Abraxas Petroleum Corporation
Q3 2018 Earnings Call Transcript

Published: 8 Nov 2018

[Operator:]

Good day, ladies and gentlemen, and welcome to your Q3 2018 Abraxas Petroleum Corporation Earnings Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will be given at that time. [Operator Instructions] I would now like to turn the call over to Steven Harris. Sir, you may begin.

[Steven Harris:]

Thank you, Sidney. I apologize everybody for being a few minutes late, but welcome to the Abraxas Petroleum third quarter 2018 earnings conference call. With me here are Bob Watson, along with our Chief Accounting Officer and VPs of Operations, Land and Engineering, all available to answer any questions that you may have, after Bob’s overview. Just as a reminder, today’s call is being taped, and a webcast replay will be available immediately after the conclusion of the call. I would like to remind everyone that any statements made during this call that are not statements of historical facts are considered forward-looking statements, and actual results could vary materially from those contained in these statements. Factors that could cause our actual results to vary are described in our filings with the Securities and Exchange Commission. I would encourage everyone to review the risk factors contained in these filings and in our press releases. With that, I would like to turn the call over to Bob.

[Bob Watson:]

Thank you, Steve, and good afternoon. I hope this -- the time of the call is a little bit better for most people out there instead of jamming everybody into the morning. I’m going to start off by just bringing up-to-date on what’s happening currently. In the Delaware basin, West Texas, our two-well Mesquite Pad, in which we own 73% interest in flowing back nicely. It’s a little over 1,800 barrels a day from the two wells, about 40 days in. So, we expect the peak rates in the next 20 days. Our drilling rig is on a two-well pad, we call Creosote, we own 80% interest in those two wells. Operations are going along normally. We expect those wells to be completed here before the end of the month and the frac scheduled shortly after the first of the year. We actually have a frac rigging up as we speak on our Pecan 47 one well pad in which we own 100% interest. That frac should start pumping this weekend, and we hope to have that well on production -- or at least starting flow back by the end of this month. The rig will then move to a two-well Hackberry Pad, our ownership is very high. We don’t know exactly what it is yet, but hopefully it will be close to 100% by the time we spud those well. And then, those wells be fracked sometime early second quarter. Production operations are going smoothly. We have now finished -- our engineering group has now finished the Phase 2 of our downspacing study on our Caprito 99 Pad. We still want to do a Phase 3, but after a thorough evaluation of the data that we have obtained, including micro seismic and tracers and monitoring the production. We would tend to say right now that the appropriate spacing, at least in the Caprito area and the Wolfcamp zones is probably going to be 660 feet between wells. We don’t see significant interference between wells that are that close, and we have reasons to explain the difference between the parent and child. Good news is the child wells are still producing above our type curve and are very economic. So, that becomes less and less of an issue, and we will report back to you when we finish our Phase 3. And our ultimate decision for spacing, at least in the Caprito area and the surrounding acreage that we have where we have tested the downspacing. In North Dakota, the winter has arrived a little earlier than normal. We did not think starting frac jobs in early October, finishing in early November, would run into severe winter weather. We have. The frac on the Ravin Northeast pad is almost finished, despite being down four days earlier this week because of road closures; we couldn’t hall in oil, frac fuel or frac sand. Good news is, the fracs are back underway, they should be finished by this weekend and then, we will immediately start prepping those wells to flow back as well as the four wells on the north central pad that were fraced in earlier in October which we last shut in for frac protection. We also have six older wells on the Ravin pads shut in for frac protect. So, over the next several weeks, we’re going to have 14 new wells coming on line, flowing back, which all on schedule and should -- means a very dramatic boost in production for the month of December. The drilling rig -- company-owned drilling rig is drilling ahead very nicely on the Lillibridge Northwest Pad, it’s a four-well pad and it is scheduled to move when that is finished to the Jore Federal East extension pad or a five-well pad. The rig will continue drilling throughout the winter, but we don’t expect to have any frac jobs starting up until in the Bakken anyway until summer weather next summer. So, a few comments about our future. Yesterday, we released our 2019 budget, which has been approved by our Board. It includes 12 drill and/or complete wells in the Delaware for $58 million, 13 drill and/or complete wells in the Bakken for $39 million, and $11 million for acreage and facilities. This budget is designed to generate free cash flow. And that’s our goal going forward. In Delaware, we will have one rig continuous program with subsequent fracs every several months. And we will continue to acquire bolt-on acreage. We’ve been successful in buying out several of our non-operated working interest partners on our existing units. That’s certainly a major goal for us. We’d like to own a 100% of everything we do. So, the last 300 or so acres that we acquired that we announced has not changed our footprint any, but it’s increased our ownership in our existing footprint. Up in the Bakken, we will continue one rig drill -- drilling program as well as completions during the warmer weather months. And again, I said, we won’t frac anymore in Bakken till summertime at which time June runs around, we should have 9 wells ready to frac and bring on production shortly thereafter. It’s interesting to note that QEP announced the sale of their Bakken asset this week, which confirmed which we’ve known for a long time is that our Bakken assets have considerable value. And my goal is to somehow crystallize that value in our share price in the upcoming months. We expect to be producing in December 8,000 to 9,000 barrels a day net in the Bakken. And if used the metrics that QEP received in their sale of similar type high PDP assets, you’ll come up with a number that’s somewhat greater than our current market cap. So, that’s my goal is to try to convince people that our shares are undervalued and that the Bakken is going for free and it has substantial value. As far as guidance goes, we don’t want to start the year until we know what our starting point is. So, we’re going to wait until we have these 14 Bakken wells and one Delaware well, pretty much flowing back to where we know what the ultimate exit rate’s going to be. So, that probably means we’ll be issuing 2019 guidance somewhere toward the middle or the right before Christmas in December. What we’ve done different this year in our internal model is tried to avoid the surprises that we had this past year, because of setting in wells for frac protection and also to account for flare -- gases have to be flared due to lack of facilities. So, we’ve actually entered into the model, and it will be representing our guidance, shut in time on our wells for frac protection. What we don’t know and we can’t predict what we try to anticipate when offset operators were going to be fracing wells near us and account for that. But you never can tell, when you might be surprised and have to shut into well because of an offset operator. I think we’re getting better on the timing on our shut ins. We’re not having to shut them in as long as we have in the past, so that will certainly help. But we also know that shutting in wells and frac protecting is certainly the conservative way to go and it avoids very costly cleanouts that an unprotected well could have. So, overall, our guidance is going to be conservative. We’re using our -- the type curves that are on our website. And I might remind you that our latest corporate presentation was 8-Ked Tuesday and it should be on our website now. And included in that presentation are all our type curves and all of our actual productions as they appear associated with those type curves. And you will see that we continue to beat pretty regularly our type curve projection. So, the fact that we’re beating our type curves creates some cushion in our guidance and in our model, and hopefully we’ll continue to do that going on through the year, which will allow us to gradually increase our guidance as time goes on. Longer term, our plans are to manage our business to generate free cash flow, proceeds from free cash flow will initially go down to paying down debt till we get the banks happy with the level that it is. And they’re pretty close to that right now. And my ultimate goal with that be to start buying back shares. It should come to nobody surprise that there’s no way we can go into the Bakken or the Delaware in the core areas and buy assets for anywhere near as cheap as our shares are trading. So, an obvious use of our free cash flow, even though it could be used to accelerate our activity is to buy back shares and take advantage of low trading price. So, with that, I’ll open it for questions.

[Operator:]

[Operator Instructions] Our first question comes from Michael Scialla with Stifel. Your line is now open.

[Michael Scialla:]

I guess, I realize you are not ready put out official guidance yet on the production side at lease, but I guess you’ve given us at least an anchor there saying you anticipate you are going to be free cash flow positive. Is that based on current strip price or some lower oil price?

[Bob Watson:]

It’s current strip and current average differentials. We actually see those maybe improving as time goes on during ‘19, but we held them constant in our model anyway throughout the year. And who knows about oil prices. That’s why we don’t guide the cash flow or earnings or anything like that because we don’t want to get into the business of your business, which is prognosticating on oil prices.

[Michael Scialla:]

Right. Well, that’s always fun. I guess, given that, based on our numbers, if we strip right now, you are at least looking at some double-digit growth, safe to say that?

[Bob Watson:]

Yes. I think we are very comfortable with double-digit growth going forward. The exact amount, that’s going to have to wait until we come out with our guidance because a company our size and you’re putting on a 14 -- actually 15 new wells this month, there’s just no way to get a real comfortable handle on what those wells are going to be generating and what your exit rates going to be until you get them actually on production.

[Michael Scialla:]

I wanted to ask too on the Caprito spacing test, you said this Phase 2 confirms the 660 spacing at least so far. What will you be doing with Phase 3? And how much do you think or to what level do you believe that Caprito area is representative of your other acreage?

[Bob Watson:]

I think, our gut tells this that all acreage is going to be similar. But, we don’t want to sneak our neck out until we actually tested it. But, I think the information we know now from say the Greasewood area all the way down the Mesquite area, which is probably about 10 miles or so, 12 miles, we are comfortable with the spacing in that area, at least through Phase 2. Phase 3 is going to be doing some tracer work on water that we are producing. Delaware wells make a lot of water. These wells appear to be making some extraneous water, which has got our curiosity up. So, we want to try to determine the source of that water and that could have a significant impact on how we develop these leases going forward. As a prime example that we have a that we have a very high confidence level that we might have fraced into a water disposal well about a mile away. And it appears that the wells are making water that are similar to what is being disposed into that well, which is not the same as Wolfcamp water. So, that could explain some of the underperformance that we’ve seen relative to the parent well. But, the good news is, the underperformance isn’t all that bad. And certainly the total fluid that those wells are lifting is very satisfactory. And if we can get the normal water cut in future wells, then we’re very comfortable with the 660 spacing at that point.

[Operator:]

Our following question comes from John Aschenbeck with Seaport Global Securities. Your line is now open.

[John Aschenbeck:]

Steve, congrats on the promotion. Bob, just one follow-up on your free cash flow outlook in 2019, specifically in terms of the potential for buybacks, which I thought was pretty interesting. Couple of questions there for you. One, would there be any type of limiting factor that could prevent you from buying back shares, like a bank covenant or something along those lines? And then secondly, how aggressive would you -- do you envision yourself getting with that buyback program? And how would you look to manage that program? Whether it be just matching up buybacks with free cash flow, managing to a leverage metric or perhaps something else?

[Bob Watson:]

We currently have a restrictive covenant in our bank agreement that precludes us from buying back equity or paying a dividend. And what I meant by making the banks happy in my statement was, we want to get them happy with the fact that we are generating free cash flow and that our leverage levels are very conservative, and hopefully they would agree to let us ease part of that free cash flow to start buying back shares. As far as designing it, I would like to be as aggressive as I can. There are limits that the SEC puts on corporate buybacks, they limit you to a percentage of trailing 25 days dollar volume as well as you can’t trade early in the morning or late in the evening, things like that entirely. I’m not entirely comfortable with that yet, but I’m going to learn. So, we will come up with some sort of a plan. But if we’re selling it between 2 and 3 times EBITDA and properties are selling at 6 to 10 times EBITDA, that’s a pretty good arbitrage there. So, it makes sense for us to be as aggressive as possible as long our share prices trading so low.

[John Aschenbeck:]

Great, completely agree as well. So, just looking bigger picture for my follow-up question and looking at the overall portfolio. I would love to get your thoughts on what you envision as a long, long term plan in the Bakken. You have, call it, 20 plus or minus locations left there, which are obviously extremely valuable. But, in the very near future, that asset will more or less be a PDP asset. And I’m just wondering, if you think that that asset, once it is primarily PDP, whether or not it has more value in your hands or perhaps someone else’s?

[Bob Watson:]

I would say, it depends on price. Obviously, I’m going to be spending a lot of time over the next several months talking with various outside financial people to see what would be best for Abraxas. There’re a lot of alternatives with that asset, all of them are good, which is nice thing to have. In the worst case, it’s going to be a great cash cow. But, if somebody wants to pay us full value for it, yes, certainly, we would consider that and then that would be a huge source of buyback money, if that were to be the case. But there are other avenues that we might pursue. The whole goal is to try to convince investors that the value is there. And so, thus my comments on trying to figure out a way to crystallize that value, and I have not decided which way is best yet. But, we we’ll try to be as transparent as we can in that process. We certainly don’t want to jeopardize the operations or put expectations out of reach or anything like that but we are certainly going to be working on it.

[Operator:]

Thank you. Our next question comes from Ron Mills with Johnson Rice. Your line is now open.

[Ron Mills:]

Just one on the free cash flow, just to beat the dead horse. When you talk about generating levels of free cash flow in terms of order of magnitude, are you talking about free cash flow yield of 5% to 10%, or is it even higher than that?

[Bob Watson:]

Well, you’re telling that all prices are going to be -- and I’d say…

[Ron Mills:]

Well, just assuming strip.

[Bob Watson:]

At strip, it’s in the lower magnitude but if we get back up into the $70 range, it becomes a bigger and bigger magnitude. And we can see good double-digit growth and generating free cash flow. I’d like to be in a position to say to the banks I’ll pay down debt with that and buy shares with that. It’s very early in the stage, but I think it’s important for people to know that that is one of our objectives. And the fact that we recognize our shares are trading so cheaply is generating a level of frustration on our part. And one way to solve that is to take things in our own hand, and that would buying back our own shares.

[Ron Mills:]

And just to also piggyback on John’s last question, in terms of -- given where you’re in the development of the Bakken, as you evaluate these alternatives, part of that’s probably also evaluating the time. Do you think the time is best when you still have a little bit of meat left on the bone in terms of development to go or is it best once you just get closer to a PDP harvesting standpoint?

[Bob Watson:]

I think that would depend on the market that you’re looking at. There are people out there that are strictly PDP buyers and they won’t give anything for the development. And yet there are people that want high level of PDP but a little bit of meat left on the bone. So, I think, we will start evaluating all our options now. And it could be we decide that we’re better off developing this property fully and then doing something with a PDP asset, or could be we do something now and let somebody have the additional locations which happen to be great rock and very high working interest. So, they’re very valuable assets, those remaining locations.

[Ron Mills:]

Now, to my question -- in the Permian, the 2,000 acre position that you have, you’ve done a great job through swaps and acquiring interest of getting to that point. How much more from a swap standpoint or how much more incremental interest do you think you can add in your existing footprint and what are your thoughts on critical mass there, especially given some of the larger operators around you?

[Bob Watson:]

Ultimately, this is a big company play, majors and big independents. But, I think there’s still some room to add value before that happens. Whether we can add significant amount of additional acreage in our area, which we’ve identified as some of the best rock in the Delaware, and there’s another bank out there that’s done a recent paper that says this is the best rock in the Delaware. And we just happened to be there, that’s good. But, it’s well recognized by others that it’s good rock. So, it’s getting harder and harder to get deals done. We have a very good relationship with the University Lands and that might help us in the future. There are some companies that might have issues holding wells or holding leases with marginal wells, and they need to get wells drilled in a hurry, and they’re not capable of moving that fast themselves. So, there might be an opportunity for us to do something along those lines. And I see that as a potential source of bigger chunks of acreage, but nowhere near what we already have. I think that’s beyond the realm of anybody’s imagination that we could do that. But, when you look at our inventory now, at least part of our acreage on 660 spacing, it’s 30 to 40-year to rig program. We haven’t modeled it out that far to see how far we could go on two rigs and still increase production double digits and generate free cash flow, but that’s going to be something we endeavor to do. But, I guess my question is how much more inventory you need than that. So, we’ll be doing a lot of study and head scratching and we’re certainly looking for opportunities. Dirk Schwartz, our VP of business development digs around and comes up with all sorts of weird things that seem like they work and they do work and we’re able to get them done. So, it takes a Dirk type guy to be able to do that and we’re very fortunate that he’s here and doing that. So, he will continue to add little pieces here in there. And any one deal might not make a whole lot of difference but collectively they make a big difference.

[Ron Mills:]

And then, the last one. You talked about commentary about longer laterals and at some point you’ve reached the point of diminishing returns with another couple months of data there. Can you just provide us an update on your latest thoughts on lateral length, given it may not seem that longer is always better?

[Bob Watson:]

Well, I’ll tell you what, the guy that authored that study is sitting right next to me. So, I’m going to let him address that question.

[Pete Bommer:]

Thanks, Bob. It’s Pete Bommer, VP of Engineering. Yes. We work the data pretty hard, as hard as we could. We study 450 wells out there in our vicinity. And whereas it’s obvious that longer laterals clearly make more oil in total, on a per foot basis, they do not. However, there is a cost savings with drilling on a per foot basis for longer laterals. But in our study, based on our economic parameters, the rate of returns diminished with the lateral length with perhaps an optimization point in the mid range somewhere, maybe 7,000, 7,500 feet. But, in all of our studies, the longer lateral group 10,000 feet or longer, all yielded diminishing rate of return. So, we haven’t seen anything recently that changes that finding. But, it certainly will be worth reviewing from time to time.

[Operator:]

The following question comes from Dennis Fong with Canaccord. Your line is now open.

[Dennis Fong:]

I have got a couple here, just kind of following a little bit of similar vein thoughts. You mentioned a scenario where you are going to actually purchase back shares, your -- the bank covenants kind of loosen to allow you to do that. How do you balance essentially share repurchase versus potentially acquiring more land within the context of the Delaware? Obviously both kind of are accretive to net asset value, not necessarily to account on cash flow basis But I just want to understand that. And then, just out of curiosity with respect to relative leverage metric, like if I think about next year, I’ll call it debt to cash flow, at what level do you feel comfortable paying down debt versus repaying -- or repurchasing shares and what’s your mindset around that?

[Bob Watson:]

I think our ultimate goal is to be around 1 times debt to EBITDA. I think that’s very comfortable with you guys up in Canada as well. It seems to be the mantra up there. So, I think we are very comfortable that we will be there in ‘19. And as far as going forward, yes, keeping debt at 1 times EBITDA and spending the rest on buying back shares. As long as there is a huge value disparity between what it costs us to buy more acreage or to drill more wells versus where our shares are trading, it’s going to bias our activity toward buying shares. Now, if our share price trades up to a higher EBITDA multiple, then we have to scratch our heads and make a decision on do we keep buying shares or do we slow down and start drilling more wells or something along those lines. But it’s kind of a no-brainer right now with the shares trading at 2 and 3 times EBITDA. I can’t buy any kind of asset for anywhere near that cheap, in the core area. And we are not interested in doing fringy stuff.

[Dennis Fong:]

You kind of mentioned the farm in items there and then kind of farm in/earn-in with the drilling of a well, how does that potentially balance in your mind versus buying back shares?

[Bob Watson:]

I would say that in our area, if we can do that, we would probably do that rather than buy back shares. We don’t have any of those deals in hand yet. We would hope to continue to work on them. And certainly, if we can work on one, then that would probably take a higher priority because the acreage is such high quality acreage, it would take a higher priority than a share buyback.

[Dennis Fong:]

And then, just one quick item on operations. So, now that you have a little bit of operation -- or operational data on the upper Bone Spring. how many of your upcoming 12 wells in the 2019 budget incorporate wells into the upper Bone Spring? And how are you going to seeing that, call it layer within the context of the Delaware, on a go forward basis on your land position?

[Bob Watson:]

I think you certainly have curveball on that one. I don’t know that I know right now the targets of those 12 wells. What I do know is, we are very comfortable with the Wolfcamp A-1 and A-2, and third Bone Springs as being pretty much equivalent. So, it really doesn’t matter to me. It’s going to depend on where the well site hits in the section, so as not to harm our wine rack. This doesn’t show -- oh, yes, it does show. Here we go. Woodbury is -- it just shows what the next -- 101 is Bone Spring. Okay. So, I got one, two -- to what degree two-well, I don’t have a number. I’ll better go back to my -- we’re going to be testing all three of those zones on those 12 wells and will probably fill in another Wolfcamp B and possibly if the upper third Bone Spring zone that we’re testing on the ski key continues to perform like it is, we’re going to add that to the mix too. So it’s a good position to be in, when you have that many targets that are pretty much equivalent, you can’t go wrong by picking one over the other.

[Operator:]

Thank you. Our following question comes from Noel Parks Coker Palmer Institutional. Your line is now open.

[Noel Parks:]

So, as you keep making progress in drilling, and folks nearby do too, I’m just trying to think about the options for codevelopment of multiple zones and I imagine that’s still a ways in the future. But do you have any primarily thoughts on what that might look like on your acreage.

[Bob Watson:]

You mean multiple zones in the same wellbore?

[Noel Parks:]

Right.

[Bob Watson:]

I think we have the technology to do that now. It’s risky and it’s very expensive. So, we’re going to let the big guys keep experimenting with that and using their money to figure out a better way to do it. We will stay up with what’s going on. But right now, that’s a big, big company science project. And that just doesn’t fit what we need to do, but it certainly could happen in the future. I’m not writing it off. But things have to be improved from a risk standpoint and an economic standpoint before we attempt it.

[Noel Parks:]

Got you. And overall industry, it seems that there is this assumption that the bulk of takeaway issues in the Delaware will -- if not be solved that the industry will start to turn the corner by mid-2019 or late 2019. I’m just wondering is that what something you agreed with as far as what was likely to happen. And also looking further out, if we get to a point of consistently cheaper transportation out of the basin, does that sort of redraw the economic map of either where you are or where you might consider entering into -- I don’t figure you want to do anything fringy but in between fringy the best rock, could transportation cost redraw that map for you?

[Bob Watson:]

I guess, it could. I don’t foresee it happening in the next year or so. I happen to think that the transportation issue’s going to get better as time goes on, and probably get better than the market’s reflecting right now. And so, I’m look what the mid-Cush differential has done just in the month of October. It’s gone from a peak of about 17 down to single digits in one month, which kind of offset the decrease in oil prices, if you think about it. $17 differential at $70 is net-net 53, and an $8 differential at $61 is net-net 53. So, it’s not a major item. And I think there was more concern with actual takeaway capacity and people having to shut wells in. That has not happened to us. I have not heard of it happening to anybody. And you hear little news, like I heard today that Plains’ Sunrise project is they found another market for 150,000 barrels or so. So, it’s gone from 220 a day to almost 400 a day. Little things like that add up, and that’s certainly going to help that takeaway issue considerably. And to the effect that takeaway is impacted, it’s going to reduce that differential as well.

[Operator:]

Thank you. [Operator Instructions] Our next question comes from Ray Deacon Energy Advisors. Your line is open.

[Ray Deacon:]

I was wondering your average lateral you’re saying next year will be 4,500, it will stay the same or will you try a couple of 7,500 footers?

[Bob Watson:]

In all probability, they’re going to be around 4,800, all of them that we have planned. We do have an opportunity to drill some longer laterals. We might get into doing some of that towards the end of the year. But, our current budget we announced yesterday just entails 4,800 foot laterals each.

[Ray Deacon:]

And I know you mentioned that in terms of share buybacks, you were constrained on cash flows. But, if you were to dispose some non-core assets like the mineral acreage or royalty or the rig or something, would you have the same constraints there?

[Bob Watson:]

If they’re pledged to the bank line, we would. I don’t know if mineral’s pledged. So, yes, there are some assets like that that we could possibly divest and use the proceeds without bank agreement to buy back shares.

[Ray Deacon:]

And I guess just one last one for Steve. If you were to approach like an Apollo or somebody like that, where do you think your cost of debt would be for kind of more permanent debt financing?

[Steven Harris:]

It’s a loaded question. I mean, it obviously wouldn’t be what appears that harvesting times our size would, but we’ve explored and are currently exploring a few alternatives on that side. And I think it’s safe to say that that’s low to mid double digits for a Company of our size.

[Operator:]

Thank you so much. Our following question comes from John Brewer with Blb & B Advisors. Your line is open.

[John Brewer:]

I guess, I just had one question today. In my retirement, I spend most of my time doing research. And one of the things that I came across really in the last week was an article about lithium. And United States had rather almost no lithium production, certainly not anything like the Great Triangle and Chile and that part of the world. But they have been in development, utilizing the water from oil wells. Somebody has done some testing and found out that that water is loaded with lithium and that there is a beginning to be -- in fact, they suggest in this article that there is enough lithium and the water is coming from wells throughout the United States to more than supply the total needs of the United States in electric cars et cetera, et cetera. Is that something that you folks have come across or is it just too new for that?

[Bob Watson:]

I’ll tell you what, John, you’ve tickled our curiosity. We’re going to certainly look at our water analysis and see what we’ve got, if we make a load of water and we could strip out lithium – lithium’s a salt…

[John Brewer:]

Well, we’re talking specifically about the Permian basin which of course is enormous but that area was -- testing from that area was such that it was very economically feasible to take that water and extract the lithium from it. So, I guess, I thought I would mention it. Certainly, you might be interested in it if you weren’t already aware of it.

[Bob Watson:]

I guarantee you, we’ll look into it now and I appreciate the comments because none of us around this table had heard that. It’s certainly possible. So, we’ll look into it.

[John Brewer:]

All right. I hope you guys go down there, and we’ll continue to look for you.

[Bob Watson:]

Well, I appreciate it, John. And thanks for letting us be in this wake. It is always good addition.

[Operator:]

Thank you. I’m showing no further questions at this time. I would now like to turn the call back to Steven Harris for any closing remarks.

[Steven Harris:]

Thank you, Sidney. Look, we appreciate everybody’s participation of the call today. As I mentioned, at the start of webcast, replay will be available on our website and transcript will be posted in about 24 hours. So, thanks everybody and have a good day.

[Operator:]

Ladies and gentlemen, thank you for participating in today’s conference. This does conclude the program and you may all disconnect. Everyone, have a great day.