© 2024 Alpha Spread Limited. All Rights Reserved.
www.alphaspread.com is not operated by a broker, a dealer, or a registered investment adviser. Under no circumstances does any information posted on www.alphaspread.com represent a recommendation to buy or sell a security. The information on this site, and in its related newsletters, is not intended to be, nor does it constitute, investment advice or recommendations. The information on this site is in no way guaranteed for completeness, accuracy or in any other way. In no event shall Alpha Spread Limited be liable to any member, guest or third party for any damages of any kind arising out of the use of any content or other material published or available on www.alphaspread.com, or relating to the use of, or inability to use, www.alphaspread.com or any content, including, without limitation, any investment losses, lost profits, lost opportunity, special, incidental, indirect, consequential or punitive damages. Past performance is a poor indicator of future performance.
You don't have any saved screeners yet
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good morning, ladies and gentlemen. Welcome to the Third Quarter 2019 Matador Resources Company Earnings Conference Call. My name is Bridget, and I'll be serving as the operator for today. At this time all participants are in a listen only mode. We will facilitate a question-and-answer session at the end of the company's remarks. As a reminder, this conference is being recorded for replay purposes and the replay will be available on the company's website through November 30, 2019, as discussed in the company's earnings press release issued yesterday.
I will now turn the call over to Mr. Mac Schmitz, Capital Markets Coordinator for Matador. Mr. Smith you may begin.
Thank you, Bridget. Good morning, everyone, and thank you for joining us for Matador's Third Quarter 2019 Earnings Conference Call. Some of the presenters today will reference certain non-GAAP financial measures regularly used by Matador Resources in measuring the company's financial performance. Reconciliations of such non-GAAP financial measures with comparable financial measures calculated in accordance with GAAP are contained at the end of the company's earnings press release. As a reminder certain statements included in this morning's presentation may be forward-looking and reflect the company's current expectations or forecasts of future events based on the information that is now available.
Actual results and future events could differ materially from those anticipated in such statements. Additional information concerning factors that could cause actual results to differ materially is contained in the company's earnings release and its most recently quarterly report on Form 10-Q.
Finally, in addition to our earnings press release I would like to remind everyone on the call that you can find a short slide presentation summarizing the highlights of our third quarter 2019 earnings release on our website on the Events and Presentations page under the Investor Relations tab.
I would now like to turn the call over to Mr. Joe Foran, our Chairman and CEO. Joe?
Thank you, Mac. Good morning to everyone on the line and thank you for participating in today's call. We appreciate your time and the interest in Matador very much and we appreciate your comments in our discussions with you.
Now, I would like to introduce the executive committee who is joining me this morning along with other members of our management team and senior staff who are standing by for all your questions. They are Matt Hairford, President; David Lancaster, Executive Vice President and Chief Financial Officer; Craig Adams, Executive Vice President and Chief Operating Officer Land Legal and Administration; Billy Goodwin, Executive Vice President and Chief Operating Officer Drilling Completions and Production; Van Singleton, Executive Vice President of Land; Brad Robinson, Executive Vice President of Reservoir Engineering and Chief Technology Officer; Greg Krug, Executive Vice President of Marketing and Midstream Strategy.
We also have a special guest today. We have with us Jason Thibodeaux, who is the Head of our Field Operations out there in Southeastern New Mexico and in Loving County. And Jason runs the crews that keep our production going. Good weather, bad weather, no matter what comes up he and his crew have been there and done that and make sure that things have gone smoothly as we could. And so Jason thank you very much for being here and thank your field people for all that they do.
The – as outlined in our earnings release issued yesterday, we are very pleased to report the third quarter of 2019 we felt was the best quarter in company's history. We had many financial and operational achievements during the quarter and I want to take a moment and personally thank the rest of the Matador staff for all their hard work and dedication. It – our business is too complex to thank one person does it? And this is a group that not only each contributes but they work very well together to make it work even more effectively
Now, I'd like to highlight a few key points before taking your questions this morning. The first is what I said about the team. I want to mention our Board and how supportive and helpful they've been over the last year in working out the strategies that we've been implementing and they appear to be working very well.
The second thing is, when we began the year we laid out a plan and we've been executing on that plan doing what we said we were going to do that we thought we would develop Antelope Ridge into another area of great interest for us. And it's worked out that way. We've also reached the production targets and beyond what we hope to achieve. We've kept to the six-rig program.
Billy has managed to upgrade those rigs. And those are working as good or better than ever. We've continued to lower costs. So we've actually had more wells drilled for less cost. And so we've been able to do that tricky movement there as where you reduce your CapEx spending, but you actually get more for your dollar, because you have more wells and better-than-expected production.
The last thing is we continue to address the issues that you all noted and we're making progress, we believe on all fronts and narrowing the spending gap, which may accelerate in the next quarter or two. And that we've looked at other cards that we have to play that could lead to increased valuation.
And finally, the midstream has received the attention -- special attention this year. We began the year with doing another San Mateo deal. And as we had indicated we would work that up to a $25 million EBITDA quarter and we've achieved that. Now that thunder you hear coming in I don't know whether you hear it or not. But if it comes in it's not directed at us. We consider that applause from above.
All right. Now let me turn it over to you for questions.
[Operator Instructions] The first question comes from the line of Scott Hanold with RBC Capital Markets. Your line is open.
Thanks. Good morning, guys.
Hi, Scott.
It looks like you guys gave some pretty good color on how you progress into the next quarter. And by the way obviously a very strong third quarter exit rate. And I would assume we can't expect you guys to drive that kind of growth every quarter, but obviously you did run into sometimes when you're going to have to shut in wells from offsetting fracs and such that's going to impact Q4. Can you discuss a little bit about like where Q4 could exit though versus where you exited in 3Q?
Yes. Hi, Scott. It's David. I think that -- I think that we – obviously, we are going to have to shut in a number of the wells that we just had recently completed particularly there in Rustler Breaks for the offset operator fracs. And then of course we're always -- it's our practice to kind of proactively shut in wells as part of our own completion operations.
I think that we may see -- we do think November is going to be particularly low in terms of production as we've noted. I think that things could be down 6000 BOE or so as a result of those shut-ins because those were some very good wells and kind of in the flush part of their production. So we're having to shut them in pretty early on in their life.
I think that we feel like that we can get some of that back in the month of December. But I guess, I feel like that maybe we may exit in December closer to what we averaged in the quarter this past time Scott, but a lot of that will just depend on how quickly we can get these wells back on production and if there is any kind of additional cleanup that's associated with them following the offset fracs.
Got it. Got it. Okay. And then Joe, I think, you had mentioned in your prepared comments talking about understanding the need to bridge that free cash flow gap right now and that there's some opportunities to kind of accelerate that in the coming quarters. Were you just referring to asset sales? Or is it a combination of asset sales organic growth and other initiatives?
Yes, it's all of the above Scott is that we're on a good trajectory as far as the bread and butter of the business, which is operations, E&P and mid-stream. But we're also -- we've been methodical and kind of from time to time we've sold an asset non-core asset in the Eagle Ford or the Haynesville. And we could do that again, they're profitable they get a favored price on oil about $3 more on oil. And of course, gas is a little better. But we would make a deal if we had a strong enough offer.
We've said that and we've had more interest this quarter than some. So we'll just see where that goes. In addition, we're trying to be proactive. It's no secret that we've got a mineral package that not a package that we have minerals that we have leased some. And if -- we're studying the various mineral deals out there. And as we normally do the way Matt likes to say be methodical and measured in each of the things that we do and kind of study it until we feel comfortable that we know the pros and the cons.
So that's not being ignored or put to the side. But we're studying that as we would some other promising prospect to know when and what we want to do with that. And speaking of that is we had a guy in our accounting group do some audits and other follow-up work and has saved us a lot of money, found some errors and that we corrected on that and that's the type of individual effort that we see across the Board of our guys getting out there and saving a little bit here a little bit there on cost and driving the cost down as well as the capital efficiencies that we've been achieving this year and driving down the cost per foot completed well cost and as well as making reductions in G&A. And so it's a deal that every -- everybody here is looking to find ways to get a little better to work with the service companies on finding ways to improve efficiencies there too. I know that's a long-winded answer, but it's on everybody's mind and everybody is trying to do what they can to help.
Okay. Okay. So, it sounds like it's a holistic effort. I mean you guys are just out there picking up every quarter an equivalent time on the ground. Is that right?
That's right. It's comprehensive.
Got it. Thank you.
Thank you, Scott.
And our next question comes from the line of Gabe Daoud with Cowen & Company. Your line is open.
Hey good morning Joe and everyone. I was hoping I guess maybe you could just start with the delivered footage expectations and D&C cost per foot slide in your deck. Just given efficiency gains and as you've highlighted on the Antelope Ridge well -- D&C cost per foot moving lower. Do you think both of those numbers at this point could be a bit conservative? And what type of oil growth you think can be achieved in the Delaware on that delivered footage number?
Hi Gabe, it's David. Well, I think that -- look we've -- as to whether we think it's conservative or not I don't think that we ever intentionally guide to things that are conservative or put numbers out that we think were conservative. That's kind of our best estimate of where we think that we can be. It is encouraging I think to see that the Jeff Hart well did manage to come in a little below $1,000 for foot. So, that was positive.
I will say that when we started out this year that I think the first time we put this slide in the deck, it was showing about -- I want to say about 12% 13% decline for 2019. And we managed to do 20% year-to-date. So, I think everyone will continue to push hard. I'd give great credit to our operating team. Drilling completions have done a great job this year continuing to be more efficient in both parts of that operation. And so I think certainly it's possible that we could improve upon these numbers going forward, but today that's kind of where we see them.
Okay this is Matt. And just to tack on what David said there. You see the slide there that we're projecting that from 2018 to 2020 with the same number of rigs, six rigs that we're going to drill an additional 200,000 foot of completed lateral footage. So, I think it's -- that's a great improvement in efficiency.
And Billy and his team -- and I might ask Billy to speak about this here in a minute, but what they've done in preparation for drilling these longer laterals is impressive. We've gone and worked with Patterson, our selected provider for our drilling rigs. We really enjoy that relationship and they've been able to prepare these rigs for these longer laterals. So, I mean the rigs that we have currently the super-spec rigs that Patterson provides are very capable of drilling these two-mile, two and a half mile laterals. But with Billy and his team adding the third mud pump, the high-torque top drive using high-torque drill pipe, and a number of other things just getting prepared for these longer laterals. I think that's going to be a great efficiency for us.
And when you're talking in terms of service pricing and then how all that works what we really like to do is sit down with the vendor and show them this type of graph and say we're not talking about the same number of wells same number of completions next year that we were talking about this year. We've got improved efficiencies. And so we're able to sit down and work with these guys and figure out a solution for pressure pumping services, for instance, that makes sense for both sides. And we can go and push on these guys and get less and less -- more and more of a pricing discount, but we want to make sure that we're adding value at the same time.
Billy do you want to describe the rigs you had a makeover of these rigs this past year.
Right. We had the super-spec rigs and we started out with those back in the day when it wasn't cool. We really did a good job with those and we move forward. And there is a new equipment that has come available. We've gone ahead and had the third mud pumps and high-torque top drives like Matt mentioned.
And we've got three other rigs outfitted that way already. We'll have a fourth one by the end of next month and a fifth one by the end of January of next year. So, we'll have five of the six upgraded and we're seeing good things there.
Along with that, we're trying out different kinds of motors, stronger, bigger motors with different bids. We had bidden a hole this last week. That was the first time it's been run and working with J. Smith bids [ph] and stand out on the leading edge of those type of things.
And also on the completion side moving from one mile to mile and a half and two- mile laterals. We got out ahead and tested new things standalone snubbing units and found different methods, different tools and kind of experimented with that and we've got those things lined out where they were running really efficiently.
So, when we actually got to start drilling the 2-mile laterals and completing them we were ready to go and we didn't stumble. We just -- all we did was get better. The longer laterals made us even more efficient. So, a lot of work the guys put in ahead of time and it's really paid off for us.
Good job. And we've noticed the difference like on the Jeff Hart that was your -- one of your first ones and you did that in record time.
Yes, sir and very good oil.
That's great. Thanks guys. That's helpful color. And I guess just as a follow-up for me. Just digging a little bit more into the trajectory in 2020. I guess, could we potentially see more of a back-half weighted growth profile given some of the items you mentioned like more shut-ins just getting ready for longer laterals and the longer-cycle times on the two Stateline rigs. So could we see a back-half weighted profile, but overall on a year-over-year basis still kind of get that double-digit oil production growth number?
Yeah. So without providing 2020 guidance, which is I know what you're asking me here Gab and thank you for the attendance. But I was going to say, certainly I think as we have indicated pretty consistently that we're going to be running six rigs next year. And one of those rigs is going to run down in Wolf and Jackson Trust, and one of them is going to run up on the Stebbins property. Two of them are going to run between Antelope Ridge and Rustler Breaks and two of them pending the approval and issuance of our initial permits on the Stateline asset are going to run at the Stateline. And that today hasn't changed. That's still where we project that those rigs will be running.
I think as we've made clear, it will -- when we start drilling those wells on the Stateline, for example, we plan to drill a minimum of two four-well pads to begin with. And so we'll have at least eight wells that are drilling. And from the time we start drilling hopefully in January, until those wells are completed, it's probably going to -- and turn to sales, it's probably going to be late August or early September.
So there's going to be an eight-month period there where those two rigs in 2020 don't contribute to any production. Once they do, it's going to be a very significant event of course we think. And there will be a lot of production that comes from those late in the third quarter and into the fourth quarter.
And so from that alone, I think you would be correct to assume or conclude that our production growth is going to be a bit back-weighted into next year. So -- and we do -- we are optimistic that we will see growth year-over-year. But I think that it is fair to assume just based on the way that the program will unfold next year that you'll see a back-weighted production profile.
Okay. Understood. Thanks a lot, David, Joe and everyone else. Thanks.
Thanks, Gabe.
Thank you. And our next question comes from the line of John Freeman with Raymond James. Your line is open.
Good morning.
Hey, John.
Yeah. Mine was sort of a follow-up to what Gabe was asking. So as you all mentioned in the release as you kind of transition to these -- the longer laterals more of the multi-well pads just sort of the nature of that is it going to be a more kind of lumpy completion cadence?
And given sort of kind of the rig allocation that you'll just sort of kind of outlined, I'm just curious like how much if at all of a factor is sort of trying to avoid sort of the frac hits or kind of having to shut in from time-to-time activity that's kind of happening during 4Q? Or is that just sort of something that you're all just going to have to bake into 2020 guidance and that will just be sort of something that will happen kind of -- I don't want to say regularly but from time-to-time?
Yeah. John, this is David again. First off, I'd say just to be clear, this is something we've baked into production forecast since 2012 in the Eagle Ford. Okay. So this is not something particularly new. I think that we have the operating philosophy and always have, but when we're completing wells that are offsetting currently producing wells that we're going to shut them in.
We do the same thing when we have an offset operator that's completing a well next to one that we have producing. And we do that, because we think that it helps to protect those wells just proactively from any damage that might be incurred from the frac operation itself.
I think we've had good success in doing that. And that's something that we will want to continue to do. I think this particular quarter is one where it was just -- it was just kind of very significant and one reason that we wanted to point it out.
We have five brand-new wells in the Rustler Breaks asset area that were five very strong wells both on the oil and gas side, all of which are now shutting in as we've noted in the release and will be for several weeks now as a result of offset frac operations that are being done by another company.
And so the significance of that being that that was going to be a 6000 BOE a day sort of impact for a few weeks, certainly through the month of November, was something we just thought was worth pointing out.
We did so well production-wise in the third quarter. I mean, really when you look at our third quarter numbers, as a result of just the outstanding well performance of some of the new wells that we brought on and the fact that we completed a few wells ahead of schedule and got them turned on and producing. We substantially beat our internal estimates for where we thought we were going to be in the third quarter.
And frankly we -- in the third quarter be -- where we thought we're going to be by the end of the year. So -- and so when we had to shut these wells in it just resulted frankly our total production is going to be above where we thought it would be at the end of the year. We actually raised our production guidance.
So we've bumped our oil production guidance up a couple of hundred thousand barrels for the year as a result of all the good results that we've seen. It just so happens in this quarter that we've had to just kind of got our number down a little bit due to these offsetting operations.
Going forward, I think that there will always be. not only the times where you have to shut in some wells but just the timing of the operations as we go to longer laterals. They take a little longer to drill and to complete. We're going to be drilling more of these wells on multi-well pads 3s 4s 5s. And as we do that there would just be longer periods of time between when wells get put on.
When we're drilling all 1-mile laterals and drilling them one at a time or two at the time. That was a -- there was a fairly more -- a little bit more I guess ratable completion pace. It will be a little more lumpy as we said going forward. And so that may result in times for a while where we have a little better production quarter and then one that may be flat or down and then much better and then kind of flat. And I think that's something we've been signaling for a while.
I think it's going to happen. And it's something that we'll continue to keep everybody informed of as we go forward. I think it's a good thing by the way. So because of the fact that I think that these wells are going to perform well they're going to be more capital efficient. And they're going to have much higher returns.
And so I can't think of anything negative about it at all. And I think really just may be one of those times where you kind of got to look at things on six months to six months, the quarter-to-quarter things may be a little lumpy, six months to six months, it's all going to be good. But I'll tell you I'll take production being a little down in one quarter, if we can have wells that are generating much better returns and much better payouts. And I'm -- I think we're all for that.
Absolutely. Yes.
Yes, John I just wanted to add to what David was saying there. I mean there's really three different ways that we address these offset fracs. And number one are the wells that we operate which is part of the holistic plan to make sure our drill schedule minimizes the number of offset frac hits we have and how things are spaced out and all that.
So we're pretty much in total control of that. And like David said the non-op stuff, we have insight into when those wells are going to be drilled and when they may or may not be completed in some instances. And this quarter is one of those instances, where none of our partners have elected to complete these wells sooner than what we had anticipated they would which is a good thing, because we'll also participate in that.
And then the third bucket is the stuff that we don't operate that we don't have a non-op position in. And I think the completion production, the drilling team even as Joe mentioned Jason Thibodeaux, the field guys have done a fantastic job of making sure that we're communicating with other operators to understand their completion schedules as much as we can. But like David said, sometimes it just ends up being lumpy.
Yes, I appreciate that. And then just the follow-up for me. Obviously, really strong results on those initial 2-mile laterals at Antelope Ridge. And when I look at the cost per foot being below $1000 per foot, which is actually already better than what you all are kind of guiding to for 2020. Is there anything you can -- when you look at those wells, anything you can identify that says, okay, well this or that did a lot better than we were expecting and that's why the costs were even better than we were expecting in 2020 on a per foot basis?
Yes, sure, John. There's lots of things that can happen while you're drilling a well. And the operations team did a really fantastic job on those wells and you see the results there. The Bone Spring wells are a little different costs than the Wolfcamp wells, you're deeper and have a little different pressure environment. So that's going to factor in.
But I think as we go forward again, like we mentioned before, I think the operations team has done a nice job of getting these rigs prepared. And I think, they're doing lots of planning. Billy mentioned, yet another bit record. So those things are going to continue on.
When you get to the completions, you start completing these longer laterals. You can do it with coal, you can do it with standalone snubbing units, you can do it with rig-assist snubbing unit. So the completion team has done a really nice job of getting prepared and finding cost effective ways to go in and make those things happen. So we're off to a great start. It's going to be something that will evolve over time.
John, this is Joe. One other thing that factors into it. I think we've taken these through our MAXCOM room where they're going 24/7. One factor that seems to make a difference since the advent of that room, we've been able to stay in zone more often on our horizontal leg. And when you do that means you're fracing the right rock. And within that zone, you generally have a preferred zone, smaller 20-foot, some like a 25-foot. And if you're able to stay in that, your wells are going to turn out even better.
And on wells like a Jeff Hart, they did such a good job steering those through that time to MAXCOM room working with the drilling rigs that we were in 100% zone, we consider ourselves 100% of the preferred zone. So the more that we can stay in zone, we'll add to those reserves and then continue to improve the results along with what Matt was talking about. And you've got several of these little things like this.
Jason and his crew, as they’re monitoring these wells and putting them on, they’ve learned something about production out there every time they complete a well and put it online. Each one is different. And they give them a lot of individual attention. And I think that pays off as well. And the Jeff Hart, as you know produced 70,000 barrels in the first 30 days and has continued to hang in there very well. So, very pleased with these better than expected results. We want to keep doing the same things. We'll keep looking for other ways to improve too.
Thanks, guys. I appreciate it. Well done.
Thank you.
Thanks John.
And our next question is from the line of Neal Dingmann with SunTrust. Your line is open.
Joe team, my question is really about the efficiencies. Obviously you continue just -- it seems like improve every quarter. And my question would be if you see these efficiencies continue to improve to such a point would this allow you to -- when you think about it potentially even drop another rig and would that still give you the growth you desire? Maybe if you could talk about the efficiencies and sort of your targeted growth if you could?
Yeah. Neil, I look at these things as these are not single variable deals. You got to look at if you outspend, it isn't just the amount you outspend, it's what you get for the outspend. And if we continue to get more than we expected from outspend, that's a good thing. Although, we're not trying to be the spindrift, it's just -- it's a calculated deal is this worth the additional expense or additional risk and will it pay off?
And so far that answer has been yes. And the same thing on these efficiencies, it's conceivable. We could enter into a time period where we could go to five rigs not that we're seeking to do that, but we look at that what are we getting? And if our opportunity set wasn't so strong as it is, maybe we'll do that. But we're -- we've got tremendous opportunities here in front of us.
Everybody knows what Rustler Breaks is doing and the incentives we have there with our San Mateo joint venture with Five Point. And then you look at Stebbins. Stebbins came in delivering a very strong noted confidence that that's going to be -- that's going to be an area of great interest to us going forward. They've delivered some good results there.
You go over to Arrowhead Ranger. The Verna Rae well is another well, that's performed very strongly for us. And we want to do more there than Antelope Ridge, not to mention Rodney Robinson and Stateline that we think are going to be two of our best areas. And yet, we've had good results down there in Loving County.
So all the areas are coming up and looking really good. And in that regard, I would just mention this notion about Senator Warren. I don't think she can do all the things. I think if she says that she can do eliminate fracking. I don't think it would be wise. We have a saying around here let's reserve the right to get smarter. I hope she excises that right and gets in there and sees the effect that going after tech finance and the energy areas three of our strongest businesses in this country that that would not be wise to do.
But if she does, I don't think it's one thing not to lease federal lands, but another to ban fracking from leases already granted and already producing almost all of our wells. By the time the election is over all it going to be producing in that HBP status, which I think will be treated different. But even if not, we still have thousands of other locations out there in the Permian to do.
We've always adapted. We think we have a great oil-finding team. We've made the right decision. We found gas in the Haynesville. We were one of the first to drill the Haynesville wells. We were early on into the Eagle Ford and we were early on back out here to the Permian. So I've got great confidence that whatever opportunities come our way that we're going to make the most of them. And I think there's a lot of rhetoric. But as time goes along the reality sets in that this wouldn't be good to hurt thriving industries. And I think she will have to modify her approach if she seeks to be elected.
I just want to underscore what Joe is saying there about the pace, the six-rig pace and dropping to five. Number one if we wanted to drop to five we could. We have the optionality to do that. But I think one important thing to think about when we're talking about pace and the plan that we've put together and the plan that we're executing on is how the Midstream and the E&P businesses work together for the -- and I'll put my Midstream head on for the Midstream team to be successful. What they're really looking for is an anchor tenant that's going to provide volumes. And so they've got that with Matador and the economics work for the Midstream business based on that alone.
But in addition when I put my Matador head-on when I'm being incentivized to drill these wells to drill them even faster, it's a very nice way to build up both of these business lines together at the same time because they absolutely do feed off one another and also allows the San Mateo team to go out and secure additional third parties, which is just gravy on top of the Matador volumes.
And Matt if I do one follow-up. Just -- you guys have already talked a lot around this. I'm just wondering any additional color around the potential completion design around that Jeff Hart state. Obviously the well was very prolific well. What I'm wondering was there some different things here that you did on the completion design? Or was it just that you could apply to future wells? Or this is more simply what you all have been talking about the longer laterals. I just didn't know if there's anything else that -- in that design that was out there.
Nothing specifically unique to that design Neal. I will say that what Joe was saying earlier about the MAXCOM, I mean to be able to drill these long laterals and stay 100% in zone is very, very helpful. And then to be able to come back in and continue to tweak the knobs you've seen in our investor deck, we talked about -- to you about the fluid volumes and the profit volumes that were kind of settled in on and how we're using diverting agents and doing different things in particular the low-temp diverting agents have been good for us. We've been out in front of that and making those things happen.
But when it comes right down to it it's just pretty much simple execution. You get these wells drilled under expected time the completion team comes in and they're able to do more stages per day. All those things just drive those efficiency costs down.
Great. And Joe hope you can talk some sense into Warren? Thanks.
Thank you Neal, but you're giving me skills I don't have. And it's -- I don't have any political skills. I just have worked out in New Mexico for 40 years many people have raised the question out there about shutting down the oil and gas. And they're part of the country that needs the industry. And they've been very sensible in what they've asked of operators. And there's a good working relationship. And I would hope that she would pay attention to people from her party who are out there that want to continue to see their state economy thrive. I think it's an amazing number that -- of amount of taxes and monies paid in by the industry into the state I think it's a third pay-in. Is that?
Joe, that's about right. And that's just in lease bonuses and royalties and that sort of thing, but not really including all the jobs that it brings into the state, the additional spending that comes from that tax revenue that comes from that as well.
Yeah. I mean the most jobs have been created in our industry of late. And in addition to the Senator Warren has this plan about paying 2%. Well, all ad valorem is about 2%. So we're already in that 2% category paying down and creating jobs where -- in an area where there wouldn't be jobs. So I think we should all work together and find solutions that are bipartisan is my real point. And I think in the long run that I think our candidates will do that. I think that's what we all want let's keep good government and a fair system.
Great. Thanks guys.
Thank you. And our next question is from Asit Sen with Bank of America. Your line is open.
Thanks. Good morning, everyone. I have two quick questions. Thanks for all the details on drilling efficiency gains. But Dave I was wondering, if you could update us on your base decline rate and expectations into 2020.
Well, I think as we've answered that question in the past I said, I think for 2019 the base decline was 38%, 40% and -- for the company as a whole. And I would hope that that would continue to shallow as we become a more mature organization. And also I do think that as we drill more of the longer laterals, I think that -- our observation has been that those wells tend to exhibit a bit shallower declines early. And so as a result I'm hopeful that that will also contribute to the improvement in the base decline rate going forward.
Okay. Great. And my second question was on San Mateo EBITDA was higher than expected. So to what extent was this driven by the Gulf Coast Express coming online? And Dave how do we think about differentials to trend going forward?
So first of all the San Mateo adjusted EBITDA didn't have anything to do with the transition to Gulf Coast Express. So, what it had to do with was excellent execution on the part of our midstream business really all year long, but particularly in the third quarter and the continued addition of third-party volumes to the system. So I think that San Mateo has hit on all cylinders and probably been some this year. I don't know if you picked up in the release but in case you didn't I want to reiterate the fact that the plant at various times in the third quarter the 260 million a day of processing capacity that we have was around 95% full.
I mean -- so we have been contractually full for some time. but we were full-full from the standpoint of actual gas that was being run through that system and process. So, it was an excellent quarter for San Mateo. And we were really pleased with those numbers but had nothing to do with Gulf Coast Express. What Gulf Coast Express we think will do for us going forward is that -- is improve our natural gas price realizations on the residue gas that comes out of the back of that plant and other places in the Delaware Basin. But after we've done the processing, we have then the residue gas and that's what is going to be transported to the Gulf Coast now large volumes of that in the Gulf Coast Express Pipeline.
And because the pricing there is based upon Houston Ship Channel pricing as opposed to Waha, we would expect an improvement in the kind of overall realization that we receive for our natural gas prices going forward. And again I give a lot of credit to our marketing team there. That decision was one that we made about 18 months ago when we could sort of see some of the issues with transportation of natural gas in the Delaware Basin knew that we wanted an outlet to the Gulf Coast and signed up for a lot more volume than we had at the time anticipating that by the time this day came and the pipeline was ready that we would need it. And so we made that decision. We made that call. We signed up. We're thrilled we have it and glad to see that that pipeline came in service a few days before we anticipated. And now that we have a significant quantity of our natural gas from the Delaware going to the Gulf Coast via the Gulf Coast Express Pipeline.
Great, very helpful. Thanks for the details there.
Yes sir.
And our next question is from the line of Sameer Panjwani with Tudor Pickering Holt. Your line is open.
Hey guys, good morning. So wanted to touch on an earlier question on the D&C front. So you already installed 1000 foot on some of the pads that you're drilling that you just drilled in the third quarter. I think these are smaller on average from a pad size on what's planned for 2020. I would assume you continue to get better from here but the early outlook has costs going back up to call it $1075. So can you just help bridge the gap there?
Well, first of all Sameer, good morning, this is David. I think that Matt alluded to some of the answer in one of the previous comments that he made. The Jeff Hart well, the Third Bone Spring that we called out in the release is a Third Bone Spring well. So it's a shallower well. We will continue to drill a lot of Wolfcamp A wells and Wolfcamp B wells that are going to be deeper and higher pressure and that will require for casing strings. And they're just going to be a little more expensive to drill and complete.
I think with regard to the wells that are -- the two-mile laterals in the Second Bone Spring and the First Bone Spring and the Third Bone Spring and the occasional Avalon or Brushy Canyon that we may do next year, the shallower zones you'll probably see that the D&C cost per foot there may be at the low end. But I think when you kind of put it all together and it becomes an average number, the average number will -- we still think right now will be in that 1,000 to 1,100/foot. I think the graph we have projected is kind of right in the middle of that $1050 or $1070 something like that. But I think that's why. It's just because it's just not all one kind of well. There are some that are deeper that will cost a little more. There are some that are shallower that will cost a little less. And given the weighted average of all that, that's where it comes out.
Okay. Okay. That's helpful. And then there was also some commentary on the trajectory of production in 2020. It seems to me that the implication here is that while we'll see the benefits on cost next year, the overall capital efficiency uplift on both cost and production will be more of a 2021 event which means 2020 should be more of a transition year and maybe not a good, I guess benchmark for go-forward capital efficiency. Am I thinking about that correctly?
Well I guess Sameer, when I think about capital efficiency I think of it in terms of the dollars per foot, I mean the -- are we able to deliver more completed lateral feet for the same amount of money? And I think that you clearly will see – you’ll clearly see that.
Again I think your comment is correct. And it's something we've talked about for a while is that, it's just the nature of our business. You have to get a well in the ground before you start seeing any production come out of it, right? And so usually the capital efficiency associated with the drilling and completion happens before you begin to see the production and the return come from that well.
So there will be a little bit of a delay. So I think that 2020 you will definitely see continued improvement in capital efficiency, but you'll really start to see the production impact of that as we get to the latter parts of 2020 and into 2021.
I think that we could certainly see the production impact really be very positive beginning in early 2021. I mean, if you just think for a moment if the first 8 wells we drilled at Stateline for example, let's just talk about it if they come on in -- right about the end of August or the 1st of September, the next batch of 8 is probably going to come on right at the end of the year or probably early in 2021.
So you're going to have 8 wells that are still in pretty much the early stages and kind of flush stages in their production and 8 more that are then in the very initial flush stages in their production.
And so when you kind of think of how that's all going to unwind, I think that's probably what you're referring to is the fact that, the production impact will come a little later but that's to be expected. But I think we'll see the capital efficiency impact of it all year long next year.
Okay. Yes. That makes sense. And then finally I think...
Sameer this is Joe. I just think of it you've been building 1-story buildings for a long time and you're shifting to building 3 or 4-story buildings. Well that doesn't mean you're having a bad year. You've got more demand and you've got more technical expertise. You've got more of everything.
It just affects the near-term – the near term effect that you can't rent it out because you're building a bigger building. But as soon as you get the first one or two done then the capital efficiency shows up, your revenues are up there and you're all the better. That's just the natural part of growth and progress. And we're not going to have a bad year. It's still going to be better than what it was. It's just is the reality.
We're calling it to your attention that we're going to work hard. It's going to be a better year, but it all -- it isn't going to happen within an 8 level quarter. It may transition over a quarter or as David's pointed out to the back half of the year.
But Matador is still getting better. And it has better assets when it drills these wells even though they're not yet online, but you can count that that has more reserves, ready to go and it's just a matter of 90 days or something, often for these wells. So the asset is there.
Just like behind every share of Matador and each share represents more than 1 barrel of oil 7 Mcf of gas, your midstream business you get for free; your minerals, your acreage all of that. It doesn't mean, it isn't there. It's just waiting to come on line as we proceed in a very orderly, methodical way as Matt like to say profitable growth at a measured pace and that's what -- this is happening.
To get to the rate of change story and the capital efficiency yes you have to wait a few days, a month or two or three or whatever, but it's coming. And once the well is drilled, the asset is there. And it's better to wait a month or two to get twice the asset that you would get with a 1-mile lateral. We think that's good business.
Right. And thanks for that color Joe. It's really, really helpful. If I can just squeeze one more question in my time. I think we're all on the same page of the merits of a frac ban, but it definitely seems like the market is already starting to price it in to some degree.
So if we assume a frac ban on federal lands goes into effect and you've kind of provided some context around your acreage exposure, but can you talk through your optionality to work around this maybe from a permitting standpoint or in terms of how many years of inventory you'd have available excluding federal leases?
Well Sameer we've got several thousand locations that we could drill if there's a frac ban. But before the frac ban goes into effect, I think you've had years of litigation with your major companies Exxon, Chevron, Conoco. You go on and on down that line that they've got so much invested out here. They're going to probably lead the way in objecting, because you'd have a taking of property by that ban and there'd be due process concerns. So I don't -- that's why I think on unleased federal lands, she may be able to do more.
But before she tackles where you've already been granted to lease and it's already spent money in production then she's having to look and pay for the monies that people have been out as she's trying to change the rules and while the horse is in Midstream. I just -- that just doesn't seem practical. And for her activities what she wants to go to she's got to find a way to pay for it. And this has been a big source of revenue. So I just don't see her -- the last thing she's going to go after are those leases with wells that are producing.
And Sameer, maybe just to add one just small comment to what Joe said. I certainly agree with what he said there. And just to add to that, we do have many, many locations that are on fee and state lands not on federal lands so that we will be able to pivot to and just reorganize our schedule, reorganize our program if that were to happen with this ban on federal lands. I think that if we've done anything over our time as a public company, we have -- and as a private company for that matter I think Matador has always demonstrated that it's a pretty resilient organization and that we've got a lot of smart people and that we're able to understand and meet the challenges that come our way. And I think that everybody in this room today feels the same way. And so while I don't think we expect to be faced with that challenge, if we're, we will have planned ahead for it and we'll be ready to meet it head on. And so we'll cross that bridge when we come to it if we should ever.
One thing I would add to David's statement, one commentator pointed out, if that were to happen there's a ban on fracking, you'd see oil prices go to $100 or $150 a barrel in my belief. And if so there'd be no problem anymore about our outspend.
As a matter of fact I think one of those commentators was Sameer. So if I recall correctly right Sameer?
Yes. You're correct.
Thank you for that.
Thank for bringing this up. But yes, we'd suddenly have no outspend problem. All those locations on fee and state land become that much more valuable. And you should have -- before it could go into effect they've already drilled and completed according to our plan. We're going to have a lot of this developed prior to the election. So I think we're in pretty good shape. We're going to be more wary. And as I said, we'll have a plan to adapt if that's a change in the circumstances. And the most important thing again is we have our team here that's found the best wells the core of the core in the Haynesville, the core of the core in the Eagle Ford and out here in the Delaware. So let's give them some regard that they can go find the next best area.
Great. Thanks guys.
Thank you.
Thank you.
Thank you. And our next question is from Irene Haas with Imperial Capital. Your line is open.
Yes. Very quickly. Just taking a look at all the demand that's going on for San Mateo the fact that you have really high capacity utilization, what's in the works for San Mateo next year? Would it be kind of similar spending as it is current year? That's all I have.
Yes. Irene, this is Matt. And I think we've been messaging that the CapEx will be about the same for next year. In regards to San Mateo II as we've talked about before we're adding another 200 million cubic feet a day at the plant there -- in our Rustler Breaks area the Black River plant. We're also adding gathering systems for oil water and gas at the Stateline area and at the Stebbins area and building a gas trunk line to get back to the gas plant there in Rustler Breaks. So all that is currently now is on time and on budget. So we should have that plant operational sometime in the summer next year and we'll be building the gathering facilities to go along with it. So that's kind of the plan. That being said, we're going to remain open to different opportunities. As something really good comes up from a San Mateo perspective, we will take a look at that too. But right now we don't have anything in the works.
Great. Thanks.
Thanks, Irene.
Thanks, Irene.
And our next question is from Mike Scialla with Stifel. Your line is open.
Yeah. Good morning, guys. I know this is something you've addressed in the past...
Pardon me, Mr. Scialla, your line is coming through very jumbled.
Either that or Mike has a really bad cold this morning. I'm not sure which it was there.
Can you hear me now?
Yes. Thanks.
Sorry about that. And I don’t think I have a cold.
You sound much healthier there.
Maybe we'll go get that checked out after the call. Joe, I know you've addressed this in the past, but some investors would like to see mid-cap E&P companies merge. I just want to get your latest thoughts on M&A or the possibility of a drillco.
Well, we've always said, we play a straight game. We sold first Matador, we sold part of our Haynesville position to Chesapeake. We made a deal with EnLink on one of our early midstream projects. We've made a deal with a JV with Five Point. And so, we think we play a very straight game. So anytime we get a serious offer, we'll give it serious consideration.
What again, I found most often, that people when they look at things, particularly from companies they tend to look at things too narrowly. And you've got to also look at, okay, if an offer comes in, it doesn't just affect that price then. But as Matt spent some time pointing out, that between midstream and E&P, one hand washes the other.
Our E&P helps provide an anchor tenant, reduces the risk for the midstream. And the midstream, by being there to hook up just when you are, has a lot of operational advantages. We're not flary. And when we hook up, we're almost all on pipe now. So we've taken thousands of trucks off the highway that really helps our ESG program, plus it reduces the cost of water disposal. So you've got to look at both sides of that. And no one yet has come in and made such a strong offer that has really ratcheted our attention.
They come in and most of the time they want to just pay some amount, that's maybe good for somebody who's a financial partner that only has money in it, but where we have enhanced operations there needs to be something taken into account there and also to offer terms that assure us that we won't have a decline in the quality of the services.
So they just hadn't -- that hadn't happened, but we play a straight game. And in our other assets, we know we're a public company, but we know the value of the operational advantages in a way that most investors on the street would find it hard to know and understand how helpful it is to have people right there when you're ready to turn it on, taking your gas or during the winter, have you on pipeline or when there are gas problems, the help that it's been in marketing that we probably have more options than somebody that just sells this gas and that's the end of it.
I think those are the people that suffered most at law. And so, it hadn't been a hard choice at all, the advantage of keeping the asset and growing it, when it's growing at the rate that it is. And we think in a couple of years it could be two to three time what it is now.
Giving up that opportunity for a little short-term payout, it hadn't even been a close call yet on what we should do. But we fully want to get the most value of it. And it's discussed at every Board meeting and it's discussed internally, at least weekly two or three times.
Thanks for that. And…
Does that make sense to you, Mike?
Yes, it does, Joe. I want to see, given that you're -- it sounds like you're near capacity or were at times at San Mateo, is there any potential to be constrained there before the next plant comes online? And if so, what would be the alternative? Would you fire gas for a short period? Or what are your thoughts about that?
Yes, Mike. This is Matt Spicer. That's a really good question. If you look at our contracts on our gas side where we've had a lot of success, we have some interruptible volumes on that system as well, which is allowing us to fill up the plant at 95%. So as Matador or other firm customers come on with more gas, we don't see constraints. We just move aside the interruptible gas that's on the system.
Very good. Thank you.
Thank you, Mike.
And our next question comes from the line of Richard Tullis with Capital One Securities. Your line is open.
Hey, thanks. Good morning, everyone. I stepped away for a moment. Hopefully, you didn't touch on these two topics. But Joe, real quick, as far as 2020 goes, I know the budget hasn't been released yet.
But at a high level, with the recent efficiency gains and likely more to come as you move into longer lateral development next year, what could the spending gap look like next year at say $55 oil and current, nat gas and NGL pricing.
Well, Richard, I don't know whether you heard it. David thanked somebody for trying to get to the 2020 numbers.
I'll play like, I didn't hear it.
That the first thing that I would tell you, we think, the spending gap is narrowing steadily. And we're looking, not only for the narrowing that's occurring naturally as we have these better and better quarters, but also we know we have some good cards to play.
We set out the first of the year, making two of our priorities, doing the midstream deal which we did, which narrows that, because they're drilling incentives in that. And then the second thing was the BLM, which gave us the rate of change, the capital efficiency story.
Now that we're proving those up and we're making the kind of wells that we are with these longer laterals that was the thing we wanted to prove. And that now leaves us more flexibility to deal -- one of the other cards that we have, either -- we've made some small -- not small, but $1 million that's a lot to me.
I started with $270,000. So anything over $1 million is still a lot of money to me. But we've made a number of sales. And we've leased minerals. We've recovered judgments. We've recovered on audits. The scrappiness has recovered a lot of money.
We're continuing to do that. We're very pleased with those efforts. And we're pleased with the quality of the offers that we're now beginning to see or other non-core assets and the -- of the non-core assets. So all that is happening and you're seeing the results of this.
Okay. For example, we kept in the Haynesville, the LA Wildlife wells. They're making 40 million a day a piece or more. Chesapeake has said those are the best Haynesville, wells that they've drilled. We have 49% roughly half of that.
Well that's one reason why our gas went over the edge. Well you would have hated to sell that for, cents on the dollar. That just shows the deliberate method. So we have 240 million a day wells, that's a great outcome.
Chesapeake did a great job on that. We've enjoyed continuing to work with them. And that's an example why you want to be deliberate, in these sales. So I think, Van, and company and Craig have done a terrific job.
And -- but we'll probably expand the efforts there. I don't know what kind of results we'll get. But expand the effort. Because now, we know more what we have in New Mexico, and in Loving County and our other areas.
So, if you like kind of the way we did it, over the last two years, where we've collected drilling fees and sold some properties. That's amounted to tens of millions of dollars. And I think, in aggregate, probably well over $100 million.
And I think, those efforts will be stepped up. Because now we have a lot more certainty on the assets, we expect to retain.
Thank you, Joe. And my last question is related to E&P asset sales. I know you just touched on that. Basically do you think you could be out of the Haynesville and Eagle Ford totally by say, year-end 2020?
Well we always could. Yeah. If you want to sell it, just accept the offer you get. And if you really, really want to sell it, tell me you'll accept less.
My understanding is…
You know that. And I'm not trying to be facetious, Richard. It's just saying is that we've tried to be clear on all these sales. We've sold to a number of well-known names that you would recognize here and there.
It's that we've always made it clear, is come in with a strong offer. But don't try to come in with a tire kicker. And expect to get a response. Chesapeake did that, they came in strong offer. We made a deal.
We've made other deals with them since then. And we I think, worked well with other buyers, in other areas. Matt, you look like you're ready to say something.
I was just thinking, with the Haynesville Richard, I mean, that's a very low-cost operation for us. I mean, those wells are -- they're great wells. And Joe's talking about these two 40 million a day. That's a lot of volumes.
And they're very, very efficient to operate. And in terms of the Eagle Ford, that's still a great asset for us. I mean, we've got production there. We have a number of undeveloped locations.
So everything that we did, as an operated company in the Eagle Ford was in the lower Eagle Ford. We didn't do anything and after we've done some Austin Chalk testing, which has turned out really well for us. So there's lots of opportunities still in both those assets. So, to Joe's point, we don't want to just to have a fire sale and get rid of them. We still think there's a ton of value there.
Thanks, Matt. I understand. I appreciate the comments. Thanks as well Joe.
Well, thank you Richard. And the last thing is we boosted our production. Now, if you sell some in the Eagle Ford it didn't quite have the effect. These two 40 million a day wells they get that preferred pricing up there in North Louisiana and the Eagle Ford got preferred pricing. So it was a big help last summer, when Waha prices got low, before the Gulf Coast went online. Now, the Gulf Coast is online we're not so sensitive to prices anymore. So looking at it holistically, we're probably more ready today than we were. But we like our properties they're cash flowing well and we see more potential there. But we'll always try to play a straight game.
Thank you, Joe.
Thank you, Richard.
Thank you. And our next question is from Jeff Grampp with Northland Capital. Your line is open.
Good morning, guys. Thanks for getting me in.
Hi, Jeff.
Just a quick one on the San Mateo side. It looks like you guys took a little bit more money into the corporate side with a credit facility. So just kind of wondering strategically, how you guys think about utilizing that or what the appropriate leverage is for San Mateo. It looks like it's at about maybe 2.5 times on a run rate EBITDA basis. I mean, is that kind of where you guys would like to keep it? So as that ramps-up maybe you guys could put some more money on the San Mateo credit facility and pull some money back into the corporate entity? Or just kind of wondering, how you guys strategically think about that?
Thank you, Jeff. It's David. Well, I think that we're just – we just started looking at it is sort of what's a good way to finance that business. I think it's pretty well understood that folks are a little – they're generally more comfortable with a little more leverage on the midstream businesses. So I think you're right, I think we're currently at around 2.5. And I don't think that we would be uncomfortable with the leverage on San Mateo, and nor would our banks going to a higher level. I think we have about a five times debt-to-EBITDA covenant in the bank group. So there would still be room to move there. But it's not something that we'll probably do with great aggression. I think we'll just be very measured in terms of our use of leverage in San Mateo like we have been in Matador.
All right. Thanks for time guys.
Thanks, Jeff.
Thanks, Jeff.
Thank you. And our final question comes from the line of Scott Hanold with RBC Capital Markets. Your line is open.
Hey, guys. Just one quick follow-up and I don't want to get into too much in the frac ban debate. But when you look at the Stateline those are obviously going to be some pretty prolific wells and important for you guys to get online. Can you just give us a quick update on where you're at in getting those permits on those? And is there any way to accelerate that? So, effectively can you get the majority of the wells you want to drill in any way prior to in theory something that could occur?
Yeah. Scott, it's David again. Look, we're very pleased with the progress that we see in the Stateline permits. So, I think we're still very optimistic that, we'll have the first batch of those permits sometime this fall. And that when we receive them then we'll move ahead with our plans to move a couple of rigs down there and get started. As we said in the release that we put out on our federal acreage exposure, we have – we currently have 88 permits submitted for that particular asset and they are in various stages of the review and approval process.
We're very thankful and appreciative of the BLM staff there in Carlsbad who continue to work very diligently not only on our permits but permits throughout the industry. We think they're doing a great job. We really appreciate how we've worked with them. I give a lot of credit to our own internal land team and those that have been specifically focused on working on the permitting process for us. They've done a great job. And these permits are involved processes. They're -- it's a fairly significant amount of information that's required to be submitted. And our teams have pulled all that together and have all those pending in front of the BLM.
So, I think our expectation is we'll get an initial batch and then those will just continue to come at a fairly regular pace throughout next year and certainly plenty of time to enable us to continue to prosecute our development at the Stateline at the pace that we plan to and perhaps even give us the opportunity to accelerate that should we decide that's the right thing to do. So, very, very, very optimistic, very satisfied with the progress that we're making there.
Appreciate the color. Thank you.
Thank you. And that does conclude the Q&A portion of this morning's conference call. I'd like to turn the call over to management for closing remarks.
I'd just like to simply close by again mentioning Stebbins is becoming an increased interest area. We've had good results of our initial wells up there. That's also tied into San Mateo II and that will be a big part of that deal.
The second thing I just want to thank again the staff for the wonderful job that they've done. And the third thing is just to mention that we think we have a lot of ways to pivot. That's got to be one of our strengths is the ability and we have pivoted from we were all in the Haynesville.
If you remember, Chesapeake came along it made us a proverbial offer we couldn't refuse. So, we did that deal with them did the JV and pivoted to the Eagle Ford which was an oil province to prove up that the frac jobs could go to the narrower pore throats of the -- the larger oil molecules could go through the smaller pore throats of the shale prove that up. And we started building the position in the Delaware. And we did that when we were going public.
And we advised everybody that looked at us then that that would be our third leg of the stool. And it -- rest well enough that it's a big part but we could pivot back to either the Haynesville or the Eagle Ford if necessary. I don't think we'll need to. We've got plenty of locations. But we have built in that kind of flexibility.
Same thing on our rigs. We could drop one. They are on short-term -- relatively short-term contracts. Don't want to do that. We've got a great relationship with Patterson. They've worked with us and Halliburton and everybody else. So, we think the business has a lot of opportunities going forward.
I do want people to feel comfortable that we do what we say we're going to do. So, when we merely point out that you have the natural effect of going with the capital efficiency is you're going to be drilling more laterals, longer laterals, more pads that you've got some of that built in. That's the -- you've got to make that -- accept that challenge when you're going to do that, but it's going to pay off in a big way for us.
And so we like our chances in all of these areas. And that if you will -- and we're addressing all the concerns that I've heard today. We are addressing each of those. And on the plus side we're continuing ahead with the plus side. And as good as some -- most of those -- as good as those results are, they're going to get even better going forward.
And so thank you to the staff. Thank you to the shareholders. We know you have a choice. We hope you'll keep picking Matador and I think you'll be really glad that you did.
Ladies and gentlemen, thank you for your participation today. This concludes the program.