areas of interest in both our Permian and core areas. M&A opportunities continue to be brought to us from a whole variety of different sources, but we haven't seen a fit yet, but are definitely on the hunt. So, with that being said, our real emphasis is about increasing or existing footprint in both our Platform area and also the Delaware Basin. And with that, Kelly, I'll turn it back to you.

Sure. I'd like to introduce Danny Wilson at this time and let Danny give you an update on operations.

All right. Thank you, Kelly. As Kelly mentioned, we had a good quarter production-wise and we're continuing that this quarter. We have substantially finished up our capital expenditures that we were going to have to do to begin our drilling program for this year. We are in the process of setting our first of two wells that we're going to drill for this quarter. Should have that one finished up probably by the end of this week, we'll start the other one shortly after that. We should start seeing production from those wells probably in June. And then we'll move forward, as our – for our CapEx release that we gave the other day, we'll have to – we will drill two wells in the third quarter and two wells [indiscernible] wells in the fourth quarter also. We also have plans out in the Delaware Basin to drill one Cherry Canyon well, but we are going to take that well down deep in to do some signs on the Brushy Canyon, which is another area that we like. It looks very perspective for us in the future, possibly next year. We'll be going in and doing some course verifying what we see in the logs to make sure that it looks is good in the course as it does on the logs, if so then it looks very promising for us. As for the study, Kelly mentioned and Tim has mentioned about our horizontal program we've been watching the horizontal play out in the Central Basin Platform developed over the last couple of years as we've been out there drilling our vertical wells. We've been watching several offset operators and kind of keeping an eye on what they were doing. And over the last year and half or so, it…

Thank you, Danny. Tim, let me just pass it back to you for closing remarks.

All right. Very good. Well, good job guys. Thank you Danny. I think it goes without saying, it's about to get very exciting here in the Ring camp. But operator, I know that we have a number of people that are anxious to ask some questions. So, I'm going to turn it back over to you and please open it up for any questions they may have.

Thank you. [Operator Instructions] Our first question comes from the line of Neal Dingmann with SunTrust Robinson Humphrey. Please proceed with your question.

Good morning guys, and great update. Say, Tim for you or the team, I guess Kelly or whoever wants to take it, just as far as cost, when you're looking at now kind of developing that plan for the horizontals, just I know you had in the release. Can you maybe a little bit more, is that still think of the same cost both for the Platform in the Delaware, which you are thinking for initial cost, and any comments if potentially how quickly those could start to decline?

Yeah, and I think -- I think you're right. We are consistent with that, but Danny maybe you could shed a little color on that.

Sure. When we went out and did the program a couple of weeks ago, and talk to all the investment groups. We were thinking that based on the numbers we had at that time, it's horizontal 1.5 mile horizontal in the Central Basin Platform was going to run about 2.4 million. We were going to need an additional, only first three wells of that at an additional 350,000 per well for infrastructure. Since that time, we have set down with the vendors again, in particular Schlumberger is one of the main vendors that we're dealing with as far as the completion goes. We talk to the drilling contractors, and it looks like now we're getting those costs down closer to the $2 million range. On the drill side still going to need to do the infrastructure part of that. But I think we've been able to pare that down that's – I'm guessing that's probably about the number that we're going to go with, Neal, is about $2 million. Now, when we lookout at the Delaware, the numbers are a little bit higher, because the wells are at 6,100 feet versus 5,000 feet, and we have those real costs in currently for 1.5 mile lateral was about $2.5 million, so it's a little bit more expensive. The completions are a little different – a little deeper surface wise, just a few other things that are different between the two areas that – so we're looking at about a $2 million cost for the San Andres horizontal and about a $2.5 million for Brushy Canyon.

Got it. Got it. Great detail, Danny. Thanks. Secondly, just on kind of – it's kind of the typical question I think we've heard on most of these calls as far as the prices. Obviously, a bit of a run up in prices, just how the change in prices, how you all think about the fluidity of your plan both in the Platform – let's just about the horizontal plan I guess, how that would change based on different pricing scenarios?

Well, Neal and that's a good question and it's a question that's often asked. Let's start off by saying, to begin with that we would be excited about initiating this and initiating as we plan to here within just a number of weeks even at a $35 realized price. The rate of return and internal rate of return on that investment on these horizontal wells even down to $30 or high – maybe say low to mid $30s is spectacular. So, you can only appreciate as we see it from a price that this space continues to hopefully trim that way the rest of the – balance of this year. It will just get better for us, but yeah, it's impactive.

Got it. And then just – I don't know if you've mentioned this before, maybe Danny or for any of the guys, just when you start to really digging into that program how should we think about if you go beyond one or two rigs? I'm just not sure none of these a bit shallow or horizontal wells how you think about frac crews needed to keep up with the rigs.

Danny?

You bet. Now, we're looking at one frac crew per rig. So right now, obviously it's not a problem when things picked up. It may take a little while for the vendors to catch up and that's a good point that we'll be looking at in the future as we move forward, but Neal, I think what we will do is we may be looking at locking in longer term contracts for some of these guys. If we look at a program next year where we're looking at 20 wells or 30 wells, I think you'll see us look at some long-term contracts, not only for the service side and the crews, but that'll help us lock in those costs for at least a year, we can do that. We're looking at also – we're looking at buying pipe and stockpiling that while current prices are low and we might stock enough to get us substantially through next year. There's a lot of places we can go to kind of keep these costs under control, at least initially.

And Danny, you don't have any long-term contracts now do you?

No. We don't have any. Right now, we're just doing as I said we're doing the two wells now. I've got a two well contract but – and we're going to do a three well contract on the horizontal wells, but last year – typically what we've done are 10-well packages and that's worked out well for us. Those processes go one way or the other, especially if they go upside down and start going down. We don't have a long-term commitment. And the drilling contractor seem to be happy with about a 10 well package.

Got it and lastly, just – if one of you all can just comment I know for Randy or who just on the differentials potentially today and kind of what you're expecting both in the Platform in Del?

Yeah. Danny, can you give some light on that?

I can. Neil, typically right now we're running about a 10% differential. So, if we're looking at $40, it's running about $4, so – and that's both areas. So, that's kind of the numbers we've been building our economics around now.

Very good. Thank you all.

Thanks, Neil.

Thank you. Our next question comes from the line of Jeff Grampp with Northland Capital Markets. Pleased proceed with your question.

Good morning, guys. I'm wondering on the horizontal front, you know kind of maybe minimum EUR expectations that you guys are thinking you need on the horizontals to have a value add relative to the vertical program, and I know expectations are obviously to do much better and create a step change on the F&D cost, but maybe just trying to get a sense for what a baseline level will be to improve kind of your base vertical program?

Yeah. Well, that's a great question, and you know a part of our study revealed a much lower number that we're using. Danny once again, I'm going to turn to you. The threshold number that we looked at was, and I don't want to guess wrong, but I believe it was 44 on a...

That's right. When we started out – if we look at all of the wells in the year, this is good, bad and some of these are really not good, but – and I think that's mostly due to completion techniques and some of the wells they – they picked four spots to drill, some of them drilled the wrong direction; east-west versus north-south. But when we looked at that overall package on a worst case scenario we're looking at about a 44 BOE per foot recovery net. And we actually use the 30 – the 16 wells that were in our initial area, right around that, those are the numbers we ran on and those are running about 55 net BOE per foot. And then as we look into the wells immediately offsetting us on the parallel which we're drilling literally two locations away from one of their best wells, their recoveries are in the – about 81 BOE per foot, but when we ran our economics, we used 55. The numbers are still good even at 44.

Perfect, that's real helpful. And then, just kind of thinking about, I know we're obviously a long way from 2017, but just kind of wondering how you guys are thinking about development and integrating horizontals. I mean let's say hypothetically if a – for $50, north of $50 for oil and pilot programs working out. I mean, can you give us kind of a high level sense, what kind of CapEx program or maybe how do you guys split between the bread and butter vertical versus this higher impact horizontal program?

Well Jeff, that's a – that's also a good question and we openly talked about this as part of the road show and that information has been posted on our website for those – some of those that have already seen that, but we're happy to review that. Probably in the neighborhood, as Danny mentioned a moment ago, we're thinking that with a reasonable deck somewhere in the neighborhood where we're at now, certainly if it's firm receiving and going to be better, but probably a minimum of 20 to 30 horizontal wells on the Platform next year. You're probably looking at an overall CapEx budget somewhere between $65 million and $75 million that would also accompany activity on the Delaware side. Now in the same breath, as you mentioned, if we get a little bit more robust price in the commodity space, you could see that moving upwards. So it is a bit of a moving target, but we're feeling pretty comfortable that if we're in the space we're at now or a little bit better and based on the results we're anticipating that next year is going to probably see at least 20 plus on the Platform.

Great. Thanks for that. And then if I sneak one more in. Can you give us a sense maybe for what kind of current net production is or how productions been trending relative to your first quarter number?

Yeah. Sure. You bet. Danny, Kelly, you guys can address that?

Yeah. I would say, right now we're trending in either roughly flat and maybe down just a hair but I don't see that's going to be a long-term issue. We only drilled one well last quarter which is – it takes us about two to hold flat, so we may see a little bit this quarter, but I think we'll see a good recovery in the third quarter and then in the fourth quarter we'll see the horizontal wells kick in. So I say again for this quarter, flat to maybe just a few percentage points.

And Jeff in all fairness the two wells that we're going to – that we're drilling on the Platform, and even though they're going to probably begin production as we wrap up the quarter, they may not contribute a whole lot, so we'll just have to wait and see.

Perfect. Great. Thanks.

No when you probably said [indiscernible]…

Yeah.

Yeah.

Yeah.

Absolutely. Understood. Appreciate the details, guys.

Thank you.

Thank you. Our next question comes from the line of Richard Tullis with Capital One Securities. Please proceed with your question.

Hi. Thanks. Good morning, everyone. Congratulations on a nice quarter, Tim. Couple of my questions already been asked, but what's the expected oil component in that 500 plus 1,000 barrel EUR for the Central Basin Platform, Kelly?

It's – I think that we're looking at about – it's in the high 80s, roughly in the low 90s.

Okay. Okay. So, it's going to be in the low 90s, if you heard that....

Probably about 92% to 94% of oil was what we're looking at on those.

Okay.

It's in line with our vertical wells.

Okay. And along those same lines what's the expected working interest in those first three wells?

On the first three horizontal wells?

Yes, sir.

Yeah. 100% working interest was at 99.5%, what is that Danny?

We'll be and we'll probably be on average in the low 90s.

Okay. Okay. And then just lastly you had a real nice reduction in LOE per barrel in the first quarter, what should we expect on a go-forward basis kind of range on a barrel basis, you would be looking at.

I think something in the $12 range is probably more realistic to expect going forward.

Okay.

Yeah. And Danny, I think just to underline that is that maybe you can speak to address this, but Richard we spend an awful lot of money infrastructure wise over the last number of months particularly -- probably the last six months, seven months, and those results are starting now to be revealed. So that's one of the things that is contributed to that. But, Danny, you may have a thought on that.

No that you're exactly right, Tim. When we took over those properties middle of last year, there was a substantial amount of work that we had to do both on the wells themselves to optimize them. But on the surface, there was a lot of things that had to be done and [indiscernible] run down just we had a lot of things to take care. We get that in the fourth quarter of last year and then finish that probably about mid-February this year with our big cost and then once we got that in line, is really just maintenance now, and I think those are what you're seeing those it's that $11, $12 range, it's kind of a maintenance level for us.

Okay. And just lastly, it sounds like the infrastructure requirements beyond what you would need to do for new wells is going to be reduced say for the second half of this year and going into 2017. Is that a fair statement?

It is.

Yes.

Yes, it is on the – on the bulk of the wells that we have now, we did have some infrastructure we're going to do. We have excess capacity for in the Central Basin Platform. We have permitted capacity there on our disposal system, we're about 50,000 barrels a day. And we're only using 10,000 barrels of that right now. And so, what you're seeing when we tie those we're going to have to do some work on these first three wells. What that is, as we're going to have to laid 2 miles to 3 miles of high capacity waterline to get into our system back. The system is ready and the wells are closed by. We again have to do that. Obviously we've got to build out some electrical grid and then we've got to do some paint battery work, but that's really the bulk of our CapEx for equipment and infrastructure this year.

Okay. And then over on the Delaware side, I know you referenced about $2.5 million well cost for 1.5 mile lateral. What would be the expected infrastructure cost associated with that, say on a well basis?

Actually, we're in – actually in a better spot, because those would be in-filled wells or actually be drilled within our existing footprint, so I would expect our cost to be somewhat lower probably in the 200 range, maybe 150, or substantially less.

Okay. That's all from me. Thanks very much.

Thanks, Richard.

Thank you. Our next question comes from the line of Mike Kelly with Seaport Global. Please proceed with your question.

Hey guys, good morning.

Good morning.

I have – I'm curious if the opportunity set on the M&A side has increased post the equity raise have been really just going public with the plants to go horizontal here basically. Has the phone been ringing here with maybe some interesting opportunities that you weren't seeing before? Thanks.

Good question. David, can you address that?

I'd be glad to. We've seen some opportunities that have come to us, Mike, that are further north on us, not anything that's much around us. I will say though that to go along with your question, yes the telephone is ringing more, we're seeing more opportunities. It's – there was a some horizontal activity in the Yoakum County, there was a property that was marketed by a company that actually drilled it called Manzano and that created a lot of activity in Yoakum County leasing activity. So, we know that there is – seen – we've seen an increased amount to our north, but where we are, so far we are in a pretty good shape, and that's what's opened up some doors for us to head Tony and Hughes team in our land department had some success in picking up some additional acreage.

Great. And I was going to ask you just on, if you are seeing additional horizontal permitting activity in the St. Andrews or anywhere around where you guys really going to be the leader on this front in the near term?

I'd say right now, it looks like, right in our particular area, we are really the only one. Our neighbor that has drilled the wells that have kind of proved up. Our acreage has got one or two wells drilled by the end of the year. But in our immediate area, I don't see anybody else whose permitting right now.

Got it. You mentioned the organic lease numbers big focus for you. How should we think about, what you consider to access there, how aggressive do you want to get on building that acreage position there, and then if you could give us any sense on ranges of what you paid or where you would like to keep that acreage cost to, that will be helpful please? Thanks.

Yeah, Kelly?

Sure. Yeah, hey Mike. When we look across the area, obviously we are staying in close proximity to a signature that we feel like, we develop that, that's helped develop around is with the outside operators. So, that we can sort of head down the same path and the same type of thinking that, he's got us to where we are so far. We are seeing cost in this area, as David mentioned, as you go far north, I mean you're getting into some cost that are probably in the $2,000, $3,000 per acreage range, and a lot of discussions higher than that, but deals not been made. But it's touring around with those ceilings in the far northern from us in and around the area that we're concentrating on, I mean we've been fortunate enough to take down some acreage as high and as low as $400 an acre. I'll just be frank, we look at $500, $800, $1,000 an acre just depending on exactly where it is, and what's the relationship to where we feel like the best place to drill these horizontal wells are and in even bolt-on verticals that we think match our criteria.

Okay. Great color. And just from a logistic standpoint here, you guys are working on the permits now. It sounds like put the rigs up end of July, do you drill these things back-to-back or when do you expect to have these wells, what's kind of the progression of between well one to three, when do you drill and when they come online? Thanks.

Right. Hey Mike, the – we're looking at a – from spud to completion data of about 45 days, and we are going to drilling back-to-back, and we anticipate it's going be 10 days per well to drill, so we're looking at three wells running over 30 days, and then as each one finishes up we're looking at about 35 days after that they have it on completion.

Okay. Perfect.

So Mike if you kind of maybe look it at this way, we're drilling those three wells back-to-back in terms of as they layer on in production, first coming on let's say mid-September, second 1st of October, last or third well mid-October.

Great. Very helpful. Thanks a lot guys. Best of luck.

You bet, Mike.

Thank you. Our next question comes from the line of John White with ROTH Capital Partners. Please proceed with your question.

Thanks for letting me on, and this is all, very positives in the excitements coming through in your tone of voice, so congratulations. On the horizontals, you mentioned 90% working interest, can you give us what you think your average net revenue interest would be?

Yeah. We're looking at 75% net on those so if we're looking at 90%, it'd just be reduced by whatever 75% is.

Right. And on your verticals, your 100% working interest.

On most of them. We do have some that vary, but for the most part of our verticals are 100% here.

Okay. And again to the horizontals, in terms of IPs, what kind of IPs are you seeing from offset operators like using the results that you've put in to your – the type curve that you've developed?

Yeah. Our IP rates that we're expecting on these 1.5 miles were looking at about a 560 barrels per day gross to start with. And that's actually when we look at our neighbors to the East -- excuse me to the West that are just right next to those, one of those came in at about 900 barrels a day, another one came in at about 600 barrels a day, 700 barrels a day. So we're actually being pretty conservative on our case, so we're using 560 barrels per day.

Sounds great. One last one for Mr. Fowler, you talked about you have a – you looked at a lot of deals haven't really found one to pursue. You said, you used the work, you couldn't find one that's a fit. Is it fit, and is it also you're just seeing a lot of low quality deals that people are trying to cash out?

John, a lot of low quality deals. I don't think there is probably anything that hit the Permian for sale that we don't see. A lot of times we see it even before it hits the street officially. We've got a criteria that we're looking forward much like what we did last year when we purchased the asset from Finley in the Delaware. That could have been a better fit for us. It was almost – at that time I think there is only one well that needed to be drilled to making a 100% held by production, and that's been done, and of course it came with a good amount of production based on a per well basis and had plenty of running room, low-hanging fruit, I mean it was a perfect type acquisition. So, it's not that everyone has to look just like that, but we're looking for opportunities that make sense like what we've done in the past. So, we've made – our criteria maybe a little higher but at the same time we're wanting to make sure that we bring an acquisition on that it's accretive, there is no question about it. It translates well, it's something that's easy in our area that makes sense, that's easy to access. So, yes, our – so far what we've seen just really has been substandard and we pass in all alone.

Yeah. Well, there is..

Yeah. I'll say this so, John. I anticipate that the quality of assets are probably going to start getting better.

That's helpful. Well, since the crash started you guys have been very patient, very deliberate and it looks like it's all coming together for you. So, congrats again. Thank you.

Thank you, John.

Thanks, John.

Thank you. Our next question comes from the line of Sam Burwell with Canaccord Genuity. Please proceed with your question.

Thanks guys. I was wondering what type of spacing assumptions in terms of wells per section went into that 137 potential horizontal locations?

Yeah. Good question.

Yeah. We're looking at six wells per section on that.

Okay. That make sense. And then digging a little bit deeper into the assumptions especially on the $2 million per well, I mean very aggressive in terms of costs. Could you give anything away in terms of the completions, I mean you guys are going to have to put these on pump early on, given that's a shallow formation, any other color you can add as far as the completion technique you guys plan to use?

Well, we are going to use the – I'm not going to go into a lot of detail just because obviously, we want to maintain our advantage out there, but we are – we're looking at it probably the biggest difference being the number of stages that we're running. But other than that, we're – well, these things will flow for probably anywhere from one week to four weeks after completion. And then, we'll probably put them on a set pump after that for – until their rate pump down put on the rod pump.

Okay. That make sense. And then just lastly a higher level one. You mentioned a pretty solid acceleration in terms of horizontal program in 2017, assuming that we have a strip looking pretty much like we see today. Is there any level at which you guys plan to accelerate the vertical program or is that clearly take a backseat now that horizontals are in the fold?

Yeah. As you know Sam, there isn't any question that we're -- the mindset right now is the biggest bank for the dollar. And so, as we wrap up this year and get into next year, although we're going to be doing some – we're going to have some vertical activity for the most part, it's going to be horizontal.

All right. Good stuff. Thanks, gents.

Thank you, Sam.

Thank you. [Operator Instructions] Our next question comes from the line of Mike Breard with Hodges Capital Management. Please proceed with your question.

Okay. Assuming these horizontal wells come on September and October, as expected or even a little better than expected and the oil price is $50. Would you start drilling wells in October and November or would you wait for next year 2017?

Mike, I think that would still – we'd still probably see an early 2017 before we'd kick off.

Okay. Thanks.

Mr. Rochford, there are no further questions at this time. I'd like to turn the floor back to you for any final remarks.

Okay. Well thank you, operator. Well, as everybody can sense, there is a lot of excitement going around the Ring camp, and we're anxious too, we're anxious to get started. I'd just leave you with that. And lastly, I think that here we are sitting in that seat somebody mentioned earlier that we've been patient. We have been very patient, we've been diligent. I think we've pulled off some great moves this last quarter, and as we started the second quarter particularly with the follow-up as it relates to our equity, sitting here with zero debt, surplus capital and a great new program to kick off. So we're excited. We thank you for your support and as always our doors are open, so if you have follow-up questions, feel free to reach out to us. Everybody have a great day. Thank you.

Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.