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Good morning, and welcome to Earthstone Energy's Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded.
Joining us today from Earthstone are Robert Anderson, President; Mark Lumpkin, Executive Vice President and Chief Financial Officer; Tony Oviedo, Chief Accounting Officer; and Scott Thelander, Director of Finance. Mr. Thelander, you may begin.
Thank you, and welcome to our conference call. Before we get started, I would like to point out that today's call will contain forward-looking statements within the meaning of Section 27A of the Securities and Exchange Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Although management believes these statements are based on reasonable expectations, they can give no assurance that they will prove to be correct. The statements are subject to certain risks, uncertainties and assumptions as described in the earnings announcement we released yesterday and in the company's quarterly report on Form 10-Q for the first quarter of 2018 and Annual Report on Form 10-K for 2017. These documents can be found in the Investors section of our website, www.earthstoneenergy.com. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may vary materially.
This conference call also includes references to certain non-GAAP financial measures. Reconciliations of these non-GAAP financial measures to the most directly comparable measure under GAAP are contained in our earnings announcement released yesterday. Also as a reminder, information recorded on this call speaks only as of today, May 4, 2018. Thus, any time sensitive information may no longer be accurate at the time of a replay. A replay of today's call will be available via webcast by going to the Investors section of Earthstone's website and also by telephone replay. You can find information about how to access those in our earnings announcement released yesterday.
The content of today's call will begin with remarks from Robert regarding our activities and how we are positioned for profitable growth, followed by remarks from Mark regarding financial measures and performance and concluding with remarks from Robert regarding our operations.
I'll now turn the call over to Robert.
Thanks, Scott. Good morning, all, and thank you for joining us on this call. I'm pleased to say that we had a very solid first quarter with results that clearly demonstrate the excellent progress we were making at growing our company.
Our sales volumes grew 104% compared to the first quarter of last year and 7% compared to the fourth quarter, which included over 900 barrels of oil equivalent per day or BOE per day associated with properties we sold in December. If adjusted for our divestitures during the 2017 fourth quarter, then our first quarter sales volume were up actually 16%. Our production is in line with our expectations, and we expect to build on that over the course of the year as we continue to drill and complete wells largely in the Midland Basin. But as we said on our call last quarter, our production guidance is back end weighted as we line out our frac activities for the year.
Importantly, we are driving our production growth to a profitable bottom line. Our net income for the first quarter was $12.2 million, generating adjusted EBITDAX of $25.3 million, which is a 312% increase over the first quarter of 2017. We continue to improve per-unit metrics, including LOE and G&A per BOE on both a quarter-over-quarter basis and compared to full year 2017. And we haven't sacrificed our quality balance sheet, operating efficiency or cost management to achieve our growth.
We are pleased with the quality of our asset positions in the two top basins located in Texas. While we work toward finding another transformative acquisition in West Texas, our primary focus will continue to be on the Midland Basin and on expanding our footprint through acquisitions and trades as well as continually improving our operating results.
We see plenty of opportunity ahead to further optimize drilling and completion activities, better delineate the stack formations and to expand our drilling inventory by adding acreage and economic benches. The majority of our Eagle Ford acreage is held by production and more fully delineated, so it will receive less emphasis as we continue our focus on developing our Midland Basin assets. We believe we have the right assets, good cash flow, a strong balance sheet and a company with exciting growth opportunities to continue to successfully build shareholder value.
I'll now turn the call over to Mark to provide a brief summary of our financial results for the first quarter.
Thank you, Robert. Before I address the financial results, I'm going to go a little bit off script and wanted to publicly congratulate Robert on his recent promotion to President, and those of you who followed Earthstone and private companies for that matter know his critical role in our success and this promotion is reflective of both his contributions to our success up to this point and also his leadership role in taking us where we're headed into the future.
So from a financial perspective, our first quarter results came in pretty much as expected and we remain on track with our objectives. Our sales volumes in the first quarter more than doubled from a year ago. We averaged 9,664 BOE per day in the first quarter, of which 63% was crude oil, 17% NGLs and the balance natural gas. Again, as I mentioned, this represents a 104% increase over the first quarter of 2017 and a 7% increase from the fourth quarter of '17 on an absolute basis or 16% increase from the fourth quarter when adjusting for the divested assets.
The key driver of the significant increase in our year-over-year production over the past three quarters has been the incremental sales volumes from the operated Midland Basin acquisition that we closed last May and the additional wells we brought online in the Midland Basin since closing the acquisition. Approximately 80% of our company-wide production in the first quarter was attributable to Midland Basin with the Eagle Ford comprising the remaining 20%.
From a financial perspective, we reported total net income of approximately $12.2 million or $0.19 per share in the first quarter of 2018. This compares to total net income of $0.7 million or $0.03 per share in the first quarter of 2017 and $5.5 million or $0.09 per share in the fourth quarter of 2017. Adjusted EBITDAX grew to $25.3 million in the first quarter, which represented a 14% increase over the fourth quarter and a threefold increase of 312% from the first quarter of 2017.
Our top line revenue growth was driven by higher production volumes and -- was a key driver and higher adjusted EBITDAX. As I think you guys know, GAAP requires us to disclose the amount of net income associated with the controlling interest, which essentially reflects our Class A shares. Accordingly, from a GAAP perspective, we reported net income attributable to Earthstone Energy, Inc. of approximately $5.3 million, which is also $0.19 per share in the first quarter of 2018. That compares to net income of $0.7 million or $0.03 per share in the first quarter of 2017 and $2.3 million or $0.09 per share in the 2017 fourth quarter. You can also refer to yesterday's earnings release and 10-Q as well as our 2017 10-K for further information.
We're proud of the results of our continued focus on streamlining and optimizing our cost structure and we'll maintain this focus as we grow. In the first quarter, LOE per BOE was $5.35, which was 22% lower than full year 2017 and 47% lower than the prior year period. We're achieving these lower operating costs through efficiencies in the Midland Basin and also through the divestiture of higher-cost assets in the second half of 2017. We expect continued improvement in LOE per BOE as we step up our production in the Midland Basin.
Now within respect to balance sheet and liquidity, we continue to have a conservative capital structure with low leverage. At the end of the first quarter, we had $30 million outstanding under our reserve base borrowing facility and a cash balance of $11 million for net debt at quarter end of $19 million. The borrowing base on our reserve base borrowing facility is currently $185 million and will be re-determined by our bank group shortly. Based on the current borrowing base on our net debt, liquidity at quarter end was $166 million.
From my CapEx standpoint, capital expenditures for the first quarter were approximately $22 million. We anticipate higher levels of CapEx in the second quarter as we initiated another completion program in the Midland Basin during the first half of April and deploy the rig in the Eagle Ford drilling program there.
With that, I'll turn it back over to Robert.
All right. Thanks, Mark. I appreciate the kind words from you, and also to arrest any fears out there, Frank isn't going anywhere. He just couldn't be here today because of a prior obligation.
So with that, talking about operations a little bit. Our sequential increase in production was primarily due to the 5-well completion program in the Midland Basin that we started back in December and extended into the very early parts of January as we discussed last time on our call. We continue to be pleased with the initial performance of our wells in the Midland Basin, which continue to meet or exceed our type curves.
We have a 1-rig operated program underway in the Midland Basin, and thus far this year, we finished drilling two wells over year-end and have spud additional five wells. We also started our Midland Basin completion program, as Mark mentioned, in April, and this consists of eight wells. This buildup of inventory of drilled but uncompleted wells positions us to complete these wells efficiently and effectively by having our vendor team in place and executing on a multi-well completion program versus trying to complete one or two wells at a time at the end of drilling each pad where we may have a hard time contracting the required services.
Having a number of wells to complete at one time is beneficial for both us and the service providers as it provides the consistency with our operating team that is necessary to make these efficiency gains. We expect to complete these eight wells during the second quarter with the first set of two wells already being fracked and preparing for drill-out now with the expectation that they'll start flowing back in the next couple of weeks. Including in this batch of completions will be our first operated Wolfcamp C well. So perhaps by the next quarter's call, we'll have some results to talk about here.
With an average 79% working interest across these eight wells, this batch of completions should drive a substantial increase in production in the second half of the year. From a service availability standpoint, we continue, because of this method of completing wells in large batches, to procure the quality services in the Midland Basin. As an example, our current completions are being performed by the same frac company that provided services for us in August of 2017 and December of 2017.
Our plan remains to bring online 22 gross and 19.6 net operated Midland Basin wells during 2018 with our primary focus on the Wolfcamp A and B formations. With completions of these eight wells underway as well as the two wells brought online in January, we are off to a good start in achieving this plan. As we continue to firm up our development plans, we are working to be in a position to add a second drilling rig in the second half of the year.
Turning to the Eagle Ford; we completed the remaining six wells of our 11-well completion program in southern Gonzales County during the first quarter of 2018. As you might recall, five wells had been completed prior to year-end '17. These six new wells are in our Crosby Unit where we have a 25% working interest and operations and they came online in January. In late March, we started a 5-well program on our Sayer pad, also in southern Gonzales County in the Eagle Ford, where we have an approximately 17% working interest and operations. Currently, we're now -- we are drilling on well number four out of five and we expect to frac these wells in July.
Our 2018 capital plan in the Eagle Ford calls for us to spend $12 million and bring online 16 gross, 3.6 net wells. With the Crosby pad already being online, we completed six of these wells. And with this 5-well Sayer pad underway, that'll get us a long ways towards completing our plan for the year. We're currently putting together a plan to drill some additional Eagle Ford wells later in the year to fulfill our drilling program there.
Going back to the Midland Basin for a moment; we have a deep inventory of highly economic operated drilling locations with over 500 gross operated locations across our 20,500 net operated acres in the Midland Basin.
Across both our operated and non-operated inventory of approximately 950 locations, 42% of these have a lateral length of between 6,250 feet and 8,750 feet and then about 55% of our wells have a lateral length between 8,750 feet and 10,000 feet. So this is a very high-quality inventory and allows us lots of running room. Right now, that inventory count includes five benches: the Wolfcamp A, two Wolfcamp Bs, the Wolfcamp C and the Lower Spraberry. Offset operators in close proximity to our acreage have successfully targeted additional Wolfcamp benches, along with the Middle Spraberry and Jo Mill. So as we continue delineating our acreage, we will add to our inventory from these other benches.
We continue to focus on making acreage trades and acquiring acreage in the Southern Midland Basin with the intent of drilling and completing longer laterals and turning some of our non-obligations into operated locations. At this point, we can't discuss any details of certain transactions we're working on, but keep in mind we are continuing to do this. Of course, we are pursuing acquisitions of bolt-on acreage and producing properties that contain accretive inventory as we look to increase our scale and drilling opportunities.
We also continue to build on our execution success and are working to further optimize our drilling and completion program. We're at a point now where we are consistently drilling wells from 15 to 17 days depending on depth and lateral length and within a cost range of $2.1 million to $2.6 million. We have also seen improvements on our frac efficiency by achieving 7 to 10 stages per day with costs staying around $81,000 to $83,000 per stage, which is only a few points of increase over December's completion.
So we are pleased with what we have achieved so far this year, and we see a lot of opportunity for growth ahead. Plus, it is great to see the improved commodity prices so we are optimistic about our ability to build on our track record for creating value.
And with that, operator, we'd like to now turn it over and take some questions.
[Operator Instructions] Our first question today is coming from Neal Dingmann from SunTrust Robinson Humphrey.
Robert, my first question is more just on the cadence for us that you said -- I know there's been some nice success on Wolfcamp C in that area. You might have already said this in the past, but on the cadence for the remainder of the year could you talk about sort of the split between may be As and upper Bs and Cs, how the plan lays out?
The rest of the year is going to be As and Bs. We've got that one C well that we've drilled and we'll complete it sometime later this month, maybe early June, but -- in terms of how we get to the schedule, but we won't drill any more C wells this year. So it's all As and B uppers and B lowers.
And then you didn't say too much, anything new to report from CrownQuest from the non-operated up in Glasscock County or any other area, how that activity sort of keeping up right now?
From a non-op standpoint, we do have some minor interest in some units being drilled both in Glasscock and then in the future we expect some more drilling in Howard County. It won't have any meaningful impact on production this year because I don't think the operators will get to completions till late in the year and then hopefully we'll see some more activity '19. But there's -- we haven't been AFE-ed on anything in Howard County as of yet.
And then just last, very quickly on you continue to seem to have no issues on getting your services for reasonable prices. Any thoughts, just if you could talk about that?
I guess, we have a long list of different vendors who can work for us or will work for us and luckily our operations guys have done a great job creating those relationships. And we put our team together, we give them a line of sight of six to eight wells to complete and they want to come out on our locations and work for us, so I give the credit to our operations guys. We're seeing a little bit of cost creep on the wages, which is hard for us to figure out how that gets incorporated into the actual cost of a frac job because we don't know all the details. But for the most part, we've -- our efficiency is helping keep our costs in line.
Our next question is coming from Jason Wangler from Imperial Capital.
I was curious, Robert, if you could maybe just walk through the eight wells that you initiated completions on? Just kind of a thought on the timing of those, how many kind of come on and the cadence of that as you look over the next couple of weeks or even months?
Okay. We got two wells up in Midland County we've already fracked and we should start drilling out by Monday or so assuming everything shows up like it's supposed to. And we ought to have those wells on in a few weeks, maybe it's two weeks or three weeks at the most. And we're fracking two wells in -- and the rest of the wells are all in Reagan County, so there are six wells to frac in Reagan County. We're on a 2-well pad now, so I suspect sometime late May that'll be on and then in June the other four wells, which are on two separate pads will come online. So that's -- order of magnitude, that's about as close as we can get at the moment.
No, that's helpful, just kind was the one interested in that. And then as you start to talk about a second rig possibly in the second half of the year, would that get you -- how would you look at the difference in the completion kind of planning than you do now? Obviously, you kind of build up a backlog, if you will, and then you're able to kind of complete like these eight. But as you got a second rig, would it be a similar plan, just there be less of a lag period? Or just how you think about that as you go forward operationally?
Yes, what we're considering or what we're looking into is how -- what is maybe the optimal sized pad for us to be drilling. So where we go put a rig and drill four wells off of one pad seems like -- it feels like it's the right size. I'm not sure there is an absolute right or wrong answer here for us, but there sure is a capital outlay and then a delay in getting production when you do these larger pads like this. So what we're probably going to do with the second rig is going to be on little larger pads, not just two well pads, but more likely three or four well pads and that'll create, again, a little lumpiness from the time you start drilling to the time you get first production when you got to drill four wells and then complete four wells.
So it's really just a logistical timing issue for all of this. And more activity creates more services that we need and that's why we're not out there running a rig right now because we don't want to drill wells that just sit there for months and months and months before we can actually go frac them.
Our next question is coming from Mike Kelly from Seaport Global Securities.
Robert, congrats on the recent promotion to President. I'm looking forward to the uptick in your Twitter activity going forward.
Okay.
A question for you kind of philosophically one here, one as being just kicked around is the potential risk in the industry right now and that's on this parent-child degradation issue, especially as it pertains to smaller operators who aren't completing massive multi-well pads and the potential to come back into a unit that's maybe got a couple wells in it and then have your child wells fare considerably less productively as a parent. And just want to get your sense on that and how maybe you guys have mitigated that risk in the program.
Okay, that's a big question and it's a big question, Mark, that I think the industry is still wrestling with. The perfect answer is you go out and develop whatever acreage position you have and you never notice that parent-child relationship. And that's not practical for most companies. So for us, at this point, we haven't really seen that. What we do see are some wells get hit by offset fracs even if they're not on the tightest pacing that you're ultimately going to develop the field on. But they tend to come back and I think every well where I've looked at where we've had to frac yet and -- or we've taken a well off-line just to avoid that, the production has come back to the trend that it was -- that it had prior to the offsetting well-being fracked. So there probably is a way to mitigate that better than maybe what we're doing, but right now I don't see as a giant issue. We get some downtime because of those wells getting impacted for a short period of time, maybe it's a month to 1.5 months that they're -- have reduced production or even off-line, but they do come back. And so that's the best that we can do.
Right now what we're doing is just studying what the bigger operators or operators who have done multi-well pads or multi-well development in the same bench or target, trying to figure out what makes the most sense and it really is company-specific based on capital. Again, the most efficient way reservoir-wise is probably to drill it all up at one time, but capital availability and other demands of the corporation maybe don't make that the best method to do it. So I don't think we have a good answer yet as an industry and specifically to us.
Got it, I appreciate the discussion on it. Getting a little more granular here, in terms of the program in Midland, once you finish up with these eight wells, you get the second rig slated to come in, but what do you think is kind of the most likely spot that you target? Or what's that kind of next batch of wells look like?
Well, the rig's going to continue drilling in Reagan and Upton County -- the first rig in Reagan and Upton County for the remainder of the year. Second rig, we're not -- we have haven't figured out exactly where it's going to go. I mean, we have some blocks in Midland, Upton and Reagan County where we could put it. And then the completion cadence, to some degree, will depend on how many wells we can build up and when our frac company can come back and that's probably late summer, maybe a little bit quicker, maybe a little bit later. It just depends on when we finish up and what their obligation is to go somewhere else before they come back to us.
So again, probably didn't give you a real good answer for your model, but...
Our next question is coming from Jeff Grampp from Northland Capital Markets.
Robert, curious, in your prepared remarks you quoted some cost D&C costs and I guess just doing a quick back of the envelope, it looks like that's maybe a touch under what's in your slide deck. Is that -- is the residual just the, I guess, the E component when you guys quote DC&E costs? Or with some of these recent efficiencies, is there maybe a little bit of incremental downside to your well cost?
No, you got it. I quoted a D and I quoted the majority of the C cost in that D&C and I didn't include the facility cost, so I wasn't trying to give you a whole well cost. I was just trying to break up the two big components.
Okay. Perfect, understood. And then if Frank were here, I'm sure he'd quote the advantages of being a multi-basin company and the capital flexibility there. So with dips in the Permian where they're at, does that give you guys maybe any consideration about timing of that second rig or maybe even looking at incrementally allocating capital potentially to the Eagle Ford just given the regional differentials in pricing?
We still get LLS pricing, so that helps insulate some of the differential -- basis differential in the Midland Basin, so I hear what you're saying there. But from an economic standpoint, even at $65 or $60 oil and our inventory as it is and the nature of our Eagle Ford being majority HBP-ed or in general better economics, I think we still spend our capital in the Midland Basin.
Okay, understood. And just one more kind of on the modeling side. I noticed the Permian oil mix was down a little bit. Is that just a function of fewer well completions? I know GOR kind of trends higher over time and then we should expect that -- the oil mix to kind of kick back up with some of these new wells coming on. Is that the right way to think about things?
Yes. I hope that we end up with a little bit higher, a point or two higher in the second quarter depending on when wells actually come online. But you got it right. You don't do any activity, have no new wells coming on, your oil percentage ought to drop a little bit over time. But I think it's still kind of within our guidance for the year. I think we're in still pretty good shape.
[Operator Instructions] Our next question today is coming from Ron Mills from Johnson Rice & Company.
Just a question on the inventory. I think, Robert, you may have said earlier that you're now talking about inventory coming from five benches. I thought you were -- you had previously included inventory from four benches. What bench did you add? And how many locations was that?
Well, we've got A, two Bs, a C, the Lower Spraberry, what am I missing?
There's two more. Two Bs is like...
Yes, two B's. Yes. So I think that's how you get there, Ron. The only thing that we updated at year-end is the C. We added, on the order of magnitude, 100 locations in the Wolfcamp C throughout portions of our Reagan County acreage and even a little bit in Upton County, I believe. So that's the difference.
Okay, great. And you talk about continuing to pursue swaps and bolt-ons. Can you give us a sense in terms of particularly bolt-on opportunities and even bigger type opportunities? What's the lay of the land in the Midland Basin, especially in your portion of the Midland Basin in terms of an opportunity set out there in terms of potential packages?
Well, most of these aren't really packages. They're opportunities that our land team, through doing work on where our acreage resides and who's offsetting us and who needs to do a trade so that we can both drill 10,000 footers or 7,500 footers or whatever it might be, develop these opportunities. They're not necessarily packages. There are a few packages out there and we review them and participate. But generally speaking, we've been able to find these bolt-ons. They're small and trades -- and the trades obviously don't go through a package kind of a broker or anything like that. But these kind of things, we've got a laundry list of 10 or 12 different opportunities that we're working on that are a bit more than 75% of them are in-house generated.
And again, it's just becoming more efficient and all the operators are willing to discuss how we become more efficient.
But longer term to kind of get to Frank's goal of potentially doubling your position, does that still probable -- or most likely include the need to do another larger type deal? Or do you think there's enough of those small opportunities to get there?
Yes. The small opportunities are going to help grow our 20,000 number to some other number meaningful, but not going to double it. It's going to take a big transaction or 3,000- or 4,000-, 5,000-acre transactions that we continue to look at and work on and knock on doors. So yes, to double our footprint is going to be easier if we can do it one fell swoop, but chance of success on deals like that are harder. And there are a few of those out there and we're working on those. They just take a lot longer.
Nice to have the balance sheet to be able to pursue them. And then, lastly, is for Mark, just a mundane modeling question. Can you talk about the first quarter G&A? Does that include any sort of reimbursement or something that took a big tick down, trying to see if what a better run rate is if there was some onetime items in that first quarter G&A?
Sure. No, there's not really any onetime items in the first quarter. And you probably noted, it was about from a cash standpoint $1 million plus in the prior three quarters. That's more an impact of the kind of onetime items we had throughout the last three quarters of last year, which were severance from the acquisition of Bold last year and quite a bit more legal expenses and other transaction expenses. In terms of a run rate, certainly I wouldn't be modeling that you expected the whole plan at $4.6 million or $4.7 million per quarter. We will continue to add some staff and we're very pleased with that number for the first quarter. But don't expect it to be hanging quite that low and should probably trend up a little bit over the course of the year.
And I guess, Mark, I was thinking more from a cash G&A standpoint. Is -- the cash G&A is what took a big stepdown from the mid-$5 million range to the mid-2s?
I'm looking at a cash G&A of $4.6 million for the first quarter versus $5.6 million for the last three quarters of '17. So we expect...
I got you. Really, it's just -- it may have been something on my side. So the $4.6 million, it may jump back to where it had been running, but there wasn't anything onetime?
That's right. I think bottom line, if we were at $20 million for the entire year after being $4.6 million for the first quarter cash G&A, we feel pretty good about that and it may churn up a little bit higher than that.
Our next question today is coming from Gordon Douthat from Wells Fargo.
Robert, you mentioned LLS pricing, and I guess, I wanted to clarify. Was that in reference to your Eagle Ford volumes or Permian or both or...
Yes. I wish we got into our Permian, but we don't have that luxury of getting our Permian barrels to the water. So somebody does, but we don't. So it's only in our Eagle Ford. Yes, we've got the Mid-Cush diff going on in our Permian barrels just like everybody else.
Gordon, it might be worth articulating, obviously we look at the diffs and it's painful and it seems like it's going to be painful for a while and maybe get even a little more painful than it's been. If you just look at the first quarter, we had less than half of our total company-wide oil production exposed to the Midland differential and that's based partly on having over 1/3 of our Midland Basin production hedged with a really nice look in basis adds up $0.15 per barrel and then a good shock of our production, about 25% or 26% of oil, is in Eagle Ford.
So all in, 53% of our production for the first quarter was not exposed to Midland Basin's differentials. And as we grow Midland Basin production going throughout the year, there will be more exposure, but it's a descent mitigate starting out and throughout the course of the year.
Thanks Mark, for that explanation. And I just wanted to get, kind of related to that topic, just an overview of how you're seeing the situation unfold from an infrastructure standpoint in the Permian and how it's impacting you guys in how you bring your production on?
Yes, Gordon. We have access and we bid out new barrels all the time to multiple purchasers. And again, all our crude is trucked. We're looking into piping in certain places where it makes sense nearby. But given that our acreage is scattered, you might say, or in different blocks even within Reagan County, it does give us options and there's plenty of trucking points that we can central -- delivery points that we can actually truck our barrels to and it's relatively low cost to get to those points. We can't control the basis differential. And the good news is NYMEX prices are up, so our economics still look pretty juicy compared to a $60 price deck.
So we're looking at continually hedging that basis. Probably today is not the right day to do it, but we'll continue to watch opportunities to maybe layer in some hedges.
Ladies and gentlemen, we've reached the end of our question-and-answer session. I'd like to turn the floor back over to management for any further or closing comments.
Yes, we thank everybody for listening in and we'll continue to keep you updated. Thanks a lot.
Thank you. That does conclude today's teleconference. You may disconnect your lines at this time, and have a wonderful day. We thank you for your participation today.