Matador Resources Co (MTDR) 2017 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the fourth quarter and full year 2017 Matador Resources Company earnings conference call. My name is Sondra, and I will 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 March 30, 2018, 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. Schmitz, you may proceed.

Thank you, Sondra. Good morning, everyone, and thank you for joining us for Matador's fourth quarter and full year 2017 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 the 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 recent annual report on Form 10-K.

Finally, this morning, in addition to our earnings press released issued yesterday, I would like to remind everyone that you can find a short slide presentation summarizing the highlights of our fourth quarter and full year 2017 earnings release on our website on the Presentation & Webcasts page under the Investors tab.

And with that, I would now like to turn the call over to Mr. Joe Foran, our Chairman and CEO. Joe?

Thank you, Mac, and good morning to everyone on the line, and thank you for participating in today's call. We appreciate your time and interest in Matador very much.

Now I would like to introduce the senior members of our operating staff who are joining me this morning and who are standing by for any questions you may have. They are:

Matt Hairford, President

David Lancaster, Executive Vice President and Chief Financial Officer

Craig Adams, Executive Vice President, Land, Legal and Administration

Van Singleton, Executive Vice President of Land

Billy Goodwin, [Executive] (corrected by company after the call) Vice President of Operations

Brad Robinson, Senior Vice President of Reservoir Engineering and Chief Technology Officer

Gregg Krug, Senior Vice President, Marketing and Midstream

Rob Macalik, Senior Vice President and Chief Accounting Officer

Matt Spicer, Vice President and General Manager of Midstream

Kathy Wayne, Vice President, Controller and Treasurer

Brian Willey, Vice President and Co-General Counsel

Bryan Erman, Vice President and Co-General Counsel

Ned Frost, Vice President of Geoscience

Tom Elsener, Vice President, Engineering & Asset Manager

Jim Basich, Vice President and Managing Director, IT

I am proud to announce 2017 was the best year ever, and the fourth quarter of 2017 was the best quarter that we had ever had, and that we -- our outlook for next year, 2018, is the best outlook that we have ever had.

Now I want to take a moment and, first, to personally acknowledge the Matador staff here in the office in Dallas, in Roswell, and our people in the field for their record-setting achievements during the year and setting us up for 2018.

Now I would like to take on a few key points before taking your questions. The elephant in the room that I can tell by the comments is the concern over our proposed outspend this year. I would like to address it, because it's a very fair question, and it's a question that we meet and discuss on a regular basis. And in our approach, we think not just about what the outspend is, but what you get for it, and to be sure that you're getting something of value that adds to the overall value of Matador.

And let's look for a little bit -- this same sort of outspend question was raised last year at this time, and let's look for a moment what our expenditures got you. You have a 44% increase in total proved reserves, 52% [increase in] (corrected by company after the call) oil, and now oil is now 57% of total reserves, and so our reserves grew from a little over 100 million BOE to [153 million] (corrected by company after the call) BOE, and the oil cut moved from 50% to 55% on production. Gas grew by 35%.

Now on production, our oil production grew 54%, gas 25%, for an overall increase in production of 40%. And then in the Delaware, I think it's significant to note how much -- where we spent the bulk of our money on our drilling and completion activities. The Delaware oil production grew 73% and gas 106%, so out there you had overall growth of 84%, which I think we all agree are very strong numbers.

EBITDA doubled, from $159 million in 2016 to $336 million for 2017, and I submit to you that when you -- that was the drilling and completion part of our capital spend. Acreage -- we increased acreage, 25,100 acres net at an average -- weighted average cost of about $8,000. And we spent a total of approximately $257 million, and when you back out the little bit of production that went with it, you'll get right about $200 million, divide by $8,000, is pretty -- I mean, divide by 25,000 acres, and you get $8,000, so we're very pleased with that.

Our Land group came in and was very wise about its expenditures. Most of those expenditures on land were from increasing our interest in our existing units and in our core areas, so this is a very select purchase, well below the going price, but we have a program where we're constantly making offers and we're nibbling away with 100 acres here and 500 acres there and averaging about 1,500 acres a month. Last year was really good, because we drilled wells, we added acreage or in the adjoining areas, but if we had not taken advantage of that, someone else would've gotten that acreage and you wouldn't have that chance again.

The third area that really worked well for us, I believe, with the capital expenditures was in the Midstream. We did a couple of Midstream deals, as everybody may remember, at the first of last year. We did a deal with Five Point for $171.5 million in cash at that time, with additional monies to be received for performance, and we received -- we'll be receiving in the next few days the performance bonus for 2017. In addition, we added three saltwater disposal wells and did the deal with Plains.

Now let me just kind of take up a little bit the importance of some of this. If you looked at our Midstream business a year ago, you would've had -- we were into gas processing. Now we're not only in gas processing, about ready to add 200 million more in the latter part of this quarter, a day of processing, but we also have oil gathering and saltwater disposal gathering, which we've not had prior to now. So next year at this time, in 2019, you'll begin to see the contributions from those two additional areas.

And on the Plains deal, that is a win-win deal for each of us. Plains has been very good to work with. They've been out there a long time, and they have a great transport business. But our joinder with them on the oil gathering side enables them to extend their oil transportation up to us. Meanwhile, we're out there connecting various wells, not only our own and third party, to bring to that point, so you accelerate the development of the Plains transport business as well as giving us a business opportunity to add to our Midstream business.

And with that, I think that you can see why we feel that the money has been well spent. We have agonized at times on whether we were doing the right thing, but the returns on the oil wells have been 40% to 50%. We have nothing borrowed on our line of credit. With the 40% or 50% on our core business of E&P, Midstream setting itself up where we've earned on the two sales to EnLink and to Five Point basically a 5-to-1 on the amount of investment, we feel like when we put money in there with our operational activities, that's money in the bank.

And on the Land side, we all know the importance of getting in there in the good areas and building your positions, and Land has done that well below what we think market value is, and we've agonized, we've thought, and the same thing on the Midstream. If you don't do it now, that opportunity probably will not be around in a year or two.

So we've tried to be prudent. We feel over the years we've established a record of stewardship and would like for you to take a look now at a sum of the parts from when we went public 6 years ago. After going public, we were about $500 million market cap, and today we're a little over $3 billion to $3.5 billion is where we've ranged this year. If you look at the sum of the parts, you've got 114,000 net acres, but I say to you let's look at it in a conservative way.

You have 80,000 net acres, excluding Twin Lakes, and you can put a range of either $2.4 billion or take a higher number to, say, $3 billion, but let's use the -- or $3.5 billion, but let's just use the lower number, $2.4 billion. Then you add the reserves of $1.5 billion, and you're at $3.9 billion, and you need to add the Eagle Ford/Haynesville acreage, and you've got about $300 million or so. Add the Midstream, and you've got another $500 million there, and your total is approaching $5 billion. And you take out our current debt of $600 million, and you've got a value proposition that could be 50% more than where it is today.

And with that, I'd like to invite your questions, but I wanted to address the outspend upfront so we could have a good discussion on it and know that we think where we've spent money has been wisely. And if Matt or David has anything they'd like to add or just do it during the session, you can wait now or --

No, Joe, I'll just -- I think you've done a really good job of describing what we here at Matador and we've talked to you guys all about this before. We contemplate things in a mode of profitable growth at a measured pace, and I think this fits that very well. Joe, you talked about the E&P wells. We're adding value drilling wells in a very good basin, so we're adding reserves, we're adding production profitably, and that's incredibly important to us. The acreage component you talked about, we're adding great acreage at less than market price, so that to me seems like a very good investment. And then the Midstream, that's really growing into a profitable and value-adding business unit for us. So I think those three buckets, if you try to simply things, are three very good buckets to invest your money in.

All right. First question?

(Operator Instructions) And our first question comes from Gabe Daoud with JP Morgan.

I appreciate all the prepared remarks. Maybe if we could just start with well results, if you could maybe talk a little bit about the break sand interval at Rustler Breaks and any other new concepts there that you could be testing this year, and then maybe just a few words on the Antelope Ridge results and any early read on the first Bone Spring.

All right. Great question, Gabe. Let me try to do that in parts. First, we were very pleased again with how the money was spent on the drilling and completion side last year. We understand one of our Mallon wells was the best Bone Spring well drilled in New Mexico last year, and that out of the top 10 wells, we had 3 of them. When we went out there to the Delaware from the Eagle Ford, we were expecting -- we did it on the basis of we thought each area would have 2 to 3 zones. We are now up to producing from 15 different zones out there in the Delaware. And the break sand is looking very encouraging to us, and I'm going to, I guess, turn it over to Ned and then to David to comment. Ned?

No, the break sand is something we've had our eye on for a number of years out there. It originally produced vertically. It's a sand within the third Bone Spring carbonate, and we've had some well proposals in. We are happy to participate in that, and it really kind of shows that there's a lot of potential in this basin, that if you kind of look at the various vertical producers that have the potential to be turned into horizontals, there's a lot of those out there, so the break is definitely a good first result. We're excited about that. I think it's also worth kind of pointing out, while we're talking about well results, is the Wolfcamp A lower in Rustler Breaks. That continues to be a good zone for us, and I would say that that one is really being proven up, so that would be a second zone in the Wolfcamp A, independent of the Y sand, that can now be developed out there. So that's really kind of a big win for Rustler Breaks also, and you'll see more of those wells coming. The Florence well, we're very pleased with how that one came on. It's a great IP, and it's always nice to have the first well you drill in a new asset really come on like that, so we're pleased with that. Really too early to say anything about the other 2 wells in Rustler Breaks, but -- or, I'm sorry, Antelope Ridge, but we'll kind of watch that space. We'll update you guys as soon as we have numbers for you. And, really, it's -- Antelope Ridge is something we're excited about. I think the Geoscience and Engineering teams are both very excited to keep drilling wells out there and move forward with that.

David, do you want to add anything?

Yes, maybe just a little, Joe. I think Ned did a good job of summarizing it. I would just say, in general, I think the team was very pleased with the whole collection of well results in Q4. I think that they continue to meet and, at times, exceed our expectations. They've been very, very solid results, whether it's in Rustler Breaks or Ranger, Arrowhead, or Wolf, and of course Antelope Ridge was the real excitement of the quarter because it was the first one and the first new well there, but I continue to be real pleased with how the wells are drilling up in the Stebbins block up there in Arrowhead continue to perform, very pleased with just the whole overall collection of wells at Rustler Breaks and even down in Wolf, the new longer laterals that we had a chance to complete on the Kerr's and the Larson's. I think as we mentioned in the release, I think those are looking very solid, and they behave a little differently. As we mentioned, they tend not to have quite the show-stopping IPs, but they tend to produce a little flatter as I think those zones start to clean up out towards the toe, and certainly we cited a couple of examples from some of our Billy Burt wells, which are also some of the longer laterals we'd been able to drill several years ago and which are some of our best wells out in the Wolf area. So I think all the way around, it was a very positive quarter for well results for us, Gabe.

Great. Thanks a lot, everyone. Just, secondly, if we can maybe discuss well costs and the cost structure overall. Where are current AFEs I guess relative to the range you guys have laid out in the investor decks? And the 10% inflation number in 2018, is that off the high end of the range, or is that off the midpoint of the range? And then I guess finally, the new natural gas and NGL takeaway agreements, how does that impact whether it's realizations or the cost structure side? How should we be thinking about that?

Well, I would say, Gabe -- this is David again. I'll take the first shot here. With regard to cost per well and per area, I think if it's all right, we'd prefer just to defer that for a couple of weeks and go into a little more detail on that on Analyst Day. I think that would be a better use of time, and we can give you a little more detail around all that. The 10% number is something that will -- it's just sort of an average for the year, probably a little lower in the first part of the year and a little higher towards the latter part of the year, and it's just our best estimates of kind of where costs are going. I think that when you look at our D&C spend last year, which was about 490, you had to cut 10% to it, so where we've come to is not that surprising, and yet it includes additional operated and definitely additional non-operated wells that we'll be drilling this year, so I didn't really feel like the guide was that surprising. On the Midstream side, we have guided to about $80 million, which, again, is a little bit more than what we invested last year in Midstream. But, again, we didn't think that was going to be terribly surprising given that I think we messaged pretty well that we had still quite a bit to do on the oil infrastructure, the water infrastructure. We had talked about, at the end of the last quarter, the fact that we were going to drill up to 5 saltwater disposal wells, of which we have 3 working now and 2 planned for this year, and then, of course, finishing up on the plant, which is going to come in right on time and probably a little under budget here at the end of the first quarter. But then with the Plains deal, I think we've also allocated a little capital there for the potential for us to gather oil from some of the third parties, to get the trucking station put in, and those are some things certainly that we weren't anticipating right at the -- until right at the end of the year, when this opportunity with Plains came along, so that's also something we're very excited about. So I hope that helps to answer your questions to some degree on that, and we'll be happy to spend more time on that when we come to Analyst Day.

Gabe, I just wanted to add a couple of closing notes. On the Plains deal, one thing that has been somewhat overlooked is that it's a 400,000-acre area, which means a 625-square-mile area of mutual interest, and we'll be gathering there, delivering to Plains, so it should boost their volumes plus give us an opportunity to really expand and grow our business. The other thing is, to give you an idea also of the potential of the Midstream for growth, right now we've hardly got our saltwater disposal wells going. We're not fully amped up on that, and already we're disposing of [107,000] (corrected by company after the call) barrels between the wells in Loving County and the wells up there by Rustler Breaks, and we think that will simply continue to grow, but that's a very encouraging start. And all this added up, again, to a doubling of the EBITDA from last year, from about $159 million in 2016 to $336 million, half of which probably reflected the increase in commodity price, but the other half in volume. So because of the -- if you point to the 50% increase in production, that reflects the volume increase, and then the other half came from commodities. So all this is what leads us to say that the 2018 outlook is probably the best that we've had, because of the balance in all areas that we're operating in and the continuing growth in the expertise and experience of the staff. So I'll point that back to you, but, Gabe, we appreciate your question very much and thought it was a good one.

And our next question comes from the line of Tim Rezvan with Mizuho.

I'd like to continue on the theme of CapEx and Midstream. To be honest, I thought you might see a higher capital allocation to Midstream kind of given the new opportunity set with the Plains deal, and I just wanted to get your views. If there are opportunities to accelerate Midstream's spending -- I mean, those are probably some of the best projects in your portfolio given kind of the revenue stream. Can you talk about kind of how that could grow and just kind of help frame sort of what the EBITDA growth could be as you capitalize on sort of third-party gathering?

Yes, sure. This is David again, Tim. Thanks for your question. I think you're right. I think that there's certainly the potential for that investment to grow over the year. Some of it is just there are opportunities that we think may come to pass, but they're a little uncertain at this point, and so we're hesitant to commit to them yet. But I do think that in all areas, as we get the plant on, of course, there's going to be opportunity for additional natural gas gathering with third parties at San Mateo. We still -- with the Plains deal, there's going to be a big opportunity now to expand upon the oil gathering infrastructure that we have at Rustler Breaks and to build on that. And of course, that's still -- we're in the process of doing that, so the first half of the year, we'll be getting a lot of that infrastructure built out and taking advantage of the opportunities then to go to other folks. And then I think the whole water side of the business has really just -- has just taken off here in the last part of 2017 in particular, and so we planned to drill maybe 2 wells at Rustler Breaks, it seemed like we needed a third, and then just the opportunities for us to add third-party volumes made it quickly pretty obvious that we were probably going to need twice that many, so we're pointing towards 5. If we were to come back to tell you in a few months that we have the need to go to 6, I wouldn't want you to be terribly surprised, because I think that's certainly a possibility. But I think we're real excited about the fact that, as Joe mentioned in his opening comments -- I feel like a year ago we were talking mostly about gathering gas and processing gas and that was it on the Midstream side, other than maybe just some intramural water disposal and oil gathering, but that's certainly changed big time for us over the course of the last year, and we feel like we can offer pretty much a 3-stream solution to any third-party customer that's operating particularly up there in the Rustler Breaks area. And as Joe may have mentioned -- and if he did, I'm sorry to be redundant, but the deal with Plains is about a 400,000-acre joint development area, so that roughly is 625 square miles, so it's a large area in which we have an opportunity to be successful, and I think that will only continue to improve as the year goes on.

Tim, this is Matt. Just to add to what David said, I think it's very important to contemplate our Midstream business as a 3-pipe system, where we're able to go get saltwater disposed of for people, get oil in a gathering system and get it out of the basin, and process the gas for those folks, and part of the processing facility there is we generate natural gas liquids, and currently the way we're set up, we're processing about 70 million a day, and we're hauling those NGLs out via truck, so that's around 20, 25 trucks per day. And so what we've got in place is an agreement to get an NGL line built into that facility, which is going to do a number of things for us and any third-party folks that might want to come onboard. Number 1, it's going to allow the cost to transport those NGLs to go down significantly. Number 2, it's going to make sure that you can get those NGLs out. In other words, we are subject in Southeast New Mexico to some icy roads from time to time, and when you've got 20, 25 trucks a day coming in and out of that facility at 70 million a day and you increase it to 200 to 260 million a day, you could see how that would be a problem. So we've got this NGL line that's going in place, so we'll be able to put natural gas liquids into a pipeline and get them out of the basin. The other thing that that allows us to do, as ethane continues to slightly improve, at some point in time the ethane recovery mode may be the way to go as opposed to ethane rejection. You can't put ethane in trucks, that just doesn't work, but you can put ethane in a natural gas liquid pipeline, so we'll be having the option to offer Matador and third-party other E&P companies that option to recover ethane. And then on the deal with Plains, on the crude oil line, one thing that does do for us and for third parties is give optionality for other crude markets. We've got -- we get the oil to Midland, and we've got Midland-Cushing, we've got access to an LLS market and multiple other markets that not only Matador but others can also benefit from.

Okay. Thanks for that comprehensive answer. And if I can just switch gears a bit, you talk in your release on the Mallon wells that continue to be among the strongest New Mexico Permian wells we've seen, yet you're going to be running one rig across the Arrowhead/Ranger area in 2018. I thought you might see that area compete for capital a little more given the third Bone Spring results, so I was wondering if you could just talk about kind of how that factored into capital allocation for '18.

Well, Tim, that's coming into being. We run a very nimble schedule where we can move a rig up there if we need to, and the opportunities are there. Some of it is working on the land to acquire -- to block up a little more interest, to acquire a little more interest, give Land a chance to increase our interests, but that's just part of the capital discipline that we try to have, is that the returns that we've had on our wells are 40% to 50%, and that's the standard, so it's a pretty high standard around here. And then the other determining factor is the interest. If we think we have chances to increase the interest, then we try to be patient to wait for the most opportune time. And some like this, where the interests are broken up not only by various operators because this is an older area of production in New Mexico, but also by tracts, where you've got to go through either the joinder process or the forced pooling, just takes a little more time. But we're very excited about moving forward with more projects in that area, and we've got a number of designated, but we're just trying to -- I'm not saying it's no wine before it's time, but it just takes a little bit of patience, and I think it'll pay off in bigger interest.

Yes, and one thing -- this is David, Tim. One thing I'd just like to add -- I agree with everything Joe just said, but in addition, you might remember that when we bought so much of that area up there, it was in the transaction with HEYCO about 3 years ago, and of course most of that is held by production. There's lots of existing vertical production already on those leases, so pretty much all that acreage is HBP, which was a real -- was attractive to us at the time we bought it and continues to be attractive to us. So some of the allocation of rigs doesn't really always reflect relative excitement. It's just the fact that we've still got a few more things to get HBP up in the Rustler Breaks area, for example, than we do in Arrowhead/Ranger. I think with time, you're probably right, you'll probably see us move a little more capital that way, but some of it is just where we need to deploy the rigs to make sure that we get as much of the acreage position held as we possibly can in a timely fashion.

And our next question comes from the line of Neal Dingmann with SunTrust.

Joe, thanks for all the details and all the color this morning. Joe, my question is, really, first on Rustler Breaks. You all have been very successful in the delineation there. Based on that and the 3 rigs you kind of have focused in that area this year, can you talk about well density there and size of pads given all the success you continue to have there?

Neal, it's David. I would say that what you'll probably see in Rustler Breaks this year and what we're planning is most of the wells that will get drilled will be done in 2- and 3-well batches up there at Rustler Breaks this year as well, as I say, continue to kind of move out particularly towards the northwest of the acreage and get the rest of the position held. Not all our drilling will be up there, of course. And I think on spacing, you'll probably see us stay still fairly conservative at about 160-acre spacing or so, maybe a little bit tighter, but I don't think we're quite ready to move to tighter spacing. A lot of those 2- and 3-well batches will probably tend to be 2 or 3 different vertical zones drilled off the same pad in an area, or they may be opposing laterals that are drilled in the same interval. But I think our focus will tend to be on the Wolfcamp A XY, the Wolfcamp A lower, and we'll continue to drill some of the Blair wells, and I know the guys have another first Bone Spring test or two that are planned along the way this year, and we may look at some other exploratory opportunities, but I think that's pretty much what you'll see from us in Rustler Breaks this year.

Okay. And then just one follow up. You all have been very successful partnering with your -- and I think Joe did a good job of explaining this, with your Midstream and really growing with some of them, like the Plains deal that you've got. Could you talk about -- any thoughts about thinking of doing some vertical integration with some of your oil field services or partnering with them like the success you've had on the Midstream side?

We wouldn't say never to something like that, but we have no immediate plans. We're not in discussions or anything like that. We've got right now such a strong set of opportunities with just what we have in hand on the acreage and the D&C in the Midstream. Our plate is pretty full. We would've liked to have kept 100% of Midstream, but it seemed to make most sense to make a deal, as we did, with EnLink and with Five Point and with Plains and focus some of the capital as to our acreage, and we thought those were a little more robust, although we wanted the Midstream because it's complementary to our oil and gas revenues and has operational advantages. So it's a balance act, and I would never say we wouldn't do it, but I think it's safe to say we're not planning to go in the rig business or the frack business or one of those, and really tend to think that if you do a deal like on a sand mine, you're tying yourself up and committing yourself to using the kind and quality of sand that comes from that mine, and you may be better off maintaining your options so that you can use Northern white in one area and brown sand in another if that chooses to be the ideal way. Matt?

Yes, I think that's right, Joe. Kind of the way we think about vendors and how we work with vendors is we try to maximize value, just like we do with everything else, so we feel as though the pumping service companies we use, their real expertise is in providing horsepower and equipment that operates efficiently and products that we can utilize. That being said, we do have a very active interaction with those people, both on the completion side and on the drilling side, in regards to how we do things and why we do them and what products we use, and I'll just give a couple of quick examples, Neal. This is a case we talk about often on bid design. We're actively involved in that process. We don't just wait for the bit companies to come to us with a new design idea. We go to them and we work with them. On the clumping services, we get asked a lot of the time, "Well, who pumps your frack jobs for you?" And the answer is, "Well, we use typically the most reliable vendors we can use in regards to the equipment they provide and their ability to provide products," but in reality, we design the jobs. We have engineers and consultants onsite that execute the job, and so we work very closely with those vendors. But I'm with Joe, I think we need to let the people do best what they do best and we'll do best what we do best.

And our next question comes from the line of Philip Stuart with Scotia Howard Weil.

Congrats on another great quarter. When we look at the 2018 capital program and the focus almost entirely on the Delaware Basin, does that make it more likely that you would look to bring forward value in the Eagle Ford and/or the Haynesville by actively marking those assets for a potential divestiture?

Well, Phil, thanks for asking that question. We've tried to make it very clear that Matador tries to play a straight game, is that we have proved that we have sold -- we sold old Matador some years ago. We sold part of our Haynesville interest to Chesapeake when Chesapeake and Petra came bidding in what we thought were good values, and we would do the same with either the Haynesville or the Eagle Ford if someone came forth with a value we thought reflected the value and the optionality to us. We've had a lot of people come kick the tires or express interest, but they hadn't gotten to our price, and 2 years ago, when oil was $25, we certainly didn't think that was the right time, and we felt being patient would increase the price and improve the offers, and it has. The offers have gotten better as oil prices have risen, and so I think our patience is paying off. We'd be open to selling them if somebody came in. We're not going to sell them just for the PDP value, but it has acreage development. The return on the 5 wells that we drilled in the Eagle Ford last year are going to be very comparable to what we've done in New Mexico in that -- overall, in the 40% to 50% rate of return, and there's still promise there in other zones -- Upper Eagle Ford, Austin Chalk, Buda. You hate to rush in and sell. There were companies that sold out of the Delaware that have now, for hundreds of dollars or a few thousand dollars, are coming back in and having to buy back at 10 times that price. So we're certainly open to it, and that we don't anticipate putting a lot more capital in it, but yet those are good areas. The Haynesville wells have really improved in their returns as they've made bigger wells and done the longer laterals, and we've been a part of that. We still have the Cotton Valley in North Louisiana. We reserved those rights when we did the deal with Chesapeake, so we have maybe another 200 billion in Cotton Valley reserves, all HBP, both areas HBP, so whenever prices get better, you have that option. So, yes, I mean, it's no secret that we're open. Anybody expressed interest, we've talked to them, but we do think being patient will eventually get something of interest, or we'll trade for it. And we also may go back here if you have gas prices on the rise or when the capital situation might be different or we felt our opportunities are less, but right now the opportunities in the Delaware are just increasing, not only as to the zones we are in, additional zones and the Midstream possibility. So they're good, but they have -- it's HBP, so we don't have to -- we're not under a time thing, and it'll just -- we look at them, but for the year ahead, I think our focus will be on the Delaware, but invite people that are concentrating in those other areas that we'll be happy to visit with them and try to make a deal if their price is strong enough.

Good deal. That makes sense. And if somebody were to offer you kind of the right price, what would be the use of proceeds? Would it be to accelerate activity faster in the Delaware, or would you be focusing more on trying to acquire bolt-on acreage in the Delaware? What are your thoughts there?

I think it'd be allocated pretty much to whatever -- these 3 opportunity sets that we're talking about, acreage, D&C and Midstream, and I'm not sure how they would allocate. We'd have to -- that just would be another discussion, but it'd be a high-class problem, and we would certainly welcome that study.

And our next question comes from the line of Jeff Grampp with Northland Capital.

I wanted to maybe get a little bit more detail. In the release from last night, you guys referenced looking at maybe some longer laterals in certain areas in '18. I know in the Wolf area you guys have successfully done that in the past. Are any of your other operating areas setting up to do some longer laterals beyond those kind of 4,000 to 4,500 that's kind of been the norm for you guys?

Jeff, this is Matt, and I think you hit it pretty right there. A lot of the longer laterals we're talking about are going to be down in the Texas area. That being said, we do have some planned and are excited to drill up into New Mexico as well. We just recently have done some, and I think it's a good exercise, because in calls in the past, we've talked about the risk associated with getting out in the 2-mile range, and I think Billy and his team have done a great job on some recent wells we've drilled, and really planning, Jeff. I mean, what this really comes down to I think from an operations standpoint is to make sure that you contemplate all the things that may or could possibly happen to you and how you're going to deal with those, so the drilling guys did an outstanding job working with the Geoscience team to identify the target and stay in these targets for a mile and a half, for discussion purposes, and at the same time, the completion guys were watching how they were going to get out there and how they were going to get these wells completed. And so we've done a mile and a half in the past, and we do have some even longer than that planned for 2018. That being said, most of the longer laterals will still be down in the Wolf area.

Okay. Great. Appreciate that detail. And then for my follow up, more on the Land side, I know you guys have obviously continued to be pretty active throughout time. Can you just qualitatively give us a sense for how the leasing activities have trended? I mean, I imagine things continue to get tougher, but I guess, in other words, could you guys acquire another 20,000 to 25,000 net acres like you did last year organically? I know, obviously, it's hard to guide, but just directionally trying to get a sense for where you see things heading.

Well, Jeff, you know the old saying in the land business, you can do anything if you have enough money, and so if we would raise our price targets to $20,000 or $30,000 an acre, I think we would achieve that. But what we're trying to do is acquire the acreage at a more reasonable price than that, and we're achieving that, but -- it'll be harder to do it in the 25,000 range, but we're not setting limits on it so much as still aiming what I think is most reasonable to expect, is 1,000 to 1,500 acres a month in a number of small transactions, and halfway through the year, if we've achieved that, then we'll challenge our Land guys to do a year like last year. We are also very pleased with each well we drill. We feel like we can say with more certainty what each acre may mean to us and have a better understanding of how to evaluate it. So I think they've done a great job, and this is probably a good point to look at when you look at, over the years -- that if you look what you have each share of Matador's stock represents, you can obviously look at our growth in acreage at the time we went public. I think we had 7,000 acres in the Permian, and today 125,000, so obviously each shareholder of Matador has had a bigger and bigger piece of the acreage, the number of acres, and plus those acres have all appreciated in value, not to mention what's in the Eagle Ford or the Haynesville, which are HBP. And the second thing, you look at the reserve growth per share -- that's also been very significant, and now you've got the Midstream, which really has helped. We've also increased the amount of mineral acres that we've been buying, which is priced even higher than a working interest acre. So all in all, the thing I feel comfortable with is, when I've visited with shareholders to show them how much -- not that Matador has grown, but the value of their share has more acreage, minerals, barrels of oil, Mcf of gas and Midstream property value that they have, and that's why we think this year is really going to be good, because whatever we did last year, we should be able to do again. And that's our challenge to everybody here, is, guys, you all were pretty good last year, but we're expecting something better today, so what have you done for us lately is what we ask the staff, and they're responding and doing, I think, a really good job, and we're off to a good start.

And Jeff, if I can just add one quick comment -- this is David. I just wanted to say too that it's also a lot about the quality of the acreage for us, and I think that we're working pretty hard -- I know the guys work very hard to increase our position in wells that we know we're already going to drill or units that we know we're already going to drill. Those don't always show up -- the value of those don't always show up, and maybe we add 20 acres in a particular well or 40 acres in a particular well, but in terms of the value that it creates, it makes a big difference. And on the acreage count, if the Land guys trade 200 acres with another operator, that can have a lot of value to both parties, and from our point of view, it doesn't make the acreage count pick up, but it can certainly make the value tick up, it make the number of wells that you can drill, your ability to be the operator, so there's a lot of things that I think for us going to the whole land game behind -- other than just simply how much can we make the tote board go up.

Jeff, this is Matt. I'll just pile onto what David's saying there. I think we're much more focused on quality than we are quantity. I think we would much rather add 100 acres in a block that we've actually got a well that we've proposed to drill on than we would 100 acres somewhere else where we're not going to be the operator. So what David said and what Joe have said, if we're adding 100 or maybe 10 acres or maybe an acre -- no acre is too small for us, but if you can just continue to put those little blocks together in very advantageous areas, that's a home run for us.

All right. Great. Well, best of luck on that, and appreciate the time, guys.

Well, Jeff, just to follow up what Matt said, when I started in this business in '83, I was doing 1-acre deals, and so -- but they can really add up and aggregate, and inside the mental part, again, about particularly where you're drilling multiple wells on the same tracks at different depths, anything you can do to help the net revenue interest -- higher net revenue interest leases or buying minerals -- has a cumulative effect. And what David said -- to underscore what David and Matt said on the quality, there's -- we may not equal the 25,000 acres in quantity, but the quality we add this year may be the best ever.

And our next question comes from the line of Scott Hanold with RBC Capital Markets.

Could you all discuss, following these Midstream deals that you've announced, what the third-party opportunity could look like over the next couple years and how you are taking a look at that at this point in time?

Scott, this is Matt, and that's a good question, and one of the things we've done strategically when we've built these Midstream assets -- if we go all the way back to the plant we built down in Loving County that we ultimately sold to EnLink, we typically build these facilities initially for what Matador needs, with some extra. So going all the way back to the plant down in Wolf, we built about a 35 million-a-day plant thinking that initially we would need capacity for 17 million or 18 million, which is kind of what happened. That got full with equity gas. EnLink now operates that plant. So if go up to the Rustler Breaks area, we did the same thing there with this initial facility. We built it, and it's -- we thought we'd initially have 35 million, 38 million coming into that facility, which we did, and so we got that full, and now we're going to ultimately 260 million there. So during the time that all this is happening, the Midstream team, Matt Spicer, Gregg Krug and their team, they've been out talking to third-party operators, and we do have some third party coming in on the saltwater disposal, and as we continue to drill these wells and add capacity, that just gives us more and more room to do that. This plant expansion will be operational here at the end of the first quarter, so that's going to give us some room. But I think one thing that ties back into this Plains deal that Matt and his team can go out and do is sell a 3-pipe system, and so when they do that, they're going to be able to go and say, "Hey, we're one-stop shopping, and we can handle all these needs." So those opportunities are there, and they're out getting these things done, and the deals are coming in now, and I think they're going to continue to increase.

Matt, you did a great job on that. Do you want to add to what Matt --

Sure. This is Matt Spicer. We've added to our business development team on the San Mateo side substantially here. We think 2018 is going to be kind of the year of the third party now that we have space. It seems like every time we built an asset, Matador fills it up. So we've got ahead of that with saltwater disposal, with gas processing, and now with our oil terminal and with our oil gathering, so we're very excited. We know the activity is very, very high up there in Rustler Breaks, and we're meeting with pretty much all of the producers in the area to make sure that they have optionality just like we've provided for Matador.

Yes, and specifically to that point, it seems like you guys have obviously outrun your expectations over the last couple years, so certainly good for you, but maybe less room for third party. Now when you're looking at this new system and continued development, are you thinking about oversizing it even more, with the expectation that third-party bottom can be a much more significant opportunity here?

I think that's a great point, Scott. The deal we did with Five Point allows us to, what you say, upsize our facilities to 260 million a day in gas processing. I think that leaves substantial room for a third party. And in our oil line, we increased that size after the Plains deal, and we'll have upwards of over 100,000 barrels a day that we can take through those lines. So with the deal with Five Point, we've gone that extra step and created significant room for a third party.

Okay, that's great. Thanks. And my next question is royalty rates on average, and David, I think you made a point that obviously you've been buying some minerals, and I know you guys have some state and some federal land. When you look at 2018 activity, could you give us a sense of what you think your just high-level average royalty rate looks like in '18 versus, say, what it looked like in '17?

Scott, I wouldn't expect for it to be very much different in 2018 compared to 2017, just mainly because the mix of wells and where we're running the rigs isn't very different. I think, as you know, we tend to have advantaged royalty interest up in the Ranger area because there are a lot of those wells that are drilled on federal and state acreage, where we have a little bit better royalty interest. In Rustler Breaks, we probably run a little bit ahead of the 75% number, but it's probably maybe 77% or something like that. And down in the Wolf area, it's probably similar, but maybe a little closer to 75% there because most of all that acreage is fee. The other thing that we've been doing, as Joe mentioned a minute ago, is we have been buying some minerals here and there, and certainly when we've been able to do that, that's helped to improve the royalty interest or the net interest to Matador in those cases, and there's also been a case or two where we've added a federal lease within an existing unit that's further improved our royalty interest there as well. But I don't think, mix-wise, it'll be terribly different than what you've seen in the past.

Okay. So right around -- it sounds like an average around 20 or maybe a little bit above that is probably not a bad number to use, then.

Yes, I would say if you're using the net revenue interest for us between 75% and 80%, you're probably going to be right 9 times out of 10.

And our next question comes from the line of Irene Haas with Imperial Capital.

So congratulations on another record quarter, and my question has to do with the Midstream. It seems like in the Delaware Basin, there's really plenty more to do, requiring more capital. I'm just kind of wondering, outside Wolf and Rustler Breaks, which of your sandboxes might need more expensive sort of Midstream buildouts of opportunities, and if yes, when should we expect San Mateo to become public?

Irene, this is Matt. I'll answer the first question.

The second one's a secret.

Yes, the second one's a secret. No. I think, Irene, as we go forward here, the deal we had with Five Points is at Rustler Breaks and down at Wolf. That being said, we have the option to bring those guys in on anything we want to do in the rest of the basin, and I think it's going to continue to be just as it has been in the past, Irene. It's going to be opportunity-based and need-based. So as we ramp up activity in, let's say, Antelope Ridge -- that's a new asset area for us to be operating in. We will take a very close look at all the things we've been talking about -- oil transportation and delivery, and gas transportation and processing, and getting rid of saltwater and transporting saltwater, doing all those things. And where there is an opportunity and where there's a need where Matador can fulfill a significant portion of that as an anchor tenant, that may be something we can look at and will look at. In some areas, it may not make sense for us to be in that business, so it's just going to continue to be, as we've talked about over and over, value-based and opportunity-based.

Okay. May I have one follow-up question? Just a little color on the Twin Lakes Wolfcamp D well. It's taking a little while to complete. Sort of any update and color on that? That's all I have.

Right now, Irene, it's -- I'm assuming you're referring to the well we're partners with Cimarex, and they are continuing completion operations, so they're still in the middle of completion there.

And our next question comes from the line of Dan McSpirit with BMO Capital Markets.

Can you speak to cycle times today, and maybe how they can improve over the course of 2018, and what that might mean for the production growth profile?

Well, Dan, that's a hard question because we're drilling so many different zones, some exploration, some development. But Billy Goodwin, who is the head of our operations group, and Matt and their staff have done a very, very good job of cutting down the number of days on well. Some of it is the technique and the experience of the guys supervising the well, and some of it is just the better equipment that we've been able to get from better drilling rigs at Patterson that we've made deals with Patterson on, more powerful pumps and just better equipment, and the same thing on fracking, cutting down times on the well, so we give a lot of credit to them. That's one reason we drilled more wells than expected last year, because they -- which helps to mitigate the costs. They're continuing to do that with innovations, as I said, in bit design, but also now we've got a 24/7 room, what we call our Maxcom program, with engineers and geologists working together, interdisciplinary, 24/7. So there's somebody here on the job at all times monitoring the penetration rate on the horizontal wells that are being drilled and keeping them in zone, and this is already starting to cut costs and improve efficiencies greatly. Billy, do you want to add to that? I want to give you a chance. It's a great idea you've done.

All right. Hey, Dan, this is Billy Goodwin, and Joe touched on a lot of the good points there of what we're doing to cut down on days on well and do better, and we love the rigs that we have out there, custom-built with a high-pressure system and the piping. We rig them up for MPD, managed pressure drilling, and work closely, as it has already been said, with the bit side and BHAs and adding to that. And also, another thing that we're doing this year, the asset teams have gotten together and are going to be doing a lot more batch drilling this year, so we'll be saving over $200,000 a well on the drilling side, and also on the completion side as well, so that's over $400,000 a well we're going to save. That also helps us on our efficiency, like Joe talked about, and lets us utilize all that. And then, also, he mentioned our new Maxcom program, and this is something that we started up 24 hours a day. You'd get a call at 2:00 or 3:00 in the morning trying to decide what to do, and we as a company feel like it's very important to stay in the target zone. We think we get better wells that way, and this has people looking ahead of time, not being woke up when something's wrong, to keep us in zone more of the time right where we want to be. So we're doing better there, but also we have people in there watching, and it helps us on the performance. We just recently started this program, and we've already seen new records in different hole sections -- vertical part of the hole, lateral section and build section, all three. So it's working out for us, improving the performance, improving our costs, and also creating a situation where the engineers and geologists are working together, learning what each other do, and it makes a better team member, so it's better for us all the way around. We're really excited to keep moving forward this and getting better.

Dan, it's Matt, and what Billy's talking about, it's a fantastic program, and we've been doing all the things he's been talking about, but this kind of rolls it all together, and so we're all about efficiencies at this company, and we've talked about that forever, and we continue to be about efficiencies. And just in regards to cycle times, just to add a couple of additional points there, we don't typically run a large DUC inventory, and so we have really good relationships with our vendors. We're using Halliburton and Schlumberger right now in our frack jobs, and we're able to, with some adequate planning -- I think that's a very important part of this -- be able to schedule additional frack crews when we need them to make sure that our DUC inventory doesn't get hardly at all. We want to be able to drill these wells -- Billy was talking about batch drilling, so we may 2 or 3 wells that we drill on a location, and then just as soon as we can get that rig off there and get a frack crew in there, that's what we're trying to do, so that's one things that helps on cycle times. And then another thing is -- it ties all the way back to Midstream again, is just for us to be able to walk down the hall and -- or for Gregg to walk down the hall and say, "Hey, marketing wants this well hooked up to Midstream tomorrow," that that happens for the most part, so that's a huge benefit there. And so we do focus on cycle times, but as indicated here in the first quarter, we're going to have some batch drilling that's going to provide some continued lumpiness, as it always has before.

Dan, it's a great question, and that's why I always encourage people to look at things, it seems like, on a 6-month schedule instead of a quarter schedule. It seems to iron out a lot of the timing differences on your cycle times. So there are a number of factors that affect it -- the batch drilling, proximity to the pipeline because we don't want to be flaring, and -- but everybody is very aware at each stage of these to reduce time as much as possible, and collectively they're -- they keep managing to find a way to cut days off of each well in each area. So I think it's a great question, and it's something that I hope you've seen the improvement over the years.

Well, I appreciate the detailed response on how to maximize throughput. As a follow up, if I could, and last one for me, what is the PDP decline rate on oil and gas in the Delaware Basin, and how might that change over time?

This is David, Dan. To tell you the truth, the -- I don't know if my numbers would be terribly accurate if I just tried to pull something right off the top of my head this morning. Maybe we can address that a little more at the Analyst Day. I think I'd feel a little better prepared to take on that question at that point, if that's all right.

Yes, that's fine. We'll see you soon. Thanks. Have a great day.

And our next question comes from the line of Sameer Panjwani with Tudor, Pickering, Holt.

I was wondering if you guys could provide some color around how you think about Wolfcamp prospectivity at Ranger and Arrowhead. I know you tested the lower A at Ranger last year and you're looking at an XY test at Arrowhead this year, but just thinking about it from a broader perspective, how large do you think the Wolfcamp opportunity set could be, especially when you consider the potential for stacked pay at both Ranger and Arrowhead?

Well, this is David. I'll start, and then I imagine Ned will probably want to weigh in, Sameer, but good morning to you. I think we still continue to feel like there's significant potential in the Wolfcamp in the Ranger and Arrowhead area. I think we've taken a couple of stabs at it, and I know the other operators have as well, and I think that it's, again, going to be just a matter of -- it's a very thick section. There's a lot of opportunity. There's even opportunity I think for multiple targets within it. It's just a little different animal, does have quite the over-pressure that you see in the Wolfcamp down to the south, and so a lot of those wells tend to perform a little bit more like the Bone Spring up in that area. So I think that we're still on the learning curve there as far as -- but there are areas that have the XY potential, there are areas that have the Wolfcamp A lower potential, and there are other zones deeper in the Wolfcamp as well, from Rustler Breaks on north, that we're excited about. So, overall, I think we continue to be encouraged. I think it is something we're going to take at a slow and steady pace. I mean, we have most all that acreage in the north, as I mentioned before, HBP, so I think we're going to -- we'll focus primarily on the second and third Bone Spring, but we'll continue to test and learn what we can about the interval, and I think from an exploration standpoint, we remain very encouraged about the potential. Ned, do you want to add anything to that?

Yes, I do, David. I'm very optimistic, and I think the Geoscience team is also very optimistic about the potential there, and I think David kind of hit the nail on the head. We're taking a pretty deliberate approach up there, and right now we're sending some of the team out to the various core repositories in New Mexico and Midland and pulling cutting and really starting to do a pretty regional study on the northern Delaware Wolfcamp. The initial reads on that are very positive, and as David said, we have a lot of optionality. The XY are present. Stebbins got the call out for a potential test this year, but the XY is present in a lot of that northern Delaware acreage, so we're excited about that. The upper Wolfcamp elsewhere looks good. The Wolfcamp D is also a widespread target up there. Some of our preferred targets in the Wolfcamp B that we've seen in Rustler Breaks will also extend up there. So there's a lot of potential, and I would say, again, to sort of watch that space over the next year or 2, and we're really hoping to prove up that asset.

Okay. That's helpful. For my second question, I was wondering if you guys could provide some color on what the delivery point is for that gas takeaway agreement you have with El Paso.

The current deal we have with El Paso, Sameer, gets us to Waha. We are keenly aware of the issues around getting out of Waha. We tend to look at these things on a long-term basis, so we are looking at multiple options to continue to get that gas on out of there. Right now, we -- knock on wood, we don't have any issues getting that done, but I assure you that Gregg and his team are rock solid into looking at what's available today as well as what's going to be available tomorrow and in the coming months.

And our final question comes from the line of Ben Wyatt with Stephens.

This is actually John Durham stepping in for Ben Wyatt. So my first question just goes for the rigs. So 3 rigs are locked in right now, 3 are on shorter-term contracts. Do you have any concerns with service prices maybe going higher? Would you consider securing any of those 3 additional rigs at lower rates?

John, this is Matt. I'll answer it and then ask Billy to jump in here. The brief answer to your question is no. I think we have a very strong relationship with Patterson, and the rigs we have operating on a short-term contract, we're in constant communication with them about what our plans are for the near-term future and also for the long-term future. So the notion that those rigs would go away from us without us having an opportunity to lock them down, that's not going to happen. I don't believe that's going to happen. As far as having them set to market rates, well, certainly they would be. But kind of the way I think about things -- and again, I'm going to ask Billy to weigh in -- is the cost for the rig is a significant component of what the well costs are, but not what it once was, so I think that the efficiency that you're going to achieve with having these high-tech rigs, the momentum that you're going to carry by continuing to use these type rigs, would certainly -- not entirely offset any cost increases, but it could potentially have a very impactful result in maintaining cost.

I think that's a great answer, and just like Matt spoke about, the relationship we have with Patterson, it's -- they like some longer term, some shorter term. That's good for both of us together. And as we move along, move into different areas, one of the rigs we've added additional pumps and a high-torque top drive, and they work with us to get those things done, and that plays in. We can just roll that right into the next extension on the contract. So it's a good relationship and works good for both of us.

Got it. Thanks. And just one final question, just with the well down in Wolf/Jackson Trust -- very strong results there, good oil cut and pressures. Do you guys see the lower Wolfcamp A becoming more of a target this year versus the XY in that asset area?

Yes, I think that we'll continue to focus on the lower there. So as I recall, the XY itself is not particularly that present there, so that's really the better of the A targets. You kind of get into the XY as you come over a little bit farther to the west there, as you get into the Wolf area, so that's another reason why we focused a lot on that interval. There's also multiple Wolfcamp targets there, so we may look at something else as we go forward, and we may even look at a B test there too down the road, but I think you'll see, in the near term, probably more focus on that A lower zone.

Thank you, ladies and gentlemen, and this ends the Q&A portion of this morning's conference call, and I'd like to turn the call back over to management for any closing remarks.

Thank you very much. I have just 2 last -- or I guess 3 points, last points, I want to leave you with. As you look at the share values, I think you will -- this year, my prediction is you'll see a year much like last year, continuing to work in all 3 of those areas. Second is -- I'd really like to point this out, is the staff works hard on its projections, and I think we enjoy the fact that for the last 14 or 15 quarters, we've met or exceeded guidance, so that's 3.5 years of meeting or exceeding guidance, so a consistency that, again, I give a lot of credit -- the credit goes to the staff here, Roswell and in the field on delivering on that. And finally, when you have a strategy not -- we don't have a grand strategy that we'll be the 3D in this company or -- but we have a strategy based on better and better performance or continuing finding ways to reduce cycle time or to improve the drilling, improve the fracks, make land deals. When you have that, it's not one factor, so there's a lot of strength in the fact that each of our groups are working well and getting better and adding to the overall -- contributing to the overall effort of Matador. And so as we saw 2 years ago when oil hit $25, we kept going, and there were a lot of people that said, "Hey, maybe you should reduce rigs." We didn't, and we had a lot of innovation and improvements, and we got better rigs from Patterson as a result, and it had a lot of benefits. We want to be careful about the money. We are all large shareholders here. We have big stakes in the game. Matt, Dave and all of us make a lot more from our stock than we do our salaries, and we care, and we have a lot of friends and relatives. We didn't come from private equity. We came by friends and relatives, and we kid with Matt he has both his mother and his mother-in-law in the deal. And we want this to work out for everybody and all the shareholders, but are pleased that we can offer a -- from going public in 2012, a much more productive group, much more well rounded and diversified into the Midstream and into other areas than just being a Haynesville company. So I appreciate the questions very much. I thought it was a -- there were some great questions answered, and these are the same type of questions our board had just gone over a couple weeks ago and that we do on a regular basis here. We look forward to Analyst Day, where we can get into more detail on these things. And we've taken some kidding that we put out too much information too long, and really that's an effort to be transparent about what we're doing and why we feel that we're on a good trajectory and an effort that -- look, you don't have to read it, but we want you to know in a very granular way that we've thought through all these different areas. So please come to Analyst Day. We'd really like to have you. We'd really like to get into more discussions on your questions. And we always want to invite everybody to come see us in Dallas and meet the staff, and not just the senior staff, but also the young staff that's out there on the front lines making a lot of this happen and coming up with a lot of good ideas for improvement. So with that, I'm going to sign off, but thank everybody for their time and attention, and we hope to see you at Analyst Day or at least some other time during the year. Thanks very much.

Ladies and gentlemen, thank you for your participation today. This concludes the program, and you may all disconnect. Everyone, have a great day.