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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. And welcome to the Fourth Quarter and Full Year 2019 Matador Resources Company Earnings Conference Call. My name is Tuwanda, 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 March 31, 2020, 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 proceed.
Thank you, Tuwanda. Good morning, everyone, and thank you for joining us for Matador’s fourth quarter and full year 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 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 quarterly report on Form 10-Q.
Finally, in addition to our earnings press release, I would like to remind everyone on that you can find a short slide presentation, summarizing the highlights of our fourth quarter and full year 2019 earnings release on our website on the Events and Presentations page under the Investor Relations 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. 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. I’m going to forego the usual introduction of the Executive Committee who are in the room with me today and other significant people at Matador, but -- in order to make a couple of points, and then we’ll have more time for questions.
And I’d like to begin simply by thanking the staff, shareholders that with their help and support we can report to you that we very simply had the best quarter we’ve ever had in the fourth quarter, and we had the best year we’ve ever had in 2019, despite the headlines. And now, two months in the 2020, I can say that 2020 is shaping up to be even better. And 2021, as I’ve noted for the first time, looks like will reach the free cash flow and continue the achievements in the field and with the midstream, and that 2021 will be the next best year.
Several points I just want to make. It’s not a model claim that 2020 is going to do good in 2021 will be clear that we’re reaching that free cash flow point, subject to the opportunities. And you can mark it this year by a number of catalysts. First, in late March and early April, we’ll be bringing the Rodney Robinson -- six Rodney Robinson Wells on line in our Antelope Ridge. That will be very important and I think very productive wells. Then, in June, we’ll have the Ray and Leatherneck. June and July, the Ray and Leatherneck wells coming on line, will be the second important catalyst. And then, you get to September, and we’ll have our big birth, so to speak, from the Stateline wells. We’ll have 13 of them coming on line in September. And you can begin to see the full impact as well as our second San Mateo project and plant will be ready to go in September. It’s currently on line -- I mean, it’s on time, on budget, and which will enable us to start processing a 0.5 billion cubic feet gas per day, doubling our capacity.
So, naturally, we’re all very excited by that. And this is the result of a two-year strategic plan that based on the longer laterals and associated operating and capital efficiencies from these longer laterals. And, it’s obvious that you save money, but you also pick up extra productive zone, and these are delivering superior results. And, it was a turning point when we were able to secure the leases and block up the acreage and the other parts, so that we could do these 2-mile, greater than 1-mile laterals.
Next year, 84% of our drilling will be wells that’ll have laterals longer than 1 mile, 74% of which will be the longer 2 miles or in a few cases, 2.5 miles. So, you can mark your calendars if we attain those goals that I’ve mentioned, you’ll see -- it’ll become even clearer that the free cash flow is around the corner, subject to those opportunities. We just didn’t want to announce that in specific terms until we felt very, very confident that we could do what we said we were going to do. And that’s important part of our operating strategy is to do what we say we’re going to do that. I know that sounds corny, but it means something to us.
And when you look at our steady rise in our production, our exit rates, think about in 2016, which was one of the most difficult years; we exited with the growth at 29,965 barrels of oil a day. And today, we exited in December at 73,749 barrels of oil a day. And when you consider on the day we went public back there in February of 2012, we were only making 400 barrels a day. So, in seven years, we feel we’ve come a long way from 400 barrels a day to over 73,000 barrels a day. And we have further progress inside. A shout out to all of our different groups at Matador for turning in exceptional jobs from operations to marketing in midstream to the accounting groups, to the land groups, so their brick by brick strategy has all resulted in this consistency that we think we’ve delivered for shareholders that we’ve met or exceeded industry guidance, projected guidance now 22 straight quarters.
We don’t see anything stopping that which leads me to my final point that these leases that allow us to drill these longer laterals have helped us reach a different level and our midstream rate going forward has helped build a thriving business half there. And it now allows us to look at -- consider noncore assets and making transactions on that would allow us to further accelerate our growth and perhaps start a mineral business much like what we’ve done with San Mateo and a JV partner. This strategic plan that we put in place and have carried out, leads to how we’re going to sustain our growth, and you’ll see the seeds being planted to go into new asset areas, to continue the better execution and continuing to work, some of the best rock in the Delaware. And so, we’re very excited and still operating under the notion. Again, it sounds corny, but I think it works of having profitable growth at a measured pace and putting first the notion, let’s create some value for shareholders. And even if it makes a little more difficult for us in the short term, the long-term value of good rock, good people and good operating plan, that strategy has been working for us and we expect that to continue.
David, did I leave anything out?
No, Joe. I think you’ve covered it. I think, we continue to be very excited about the plan we put in place last year. I think, everybody can see that we’ve executed very well against the plan, probably a little farther along at this point than we thought we would. But I think things that we had laid out for our investors at this time a year ago that we’d be drilling into Rodney Robinson area by the fall and that would be at Stateline by the end of the year, have all come to pass. And I think, all of us here on the team are very excited about the year ahead and the things that we have to accomplish. And we’ve said we were going to build these two businesses, the E&P business and the midstream business side by side. And I think that’s exactly what we’re doing. And we’re looking forward to achieving the milestones that we’ve laid out, and particularly, when the expansion of San Mateo and the Stateline production come on at the latter part of the year. So that’s what we’re focused on and looking forward to accomplishing that.
All right. So, we will take the questions. Operator?
[Operator Instructions] Our first question comes from Scott Hanold with RBC Capital Markets. Your line is open.
I appreciate all the updates, pretty constructive, especially setting a free cash flow timeline. Can you give us a little bit of color? As you look into that period of potentially hitting that in mid-2021, how do you look at the decisions to that point? Like, do you see yourselves maintaining a free cash flow neutral position from that point, or would you ever move into the strategy of now more of maintaining activity and generating free cash flow for other options?
Hey Scott, it’s David. It’s an interesting question. I think, in some ways, I would say, maybe the best answer I can give you is kind of one step at a time. I think that we are and have been, for the last year, looking toward how we would best to get -- best get to that point where we felt like we could achieve and continue to generate free cash flow into the future. I think that we feel like we’re solidly on that path and that next year can be an inflection point for us. But, I think that’s what we’re going to focus on over the next 12 to 18 months. And as we get closer, we can give some additional thought to you to how we want to use some of that cash flow.
I think, as you know, we don’t see ourselves as an opportunity constrained company. So, I think that we always feel that there are good ways for us to put -- to put money to work. The current environment has -- we’ve been a little constrained in terms of the capital and what we can do. So, we really focused on this 6-rig plan. I don’t think we have any immediate plans thinking through the next year to increase the rig count. I think, we feel like we can achieve these goals with -- staying with the 6-rig count that we have. And if you look at what we did in 2019 in terms of the improvements in the capital and operating efficiency, I think we already feel like we’ll make more strides in that way in 2020. And as we travel through the year, I think we’ll have an ever better outlook for 2021. But, I think, things look pretty promising. And we’re excited about the days ahead.
I appreciate that color. And you all have pretty impressive entry exit growth rate that really sets you up pretty good for 2021. And, in that context, David, where you said you’re -- generally speaking, you’re maintaining six rigs into next year is kind of a high level perspective. What do you think like growth looks like in 2021? Obviously, you made the point that you think it’s going to be stronger than 2020. But, can you provide us a little bit of context on what that might look like?
Scott, I would say this, is a lot of it depends what is the price of oil in 2021, what is the American economy doing in 2021, and what has changed about our industry over these next two years? I think, we’re in something that’s -- there’s great change going on around the world. And we’ve got to look at those circumstances. And that’s why we’re looking at it from a number of different perspectives. It’s important to take one step at a time. We know we’re doing that. It’s not that we’re going to not think about anything until 2021. But you just -- it’s a lot of uncertainty. And there’s no sense in making an announcement, oh, yes, we’re going to do this, do that. That’s almost two years away, and a lot can happen in two years. We will have more definite and clear plans or announcements on that as year 2021 approaches. But, those are under study right now. And I do think, we’ll maintain the 6-rig program that’s working pretty well for us. And we’re optimistic about the opportunities. So, we’ll have more on that as the year goes along. So, give us a little time to see how circumstances shape up.
I appreciate that. We’ll do. And congratulations.
Thanks, Scott. We appreciate it.
Thank you. Our next question comes from the line of John Freeman with Raymond James? Your line is open.
Good morning, guys.
Hey. Good morning, John.
Good morning. So, I’m just -- when I think about just you had a terrific track record of beating your production guidance over the years. And I’m just trying to get a sense of when we think about such a dramatic step up from only 8% of the wells last year that were 2-mile or longer laterals versus a 74% this year, just sort of how we should think about how you incorporate kind of the uplift from the 2-mile laterals in your production guidance, given the limited data set in ‘19 from those type of wells and just your typical conservatism, just any way to kind of think about how you go about budgeting with such a dramatic change in the wells?
Yes. Hi, John, it’s David. Well, I think that what we’ve done of course is done a lot of looking at not only the few wells that we’ve drilled, but also wells that have been drilled by others throughout the basin to get an idea as to what the expectations would be. I think that we have -- generally are of a mind that from the standpoint of EUR that -- whether it’s field preferred or how we want to look at it that those things seem to be pretty close to linear, I think. And so, we feel like we’ll see that from an EUR standpoint.
I think we said in the past that we have typically seen and think that it bears out when you look at others’ walls as well that you probably tend to have a little less of an initial rate. It’s certainly not -- it’s not a 2x kind of initial rate, and then probably tends to be a little flatter as these wells begin to clean up. And I think that’s certainly been the case, like you take the Jeff Hart wells for example, that we did in the third quarter in Antelope Ridge. That’s absolutely what happened there. Those wells maintained a fairly flat or low decline for the first four or five months, six months of their life. In fact, I think even the Second Bone Spring well inclined a little bit as it continued to clean up.
So, I think that that’s the way that we’ve approached it, is to try to forecast the wells in these areas like the Rodney Robinson or the Stateline in that way. And we’ll see what happens. And as we have more actual information from our own wells, we’ll modify things accordingly, if we need to. But that’s probably the best answer I can give you in terms of how we’ve approached it.
Yes. John, this is Matt. I’ll just tag on to what David said there in regards to the scheduling for 2020 and these longer laterals. While we didn’t on a percentage basis drill -- most of the wells were shorter laterals in the past, we have present at well north of 20, the 2-mile laterals that we have drilled in case and got another 10 or so in progress, and we’ve successfully completed about half of those. And knock on wood, we’re having some good success there. I think, one of the things that we did in preparation for these 2-mile laterals, it’s really paying off as these rig modifications that Billy and his team did, including the high torque top drives and the big pumps and the high torque drilling systems, really started to pay off. We’ve got -- one example is, here just recently we drilled well over 4,000-foot of lateral in (1) 24-hour period. So, I think the team is off to a really good start. The MAXCOM team is growing in there too. And that 4,000-foot -- it’s close to -- actually closer to 4,100-foot that we drilled in (1) 24-hour period. 100% of that was done in zone. So, the drilling team continues to make great efficiencies. Chris Calvert and Cliff Humphreys on the completion side, they’re doing the same thing there. We’ve got built into the plan these efficiencies for drilling -- or drilling and completing these multiple well pads. And so, I think the team is really off to a good start on these longer laterals.
Billy, go ahead.
Also in the MAXCOM room and Patrick Walsh and geology, using the big data technology, working with our non-op group, we’ve also been watching others go out and drill 2-mile laterals, our partners and all. So, we’ve been able to see the good and bad and what’s going on there. And they’ve been able to use that to also help us from running into those same little bumps along with our experience with over 20 2-mile laterals now as well.
John, this is Brad. I’ll just add one piece. These are conversations about the uplift that you referred to that we have on a regular basis with Netherland Sewell, our reserves auditors. And so, we look at that very carefully. We look at, as David mentioned, on analysis of all the surrounding wells. We’re doing statistics, the EUR distributions and things like that. And we’ve come to agreement with our reserves auditors on what those are, because they vary, as you can imagine, Bone Springs is different than the Wolfcamp A, which is different than the Wolfcamp B. And so, we do look at that very carefully.
Thanks for all that info. And then, just the follow-up question, I appreciate, the commentary and details you all provided on the on the ESG front in the release. And with what’s going on with the additional investments at San Mateo, the large diameter oil pipe that will be operational late summer. Can you give us a ballpark idea of the -- how much oil will be on pipe at the end of the year relative to the 55% that’s transparently a pipe at the end of ‘19?
I don’t know if I know the exact number, John. I think that certainly, we would expect that -- right now essentially everything that comes from Rustler Breaks and from Wolf is on pipe? We’ve got this will -- everything from Stateline will be on pipe; everything at Stebbins at that point will be on pipe from the Greater Stebbins area. I believe that would only leave maybe a little bit of our production, which is a fairly small volume up in the Arrowhead area. And that would be maybe still being trapped. And there might be some in Rustler Breaks. Although, we’re working on options to get more of that on pipe as well. I think it’d be fair to say that we could probably be between 70% and 75% of the oil on pipe by the by the end of the year.
And, John, this is Matt. I think, one other thing that’s important there is the amount of water that we’ll have on pipe. So, where we’ve got these big drilling activities at Stebbins and Stateline and Rodney Robinson and other places, we’ve got everything set up where we can put most if not all of that water on pipe. So, we’ll be well north of 90% for 2020 that will have water on pipe as well.
I think looking forward into 2021, John, those numbers should increase as well. So, I think we feel that we have the potential to be better than 90% on pipe by -- in 2021.
Thanks, everyone. Congrats on the quarter.
Thanks John.
Thanks, John. One other thing I’ll just mention, while we’re on this ESG topic is we’ve always had an active ESG program. It’s getting renewed focus. And of course we’re trying to continue to step it up. I’d also like just to know that Billy and his operations group have logged zero lost time accident since 2017. And no employee injuries have been recorded since 2014. So, kudos to Billy and his group.
Thank you. Our next question comes from the line of Neal Dingmann of SunTrust. Your line is open.
Good morning, Joe and team. Joe, my first question centers on your Stateline area. It sounds like the plan now is to drill even more initial wells in the play before completing all of them shortly. I’m just wondering, is this increased plan a result of new confidence you all have in the play with the increased multizone development or is there anything else we can read into this?
I think that -- this is David, Neal. Good morning. I think that what we decided as a team, what the technical team that works at Stateline had put forward for consideration was the fact that we feel strongly that it would be best to drill the Wolfcamp A-XY and the Wolfcamp A-Lower sort of the greater Wolfcamp A formation and to sort of co-develop that, if you will, get -- I think we have more concerns about if we have any, with regard to drainage impacts or shut in impacts or things as we go horizontally across this play as opposed to this acreage as opposed to vertically. And so, although we always knew we were going to drill the first nine wells, the team came to us and suggested that we ought to bring a couple of the other rigs down and drill out the remaining Wolfcamp A-XY and A-Lower locations, which was fur additional locations on the boroughs wells and complete all those at the same time. That seemed like a quite a great idea to us. And so that’s what we incorporated into the plan.
And so, it’s just an effort for us to -- it’s just sort of consistent with our philosophy about how to develop this asset area in the most prudent way possible to make us the most money possible. And this is what we thought made a lot of sense. And so, as a result, that’s what we’re going to do. And that’s why you saw the increase in the initial well count from boroughs being 13 instead of 9 in September.
Very good. And then my second question focuses on San Mateo. You all suggested in the release that the facilities expansion of last year’s initial footprint should be completed by late summer. And I know John was kind of alluding to part of this. I’m just wondering, after this point, Joe, do you all foresee material amount of third-party business in addition to obviously Matador benefiting from this?
Yes. The third party is very important and the team has done a good job of developing relationships with the quality companies out there to provide third-party services. And that’s worked very well. I mean, we feel like we really have some very strong companies that are long-term and are they kind of people you really want to work with and importantly can pay their bills. The second thing and on building that relations with and what’s pleased to us is that firstly all of them have increased their business with us since the time of the first contract. So, all those relationships in the San Mateo have been expanding, which I think bodes well going into future. But, our guy’s been hitting the streets and continuing to develop the relationships and look for additional business.
And that’s why the plant’s grown from its original output, taking care of what we had in Rustler Breaks to something’s going to be 0.5 billion cubic feet of gas a day. And the marketing group’s been working hard to develop options and interconnect points and working out deals with other companies that are downstream. So, it’s really worked. And then, a shout out to our partner, Five Point has really contributed to this and help make everything work. And we appreciate their point of view and the suggestions they’ve made operationally and financially. And I think that has also accelerated the growth.
Just to add what Joe said there. I think, one of the things that we take a lot of comfort in is when we do these experiences for -- going all the way back to when we first started the midstream business, there is always an opportunity base. We’ve never done the building and they will come model. I think with San Mateo 2, what we’ve done here is expanded this business, based on volumes that Matador can and will provide, and that makes economics work. But, if you’re looking at the map, we’re going to 15 miles to the north and about 25 miles to the south with this expansion. And along those paths, there’s a lot of great rock, a lot of good operators, they’re going to drill good well. So, I think the challenge for the San Mateo team -- and I they’re going to respond to this challenge very well is to add some third-party volumes along that pipe, which will make economics even better.
Thanks, guys. Look forward to all the activity.
Thank you, Neal.
Thanks, Neal.
Thank you. Our next question comes from the line of Sameer Panjwani with Tudor, Pickering, Holt. Your line is open.
Good morning, guys. So, last quarter, you highlighted getting below 1,000-foot of D&C in Antelope Ridge. And just wanted to see if you had an updated number for leading edge cost. I’m just trying to see how to maybe frame potential downside to the 2020 expectation of $1,025 a foot.
Well, again, I think -- Hi, Sameer, it’s David. I think that the $1,025 that we put out there is already down 3% or 4%, I think from what we had in the fourth quarter. It does reflect some -- what we think will be some additional efficiencies and cost savings in 2020. So, I think that when you think about that number being a little over $1,000 a foot, I think you have to think of it also in terms of kind of where the wells come from. If you’re a Wolfcamp well, you’re probably a little more expensive on the cost per foot basis than if you’re a Second Bone Spring well. I think that a couple of wells that we highlighted last week is getting -- the last quarter, excuse me, is getting below $1,000 a foot were the Second and Third Bone Spring wells.
And so, I think that we’ll see a little bit of -- maybe just kind of put all that together, it averages out to a little over $1,000 a foot. But, there certainly will be, I think wells that drill in the Bone Spring that will be below $1,000 a foot. On the flip side, there will probably wells in Wolfcamp that will be little higher than that. But we will continue to work diligently I know throughout the course of the year to try to bring those costs down further.
Okay, okay. That’s helpful. And then, on San Mateo, things definitely look to be progressing well operationally. But, I wanted to get updated thoughts on how you think about the value of this asset. I know you’ve talked about, maybe a double-digit multiple over time here. What we’ve seen from recent transactions is somewhere near closer to like a mid to high single digits. So, I wanted to see if you have any updated thoughts there.
Sameer, I’m sorry. This is Joe. Could you kind of rephrase that question just a little slower? I was trying to write it down.
Yes, sure. So, on San Mateo, I think you guys have talked about 10 times or maybe higher on the multiple sides in an eventual monetization. But, what we’ve seen more recently and the market has been in that mid to high single digit EBITDA multiple for Permian assets. And so, I wanted to see if you guys had any updated thoughts on potential valuation or the thought process there had evolved, given what we see in the market recently.
Yes. Hey, Sameer. I think that we -- I’d say two things. Number one, I think we still probably tend to value the asset at around about a 10 times multiple that I think there’s real transactions that go for that; there’s probably been some that have been less; there there’s probably been some that have been more. One thing is for certain, I don’t think that we’re -- that today we’re looking to monetize San Mateo. So, that’s going to be a discussion probably for down the road. And I don’t know what the market will be at that point. So, I think again what we’re most focused on for 2020 is to complete the build out of the expansion that we started a year ago, which is going very well, going on time, on budget. And I’m confident that we’re going to have some very valuable new assets in the ground, come the latter part of this year, including two large frontlines, a $200 million a day expansion in capacity to our processing capabilities and additional local oil, gas and water gathering as well as a very nice oil transportation pipeline coming from the Stebbins area, down to our existing Russell Breaks infrastructure.
So, I think there is a lot of very valuable assets being created by San Mateo and that they are going to contribute greatly to the future of Matador. And at some point if we look to monetize those assets, I think that’ll be more of a discussion as to what multiples are at that point. So, I’m not -- it seems a little premature for us to be overly concerned about that at this point.
Yes. Sameer, this is Matt. And I think we’re at San Mateo -- I’ve got my San Mateo hat on that. I think we’re a bit unique in that space in regards to number one, we’ve got assets as David is saying that are new. I saw water disposal wells are new, the facilities are new, the plant’s new, it’s all this stuff is just a few years old at best.
I think secondly, this third-party base that the team has built up in the 30%, 40% range on San Mateo I is a nice step for us to be in. And like I said a little bit earlier, we will add third party to San Mateo II as well. I think also the strength of the anchor tenant at San Mateo, I’ take a lot of comfort that it’s Matador. And Matador continues to execute on their plan in a way that they said that they are going to execute and they are drill the wells and provide volume. So, I think that absolutely does warrant a little bit multiple.
The last thing, Sameer, I would just say that in evaluating the multiple, there is other factors about is the acreage dedicated or is it interruptible? What is the nature of the commitment, and then what other options you have? The interconnect -- do you have an outlet for the NGLs? And those are all factors that weigh in on that multiple. So, it’s more complex question. But right now, we feel we’re as well positioned as any. And the last thing is just the operational advantage to Matador of having the plants ready to hook up, so you’re not flaring when you’re ready to bring the wells on and the different options forward. So, you have to wait and see. Multiples vary according to special factors. And -- but I think if we -- anybody considers this, they got to appreciate that this has been built in the right way and they’re getting quality assets. And again, we’re opportunistic and would like for an opportunistic time, but I think David and Matt said it very well.
Thank you. Our next question comes from the line of Jeff Grampp with Northland Capital Markets. Your line is open.
Good morning, guys. I was wondering kind of sticking on some of the more complementary assets on with Matador. The minerals kind of royalty side, I think the release mentioned potential sale or joint venture type of structure. Was just kind of wondering if that’s still, I guess a potential goal or objective for you guys that’s actively being evaluated or is that a more kind of passive approach or just I guess hoping to kind of characterize how you kind of view any potential transactions for the minerals business in 2020.
Yes, Jeff. Yes. We have a same around here. We always reserve the right to get smarter. But presently, it’s active consideration because we see an opportunity if we could find a strategic JV partner to start a business, most like what we’ve done in the middle. Because we know these areas, we’ve got the data, we operate in wells, we control the drill shares with some. It looks like it’d be a good opportunity for a JV. And much like we did with Five Point, where you have a partner and you have a go forward and the notion is to build a mineral business. But we’re open to other ideas. But, we have a set of minerals. We can sell them part of that and then go forward and buy in these areas, we know we’re going to drill and there is good rock. And to add to that, while getting a more accelerated rate of return from our E&P minerals a more long term and get a bigger multiple. So, we see that as a basis for a win-win and thanks it’s worked out real well in midstream on that so you have a similar kind of structure. Now, we opened other ways to do it. But, we were thinking, if we could do that that would be attractive. And we’ve got go forward plan that puts us in some of the best rock and we’d like to add to what we have, and take advantage of what we have to address -- to mitigate the outspend plan as well as to generate more cash flow.
David, I don’t know if I said this -- but that’s the general -- I would say that’s the general idea, open to other ways to do it. Matt?
I think you said it well, Joe. I think it’s an asset that has a lot of optionality to it, which you can sell part of it, keep part of it. There’s just a number of transactions that you can do. And I think we just -- as we typically do, we’re going to look for the right transaction with the right people.
Does that answer your question, Jeff?
That’s perfect. That sounds good, looking forward to it. And then, obviously, pretty volatile start to the year here, I know you guys never want to have a kneejerk reaction. But, can you just talk kind of sensitivity, I guess, in terms of activity levels in 2020? And, if oil is at -- if see 45 or pick a number versus same period, just talk about, I guess your all’s comfort level with either keeping the six rigs or what that sensitivity could be if you wanted to kind of pare back at all.
Jeff, that’s a very fair question. The first thing, I always start out on a question like that is it’s not a single variable. What is the price of oil, you got to look at also what you did for that or the costs, do the costs come down proportionally. And that has a big determination, because you made money at a lot less than 50 as long as costs come down proportionately and look at your opportunities that with the volatility that’s another reason why we hedge to try to protect ourselves at about 45%, approximately, maybe a little more is a hedged on oil side. So, we think we’re pretty well protected for 2020 and we’ll see where it goes from there. So, we have -- and as far as the rigs go, we have six rigs, but these are on short-term contracts and that we have a couple of rigs, Bill, that -- correct me if I’m wrong, they could be released on 60 or 90 days to see if worse came to worst.
That’s right. We keep some of our rigs on a longer term basis and some of them shorter. And it depends on what we’re doing with the rigs. Like Matt mentioned earlier, we’ve beefed up some of the rigs with even more equipment and as we’re going through doing that, we keep changing the term on the rigs, but adding third -- top drive and certainly drill more efficiently and be better at these 2-mile laterals.
And the last thing, Jeff, is consistently through time -- I’ve been doing this 36 years, and consistently through time, you make your best rates of return and your most money from wells drilled in these more turbulent difficult times. Because if all goes up a $1, $0.25 of that generally goes to the landowner and only 75% goes to your bottom line. On the other hand, for every dollar of cost savings, you get the whole dollar going to your bottom line. So, when you look back over time, your most powerful wells are generally drilled in these more difficult times. Now, that doesn’t mean you just know that we would double our rig count, but it does mean we don’t panic and overreact to short term period of low prices. We just move ahead cautiously and at a measured pace, keeping our balance sheet in mind to make sure we don’t get over the skis. But it’s important to keep going forward. And also with your staffing, if we were to cut our rigs in half, a lot of our best people would leave. And so, what has been working for us is strategy that I mentioned at the first of the conversation was to keep going. We thought six rigs was the right size for our cash flow. And it seems to be working out that way because that line of sight is now visible to the free cash flow. And by staying with the program and drilling the good wells that we had and had to grow with our cash flow is continuing to grow. And we’re now in a position to see free cash flow.
And if we can make a deal on a couple of our assets, either the minerals or have an appropriate offer for some in the Eagle Ford or Haynesville, we’ll be even better off. Those assets in Eagle Ford have been very good to us, really got us started. But now, they’re relatively small part of the whole pie. And we could continue to benefit from the cash flow and the opportunity, but it also would be an attractive deal, if I were starting over. Those would be the kind of assets I’d want to have, a good cash flow, good return. There’s some upside. And it’s a little simpler down there, not as complex. You go down and hit to Eagle Ford turn right, drill your well, which they’ve gotten the drilling. Last time we drilled one, we did it in six days. So, it’s a great opportunity, but probably it would be something that we could make a good deal on and someone else could benefit to just be a better fit. David?
No. I think you said it well, Joe.
Please record that.
I wrote every word of it down, Joe.
Thank, Jeff.
Thank you. Our next question comes from the line of Gabe Daoud with Cowen. Your line is open.
I was hoping we could maybe just -- I guess on San Mateo, the 200 million a day expansion, how quickly do you think that plant fills up? I guess, I’m just trying to get a sense of what 2021 run-rate San Mateo EBITDA would be and CapEx for that year as well.
Well, look, it’s not going to be immediately full. I mean, obviously as we drill the first -- as we drill the first set of wells at Stateline, that will fill a nice portion of it. And then, when we put the body wells on in the spring of 2021, that will continue to increase it. I also think there will probably be some additional third-party volumes that get added to the system. And so, it will continue to ramp up from there. So, I don’t have in front of me exactly what our expectation for is, when that plant comes completely full. But certainly we expect the volumes to run.
I think, as you noted in the release, in the fourth quarter, we were -- there were days when the processing plant was already running at above 95% capacity. So, we think that is certainly something we’re going to need from day one, and will continue to -- will just continue to add to it as our volumes increase. And as I say, I’m sure there will be additional third parties that come along or other ways, that seem to be often covered in terms of finding ways to maybe even process third party customers or gas or get other midstream companies, things like that. So, I think that there’s a lot of optionality for us to begin filling that plant up.
Thanks, David. That’s helpful. And then, I guess just as a follow-up, the capital program this year, obviously a lot of exciting stuff going on at both Matador and San Mateo. And I guess if commodities do rebound, it’s somewhat of a move point. But at current drivers you’re looking at outspend for this year, you highlighted asset sales. But I was curious if you could maybe quantify through asset sales, how much of that outspend you do think you’d cover? Is it maybe 50%, is it 60%? Just trying to get a sense of balance sheet protection as you as you move through 2020?
Well, I think, I gave -- I don’t want to sound flip, but it’s like, somebody offers us for some of these assets. I think that we could go anywhere from covering a small percentage to substantially all of it, depending on what sort of deals that we’re able to make and going down the road. I mean, I think that both of the minerals and the Eagle Ford offer the possibility to cover a substantial part of outspend. And I think that that’s something that we would be very interested in doing. But, we want to just be sure that we get what we consider to be the proper value for those assets. But, we certainly are mindful of the need to keep the balance sheet front of mind. And it’s important to us. It’s something that we talk about all the time. And I think we did an excellent job of it last year in terms of -- I think a lot of folks at this time a year ago would have thought would have been in the high 2s, 2.8, 2.9, and we managed to hold that down to 2.3 through a lot of initiatives that we did, including selling some portions of the Eagle Ford and the Haynesville last year.
So, we are very much willing to continue to keep that front of mind and continue to do what we need to do, in order to manage the balance sheet and protect the balance sheet. We know it’s important, we know we have to do it. As to exactly what all that brings, I think that we’ll see as we go along.
Yes. Gabe, the other thing, just keep in mind is that our bank renewed our line of credit at 900 million and we currently have 225 million drawn. So that means we’re not going to have any fore sales or anything like that and that we have flexibility on the timing. So, the important thing is not to sell too cheap or expect too much. And consider the other alternatives and what the price of oil that if you’d had a little better price of oil last year is what you had in 2018, we wouldn’t have announced then, largely, a very small one. That was pretty much our difference. So again, in your question, you got to take into account what is going to be the oil price, and it’ll trend down and it’ll trend up. The political risk of the Middle East I don’t think is necessarily factored in.
So, we plan to work on it diligently but we also with the banking that we have from our banks, that we don’t feel we have to do it and we feel we have even other options from that. And our growth is we have the drilling incentives from San Mateo coming up. You’ve got -- we’ve sold bits and pieces of the Eagle Ford and the Haynes this past year, not got a lot of attention to it. But we’ve recovered different money in different ways. And to the extent that it is a low oil price, you’re going to have better cost. And there’s savings on cost, as we’ve mentioned, capital efficiency, just the cost and sales, the fact that infrastructure’s built out there on the roads and the tank batteries and the pads. So, you know, there’s not just one way to close that gap and marking. [Ph] I think our group did a really good job marking. The Gulf Coast Express is operating, which we may be earning as much as $1 more firm that transportation or other tradeoffs. So, that’s what I would say. I know you have to screen and have your deal, but there’s -- should be an algorithm for these little ways to -- you chip away, but they add up over the course of the year. And that’s one of the reasons why we finish with 2.3 instead of 2.8 or 2.9 on the leverage ratio. So, good job to all the staff and not only increasing revenues but watching the cost side.
Definitely. Thanks a lot, Joe and David.
Thank you.
Thank you.
Thank you. Our next question comes from the line of Gail Nicholson with Stephens. Your line is open.
Good morning. Thanks for taking my questions. In the release, you guys talked about there were going to be some cost savings from -- using some existing infrastructure. Can you talk about how many wells in 2020 are utilizing existing infrastructure and how you think that changes over time?
Yes. Hi, Gail, it’s David. I think that you can pretty much -- you would pretty much think that the wells we drill at Wolf, and the Jackson Trust area are going to benefit from mostly existing infrastructure. Things that we do at Rustler Breaks are -- we’re already building out infrastructure in the Stebbins area. So, there’s going to be some infrastructure there that we’ll be able to take advantage. And anything that we do in Antelope Ridge that’s not Rodney Robinson, probably we’ll be able to take advantage of existing infrastructure. Certainly, the new areas like Rodney Robinson, there’s going to be new infrastructure built there; Stateline, there’s going to be new infrastructure built there. So, it’s a bit of a mix.
Gail, I’ll just add to that. This is Matt. I will just add to that too. It’s all kind of part of the -- as
David said earlier in the discussion that building these two businesses up together at the same time, each and every one of these little legs that we have to San Mateo to go out to get one of these new facilities is something that we can use not only to extend the Matador reach there or San Mateo reach to Matador but also for third parties.
Great. And then, just a housekeeping aspect. The potential of that $50 million to $60 million of incentive for next year, is that just for San Mateo II or does that include an incremental $14.7 million in incentives with San Mateo I incentives?
Yes, Gail. It’s both. So, it would be the 14.7 from San Mateo I plus additional incentives we would expect to earn from San Mateo II.
And do you think when we look at that $50 million to $60 million run rate, is that a good number to use to -- at least for the next several years, maybe ex San Mateo I as that rolls off after achieving the full amount there?
Well, I certainly think that -- I mean we’ll have ‘21 and ‘22, I think that would be a -- plus or minus $50 million is probably a pretty good estimate. I think that once you get into ‘23 and beyond the San Mateo I incentives will have been satisfied and will have rolled off. And so, maybe that number becomes more 35 or something in that ballpark. But by that time, we close everything that we’re drilling in Stebbins and Stateline is in -- there’s another AMI associated with that, where there likely be other wells drilled. And I think it’s reasonable to expect that those wells will come into that too.
One thing I would say, just to keep in mind, as you kind of are modeling that out. It will be sort of -- it’s predicated on when wells get turned in line, so when then they begin to produce. And so, it’s going to be subject to a little bit of the same lumpiness of the production. I mean, you will see that. Now the nice thing about it is, we get those paid on the San Mateo II side on a quarterly basis as opposed to annually. So, once we sort of clear this initial threshold to start earning those incentives, which we think will be toward the end of the year and start earning them into 2021, we will get them -- get paid on a quarterly basis. But, it won’t necessarily be that it’s going to be 10 million per quarter. It may be 15 million, one quarter and 5 million the next, and 15 million, the next. So, it will have a little bit of lumpiness to it.
Our next question comes from the line of Matt Sorenson with Scotia Howard Weil. The line is open.
Thanks for squeezing me in here. I think, based on all the questions there, you might have to start holding a separate call just for San Mateo. So, on the lateral length side, your 2020 program calls for a 53% increase over your 2019 average. I don’t think you’ll be able to continue to increase it 53% moving forward. But wondering if you guys could speak to your ability to either maintain that average or kind of continue to increase your lateral lengths in 2021 and beyond.
I think the way we’re thinking about this now is this is the new path for us forward. I think going into ‘21, ‘22, these 2-mile and 2.5-mile laterals are going to be even more and more the norm. So, I don’t know that you ever get to 100%, but I think there is a notion that we would be in the 85% range for longer than 1 mile and 75% or greater for 2-mile I think is pretty much what we’re looking at going forward.
Okay, great. Thanks. And then, just kind of a housekeeping one. I’m sorry if I missed this, but following up on a few of the mineral questions. About how many royalty acres do you guys currently own, I think the last number you guys referenced is maybe about 11,200 net royalty acres. Has that changed at all since then?
Well, I think that Matt -- this is David, that’s still right in the ballpark. So, I think that’s still a good number.
Thank you. Our next question comes from the line of Richard Tullis with Capital One Securities. Your line is now open.
Thanks. Good morning. Two quick ones for me, Joe and David. Looking at the 2020 production guidance, roughly what level of contingencies for downtime, just the move to the longer laterals, et cetera, do you have factored into the guidance? Is it more contingencies than what you’ve done in the past or kind of similar?
Richard, it’s David. I think that it’s probably -- I would say, it’s probably reasonably consistent with what we’ve had in the past. I will say that it may tend to be a little bit higher from just from the standpoint that we do have in some of these bigger pads and more wells, there’s a lot of wells being completed at the same time. And one thing I can tell you for sure is that it’s all been very -- it’ been very meticulously thought out and -- in terms of how that’s going to work and how those are scheduled. We don’t typically just say, we think it’s going to be X percent and then -- and just model that flat across the board. It’s modeled very much with the timing component as well. So, our teams are charged with and doing good job, I think of actually figuring out as they have new wells coming on and operations in their areas, what has to be shut in, trying to anticipate what other operators in the area are going to be doing. And so, we do try to put a little more science to it. I think that it’s usually about 2% to 3%. And I would imagine that’s about where it is on average for this year. But that doesn’t mean that it’s just linearly that. It probably changes from quarter to quarter.
That’s helpful. Thank you. And just lastly, David, earlier in the call new asset areas were mentioned. I just wanted to verify that that comment is related to the Company’s existing acreage portfolio. Is that correct?
Yes, it absolutely is. I mean, Richard, I think when Joe mentioned the new assets, he was referring to in particular the work we’re doing on the Rodney Robinson area, the work we’re doing down in Stateline. And certainly we feel like that there are other areas of our existing Delaware portfolio that offer a lot of future potential for Matador. But when we’re talking about new assets, you don’t need to anticipate that we’re announcing -- we’re about to go into Utah or something like that. So, we’re talking about just being right where we are there.
Yes. Richard, this is Joe. And I want to emphasize, yes, we got a very full plate where we are right now. When we talk about new asset areas, we’re really talking about different zones. There are more zones opening up all the time. When we went out there, we thought we had about three zones five, six years ago, and I think we’re producing from 16 or 17 different zones. And the final point that I really want to make on that is we haven’t talked about the MAXCOM room. But that’s been a very important part of our success is that the in the MAXCOM room, we have on real time room run 24/7 by engineers and geologists here at the firm that runs 24/7. It’s looking real time what each of our rigs are doing. And within each target zone, there is generally a preferred zone that you want to stay in the middle of that preferred zone because you’ll get more reserves, better permeability. And if you can do that, you’ll have more productive fleet. If you were to drill out of zone, or even out of the preferred zone, whatever -- if you drill out of the zone, you might be getting nothing back. Whereas if you stay in the preferred zone, that’s more than even in the rest of the zone. So that’s generally a smaller target 15 to 30 feet. But if you stay there, you’re going to have a better than expected well. If you drill out of zone, you may not get something.
Now in old days, the guy might suspect, after on the ring that he was out of zone, but by the time he calls, it could have been several hours, and then you got to redirect it back in the zone. And you’ve lost that much of the productive interval in the well. We cut that down. So, we’re saving money and adding reserves on every well we drill -- been drill since day one. And we would like to invite all of you to come in, get to know us, we’ll have lunch or dinner and take you down there. And you can see and it’s dramatic what they’re accomplishing on there, and one reason why these are leading to better wells. And just kudos to the operations group, the engineers and geologists working on that, but they’re delivering the results. Billy, do you want to add to that?
Yes. Sure, Joe. That’s exactly right. This MAXCOM and big data, that’s something that was needed back in the 80s or 90s. You’re just trying to stay somewhere in a particular formation and in the 2000s you’re trying to drill a 1,000 foot a day and you’ve narrowed it down a little bit to part of the formation. But now, we’re drilling 100 and 200 foot an hour, 4,000 plus days in the lateral and we’re keeping that in a smaller target formation. And I mean, there’s no way you can do it without MAXCOM and all the different software, big data they’re using. It’s amazing. They just keep getting better and better and working with the providers of that service to find different ways to make it better, watching all the offset wells. And it’s all real time. It’s not like it used to be like you’re getting data from the wholes wells and pulling it up after you’ve already drilled that. I mean, they’re watching out front; they’re comparing the other wells that they drill next to it and other operators drilled. I mean, this is getting after it.
So, we’re not the only company with such a room, but it is something that adds to your efficiency, saves money and adds to your reserve base. And we see it make a great difference and want you all to see it. And that’s why these results have -- we’ve been able to generally report better than expected drilling results and costs because this is contributed and it has our geologists and engineers working together to make it more tightly integrated operational effort but more of a team concept that we try to emphasize around here. So Richard, I think you were the last guy to ask questions. I was hoping somebody had asked me that. So, I just thought I’d jump in on the end of your question period and put it in that plug for our operation people.
No. Happy to lend a hand, Joe. I appreciate all the comments. Thanks. Thank you, Billy.
Thanks, Richard.
Thank you, ladies and gentlemen. This ends the Q&A portion of this morning’s conference call. I’d like to turn the call over to management for any closing remarks.
I think I made them. It’s been a great team effort. It’s fun to have your best quarter, fun to have your best year. I would like to simplify the life a little bit and they have a few of the other difficulties. But, things are going well here, proud of the effort and looking forward to what we can deliver -- value that we can deliver for you in 2020 and 2021. And, I’m pleased that we can say with confidence that by this time next year we think the free cash flow standard will be clearly seen and very close to where we’ll be as a Company. Talk to you later.
Ladies and gentlemen, thank you for your participation today. This concludes the program.