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Good morning, ladies and gentlemen, and welcome to the Second Quarter 2020 Matador Resources Company Earnings Conference Call. My name is Valerie, and I will be operator 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 August 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. Schmitz, you may proceed.
Thank you, Valerie, and good morning, everyone, and thank you for joining us for Matador's Second Quarter 2020 Earnings Conference Call. Some of the presenters today will reference certain non-GAAP financial measures regularly used by Matador Resources in measuring the company's financial performance. Reconciliations of such non-GAAP financial measures with comparable financial measures calculated in accordance with GAAP are contained at the end of the company's earnings press release.
As a reminder, certain statements included in this morning's presentation may be forward-looking and reflect the company's current expectations or forecasts of future events based on the information that is now available. Actual results and future events could differ materially from those anticipated in such statements. Additional information concerning factors that could cause actual results to differ materially is contained in the company's earnings release, and its most recent quarterly report on Form 10-Q.
Finally, in addition to our earnings press release, I would like to remind everyone that you can find a slide presentation in connection with the second quarter 2020 earnings release under the Investors Relations tab on our website.
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, and thank you for participating in today's call. We appreciate your time and interest in Matador very much. Similar to last quarter, we have prepared a set of 8 slides identified as the Chairman's remarks. Slides A through H, to add some color in detail, which many of you seem to indicate were helpful.
So we're going to try it again. You can find these remarks on our website, and I'll begin with Slide A. The -- yes. It's appropriate that we have slide some paper around here as --because the second quarter of 2020 has been much like that challenging and chaotic. But ultimately, we get to the results and the results for the second quarter were better than expected, as we noted in Slide A. The Board and I would like to thank and commend the entire Matador team in the office and in the field for their continued strong execution and professionalism, despite all the recent challenges of the novel coronavirus and the abrupt decline in oil prices. Consistent with our updated plans for 2020 is provided in early March, we reduced our operated drilling program from five rigs to three rigs during the second quarter, and we continue to focus on capital discipline and operating cost control to further reduce our outspend.
As a result, despite the challenges in the chaos that we faced in the second quarter of 2020, Matador delivered record high oil production, along with record low unit operating expenses and drilling and completion costs per lateral foot, which should help us attain free cash flow by the end of the year. We were heartened by these promising results. Throughout the second quarter of 2020, capital efficiency, operating cost control, and increasing the number of our eight plus locations were key objectives. Our operations group once again led the way in this effort by achieving better than anticipated capital cost and operating expenses.
Our capital expenditures for drilling, completing and equipping wells in the second quarter were $19 million less than our original estimates for the quarter. And we estimate that $10 million of these savings were attributable to improved operational and capital efficiencies and lower than expected drilling and completion cost.
Drilling and completion costs for all operated horizontal wells completed and turned to sales in the second quarter of 2020, average $881 per completed lateral foot, an all-time low for Matador is illustrated in slide B.
On the five Ray wells completed and turned to sales in the second quarter of 2020, all two-mile laterals, we did even better, averaging drilling and completion costs between $750 and $850 per completed lateral foot. Operating expenses in the second quarter of 2020 were also at all-time lows for Matador. Lease operating expenses on a unit of production basis declined to $3.92 and per BOE in the second quarter, resulting primarily from our continued efforts to reduce costs and improve efficiencies in the field.
General and administrative expenses on a unit of production basis were $2.21 per BOE, also an all-time low for matador as the salary and other cost reductions voluntarily implemented in the first quarter of 2020 were more fully realized during the second quarter of 2020.
During the -- further, during the second quarter of 2020, we achieved the second of four important production milestones we set for Matador back in December of this year. When the five Ray state wells in the eastern portion of the Rustler Breaks asset area were turned to sales in May and in early June, slightly earlier than we had planned.
As recently reported in a separate press release, the 24-hour initial potential aggregate test results for the five Ray state wells were approximately 7,600 barrels of oil per day and 29.5 million cubic feet of gas per day. As we all know, 24-hour test can be a little erratic, but these wells have continued to perform very well. And I want to emphasize that they've led to better than expected results. After an average of about 55 days on production, these five wells have already produced an aggregate of 500,000 BOEs. The six Rodney Robinson wells also continue to exceed expectations, having already produced in aggregate more than 1.2 million BOEs in just over 100 days of production.
The early outperformance of the Rodney Robinson and the Ray state wells in the second quarter of 2020 contributed to Matador reporting record oil production in the quarter, even though 10% to 15% of our potential production was Chadian curtailed during the months of May and June. Matador believes it has hundreds of more of these eight-plus caliber wells in its drilling inventory and building up these number of eight-plus wells is very important to our future, and it's a major company and staff.
Looking to the third quarter, we are very excited by the outlook for Matador. Going forward is illustrated in slide F. First, we expect to achieve the third and fourth of the key production milestones, mentioned earlier, for 2020, as we had earlier projected.
In late July or August, the five Leatherneck wells in the Greater Stebbins Area, all 2-mile laterals should be turned to sales. Then in September and early October, we expect to turn to sales the first 13 bore wells, also all 2-mile laterals in the Stateline asset area.
Second, the San Mateo to expansion in Eddy County should also be completed in the third quarter of 2020, including the addition of an incremental 200 million cubic feet per day of design natural gas processing capacity in the large diameter pipelines connecting the Stateline asset area and the Greater Stebbins Area to San Mateo's Black River processing plant in Eddy County, New Mexico, covering 43 miles.
These projects reflect the vision, planning, execution and hard work of the Matador and San Mateo teams to achieve the goals, Matador set as part of the Bureau of Land Management lease acquisition two years ago, in terms of production and reserves growth, midstream expansion and improved capital efficiency.
And I want to emphasize that this has been a very active two years in planning these events, and it's very encouraging and satisfied to see that these events are coming off as planned or better than planned. Financially, we were pleased with the recent upgrades by Moody's investor service to our corporate credit rating, unsecured notes and rating outlook.
We have continued to protect our balance sheet and liquidity while achieving these plans and ended the second quarter with outstanding borrowings that were $10 million less than anticipated in a leverage ratio of 2.5%, just as we had expected, and still well below our reserves based loan covenant of 4 times.
As shown in slide G, we expect to generate free cash flow in the fourth quarter of 2020, and we plan to use the excess cash to reduce debt outstanding under our revolving credit facility.
In addition, we continue to be pleased with the growth of our financial and operating results compared to our industry peers on Slide H. The Board, the staff and I look back on the second quarter as yet another time when we came together, kept our focus, executed on a revised operating plan, and delivered strong results for our shareholders and bondholders in a very difficult operating environment.
We appreciate the support of our shareholders during this time and we remain confident the outlook for Matador is very bright and we look forward not only to completing 2020 on a high note, but also in the years to come.
So with that, we'll turn it back over to Valerie to take the questions on the line. Thank you.
Thank you. [Operator Instructions] Our question is Scott Hanold of RBC Capital Markets. You may proceed.
Thanks and congratulations on second quarter. [Technical difficulty]
Yes. Hey Scott, this is David. I think that I think we're pretty optimistic about the Boros wells. I would point out that we began drilling the Boros wells back in January. So, some of the wells were certainly drilled prior to the coronavirus and the oil price decline and maybe some of the service cost declines that we anticipated. But certainly, they've all been fracked during a time when the completion costs were particularly low.
So, I think that we're optimistic. The wells went well. I know that the operations team, Billy and his group actually set a number of records for Matador during that time in terms of portions of the wells drilled. I know they drilled more faster than what we thought that they would. I think in the last -- or in the current investor deck, we even highlighted the fact that our drilling costs were a little below our expectations on those wells.
So, I think that we're optimistic that that they'll come in pretty good. I don't know that they'll be quite to where the Ray wells were, the Ray wells of course, are in an area that in Rustler Breaks, that's a little shallower. These wells are a little deeper. But nevertheless, I think we're optimistic that we're going to see some pretty good numbers on the D&C costs on those wells.
Yes, Scott, this is Matt. Just to tack on what David said there. I think what the operations team did a really nice job of and not just operations, but land legal, everybody getting ready for these longer laterals.
We've talked in past quarters about the additions that we made to the rigs, the high torque -- high horsepower top drives, a number of things that we worked with Patterson and getting those rigs ready for these longer laterals are really coming to fruition now.
So, we've just -- recently, this is just one example of that. We recently had a bottom hole assembly run, which is one motor, one bit, one trip in the hole that we drilled over 12,000 feet. So you're approaching 2.5 miles at that point. So I think it's reflective of the preparation that the team did in order to get ready for these longer laterals.
Scott, one other thing. Last year about this time in the fall conference that we went to, we emphasized that Matador was in the midst of a capital efficiency change and a capital efficiency story. And I think you saw it come out last year while we boosted our number of wells that we were drilling more than a mile from like 29% to something like 83%, and this is a continuation of that. And that's one thing, the Bureau of Land Management acquisition enabled us to do to accelerate that.
And you're seeing the dramatic drop in cost per lateral foot and rise in productivity from being able to execute on that. The MaxCom room that we have here working with a combination of geologists and engineers going 24/7 has added to that efficiency and that those cost reductions, while still improving the wells by staying in zone longer and being able to drill further and quicker than you were before. So all this seems to be working together, glad that for it to be coming together, and I think you'll see that continue for the year ahead.
Okay. And just to clarify the -- on the target of $900 is that a good number to think about going forward on some of these -- future longer lateral or you think it [Technical Difficulty]
You know, Scott, I think we'll do better. So I really do believe that you're going to see us continue to deliver strong results with regard to our capital efficiency in dollars per lateral foot going forward. So I think for the rest of this year, anyway, $900 is sort of the top end of things, I think we'll do better.
Now, Billy, I don't want you to fill any pressure of that remark. But we do, Scott, we expect to do better. I mean Matt does. All of us here are at comp, when price of oil goes up, service costs are going to go up. But for the foreseeable future, I think Billy and his group and the MaxCom group will continue to improve on that.
Yes, Scott, we're -- sorry, Billy.
Got ahead.
We're really excited about what we've got coming forth. I mean, once you get started drilling these 2-mile laterals, Billy and his team are going to get more and more efficient. I mean they just are -- they're setting records. Joe was talking about the MaxCom room. Some of the other functions that team is working on or working on torque and drag models. So prior to going into these wells, they run a model, it suggests what our torque and drag profile is going to look like. And then we monitor that as we go along through that drilling process and make changes as we need to.
So I think all this is just a lot of preparation to get to the $900 per foot. I think if you contemplate that it's a mixture of service cost reductions and drilling efficiencies, obviously, the drilling efficiencies we keep regardless of whatever the service price is. So if the commodity price goes up to a point or actually, it's probably more related to activity.
The rig count in the basin in March was a little over 400 rigs. It's about 125 now. And so we've got lots of room, I think, in the rig activity where our service costs will stay there. In addition, we've kind of locked in a lot of those costs. In fact, on the completion side, it's 70% to 80% of the completion costs are locked in for the remainder of the year. So that's in a good position. But even if commodity price goes up, service costs go up, our revenues will go up. We'll maintain those efficiencies.
And Scott, one other thing I'd just like to point out, and I'm sure you're aware of it, but most of the shorter laterals in our program for 2020 are behind us now. We achieved the $881 in the second quarter with sort of like a mix of sort of half 2-mile laterals and half less than 2-mile laterals, with the exception of just two wells going forward.
Now every well we turn in line, it's going to be a 2-mile lateral. And I think the 2-mile laterals have all had a little a little extra dose of capital efficiency. And so given the fact that, that's where most of the turn-in-lines are going to be for the rest of the year, that's why I think we're optimistic you're going to continue to see good numbers.
Also to add on a little bit more. This is Billy Goodwin. We're doing things a lot more efficiently out there. We've got engineers out in the field now helping out with each part of the business that we moved out, and that's helping us out a lot. Those guys are getting better right their hands on in the field, close to the wellhead, making improvements, but also a shout out to the service companies and vendors, contractors we're working with because they're also getting better at what they do and getting more efficient, improving technology.
We just keep getting better and better. So as costs start coming up. We're getting better all the way around us and the people we're working with and a shout out to Patterson, their frac company, Universal, Directional, MS Energy and Halliburton, Schlumberger, all these companies have gotten better and better all across drilling, completion and production department to help us out and get everything better, including our LOE.
Great. Appreciate that color. And as a follow-up. As you look forward, you've had obviously a lot of the federal permits you need develop the Stateline area as well as imports annual bridge. Could you discuss the midstream beside the midstream expansion and in the pace that you would actually develop this -- does the midstream maybe expanded that you are continuing to you know, get after in the Stateline area or [indiscernible] midstream?
Scott, it's David. I think the midstream part is going along extremely well. And we're as we noted in the release, we're nearing completion of the plant. There's a shiny new plant in Eddy County, and it belongs to San Mateo, and it's just -- it's getting very close to being ready to turn on and start testing. And I think we're very optimistic, as we said, that by the latter part of August, it's going to be ready to accept the new gas from the Stebbins and the Stateline areas, in particular, with regard to Stateline, the large pipeline is it's getting very close to being completed now and put together.
We're building out all the remaining infrastructure on the surface in the Stateline area itself, and that's all coming together. So I think we remain very optimistic that we've got to -- we certainly have all the all the permits we need for that, too, by the way, I mean, all the permits that San Mateo needs to get all of that wrapped up have been received, and we're moving ahead.
So I think we feel optimistic that things are going to come together as we thought, and we'll be turning those wells to sales in September and October, as we've laid out. And I think that the new plant gives us quite a bit of runway then for the development of Stateline. So as we continue to develop state line, we're going to have sufficient capacity with the midstream to be able to develop at the pace that we want to. So I feel like that that's all moving ahead very well.
Scott, one other thing or everybody listening in when the operator is speaking, and when you all are speaking, there's been an echo, and you're breaking up occasionally. So we may have to ask for a repeat of the question. We hope you're hearing our voice is okay, but you all are breaking up, through no fault of your own. I'm just if we ask to repeat this, for no other reason, we want to be sure we understand what you're asking.
Yes. No, I appreciate that. You heard the feedback from when the operator was talking. So I understand. But your answers are clear. Thank you.
Thank you, Scott.
Thank you. Our next question comes from Gabe Daoud with Cowen. Your line is open.
Hey, good morning guys.
Hey, Gabe.
Hey, guys. I was hoping to start with your liquidity position, you look so the fall, I guess, how do you think both the upstream and midstream credit facilities can change? And I guess, are you anticipating an increase to the San Mateo credit facility, just as you mentioned, on the back of the processing plant expansion starting up?
Well, this is David. Hi, Gabe. I'll start with that part of the question. So I think that the that once the merger between San Mateo I and San Mateo II is complete, and that's getting pretty close now that then the assets that were a part of San Mateo II will become party to the existing credit facility. And once they do, that will provide a lot of additional assets backing that facility. And I think we're optimistic that the lenders then who are party to that facility would entertain an increase. I mean, we've probably invested between Matador and San Mateo. I mean then five point, probably somewhere between maybe $250 million and $300 million in additional assets that we've built that are going to greatly contribute to an increase in cash flow going forward.
And so we feel like that the bank group would be open to increasing the size of the credit facility. But we do need to complete the merger agreement so that those assets can flow into the San Mateo facility. With regard to the reserve-based borrowing agreement, I think that we remain optimistic that we'll hold on to our borrowing base in the fall. Certainly, prices have come back nicely. And I think that, that will contribute to better decks being used by the bank group in the fall than were in the spring.
In addition, we've got a number of very exciting wells that are coming on and that will be in a PDP status by the time we probably initiate the fall borrowing base review. And in talking with our bank group, they've indicated that they certainly will take the initial results from those wells into consideration in looking at our borrowing base for the fall. And I also expect that we'll probably be able to book a fair amount of additional proved undeveloped reserves off of the results of those wells also. So I think, we feel pretty optimistic. A lot of it will depend, of course, as you know, on the bank price deck and where that is at the time. But, given where things are currently, I think we remain optimistic about the fall borrowing base.
Gabe, this is Joe. I just have two little points, I want to underscore. David gave a real good answer and -- but two little points that means something to me is: one, we were one of the first ones last year in February to undergo a redetermination by the banks. And we went through -- unanimously, there were 11 different banks, credit committees that approved it, 11 different reservoir groups that have approved it. And we were conforming loan all the way down to $35, fully conforming.
And since then, as David said, we've added more PDP. We've added more PUDs. They've been very supportive, led by RBC, very cooperative. All of them have been great to work with, very professional, and we're really proud of the bank group and the caliber and we're not anticipating any problems. But we also don't want to take them for granted.
And we're pleased with these reductions in G&A and in LOE and then our drilling costs, which improved our borrowing base numbers, but also want to give Scotia credit on the midstream, as they've been working hand-in-hand with us through the midstream expansion and very appreciative of their work, too. And on the midstream side is that, yes, we'd like an increase, and that gives us some flexibility. But our real aim is to get ourselves in position to start reducing debt. And being more free cash flow.
Great. Thanks, Joe and thank you, David. That's really helpful. I guess, just as a follow-up, just looking ahead to next year, you keep the three rig cadence, given the significant cost reductions that you guys have highlighted. How do you think capital trend next year? And then just alongside that, three rigs represent a maintenance-type program? Or does that equate to some oil production growth, either on an exit basis or on a year-over-year basis?
Well, I think that -- I think, if we maintain the three rigs throughout the year next year, Gabe, we still believe that we'll be able to grow our production, maybe in the low single digits, plus or minus 5%, let's say. I think, we continue to feel like that we'll see that growth.
I think, as we commented before, that's on a year-over-year basis as far as exit-to-exit. I think that -- I think we can be close on the exit-to-exit. I will say that the fourth quarter of 2020 is going to be a pretty difficult comp to beat. And it's going to be a good one.
Because of these wells that are about to come along at Stebbins and particularly at Stateline. And then I think that the next group of wells at Stateline, the [indiscernible] on the western side are due to really come on right at the beginning of the second quarter. And so that's going to be a very strong quarter, too, we feel like in 2021. So, I think we'll be close on an exit-to-exit basis, but we certainly will have another very strong quarter in Q2 of 2021.
And overall, I think we think that our production should grow next year even if we stay at the 3 rigs. And with regard to CapEx, I think we would expect to be probably in the $425, $450 range on those 3 rigs, some will depend before we get to next year on the kind of mix of wells we decide to drill, but that feels pretty reasonable to me. I'm sure there will be some additional non-op that we would have. And depending on what that is, that could impact our CapEx a little bit, but also our growth a little bit because when I'm talking about plus or minus 5% I'm really not considering much of a non-op program.
So if we have a little non up, that's going to add to it as well, and that might push the production up a little bit also. And I think with San Mateo, that we're thinking of next year as being a bit more of a maintenance CapEx year. And if that's the case, then I think that Matador's portion would probably be $15 million, maybe $20 million. And so we actually, as you know, are looking for San Mateo to be very positively free cash flow next year.
And so, I think when you consider the contribution of San Mateo to free cash flow, you consider the incentive payments that we'll have next year because, we'll continue to get the San Mateo I incentives. Those will be earned we'll receive that $15 million in the first quarter of next year. But then as soon as the BONI wells begin to be turned on, all the San Mateo II incentives, the $1 million per well that we get through San Mateo II is all going to kick in. And so, that's going to also contribute, I think we figure $25 million, $30 million potentially of incentive payments next year on the San Mateo -- on the -- on the -- from Five Point.
And so we'll have those incentives. We'll have free cash flow. I think that the E&P program will be getting itself close to free cash flow. But in aggregate, we feel like that we can generate cash flow. If we're in a $40, low $40s] kind of environment and anything that's $45 million or $50 million will be that much better. So I mean, I think that's directionally how we're looking at it. Don't beat me up too much if those numbers change a little bit here and there when we finally come out with guidance. But I think that should give you a pretty good direction as to how we think things will go.
Yes. And Gabe, just think that if you were at 50 instead of 40, we make the numbers work at 40, as we said, we're doing it now. But if we should be fortunate to for it to grow to 50 times the 13 million to 14 million barrels well produce. That's an additional 130 million; 140 million would change everything around. And even half that would make a great difference. So I think that outlook is pretty good going forward, and we intend to make the most of it at three 0rigs, and we plan to stay there for the foreseeable future.
Yes, Gabe, this is Matt. Just a couple of points. One on the E&P side, David was talking about with three rigs. We did see some single-digit growth and some capital efficiencies we go along with that. I think we'll continue to get better drilling these wells. So you're going to get more bang for your buck. And we're drilling these wells at a time where we're drilling them as efficiently as we ever have, and likely ever will. So that's a good thing. I think when prices do go back up, like Joe said, to fix charge, we're going to be really glad that we've drilled these wells.
And then just on the San Mateo side, once we get this expansion done, we'll be at almost half a BCF processing capacity there at the plant, and we're at 335,000 barrels of disposal capacity so -- a day. And so as we go forward, once we get this expansion done, we greatly expanded the footprint of San Mateo.
So it's, kind of, like the -- we're at a size now where we want to add third-party customers, we can go ahead and get contracts in place that support those economics. So it's not like we're -- and we never have done the build of an ABL come model, but we're greatly expand, like Joe said, another 43 miles of the footprint in the basin. So we're in a good position with San Mateo.
Great. Thanks so much, everyone for the color.
Thanks, Gabe.
Jeff Grampp of Northland Capital. Your line is open.
Good morning guys.
Hi, Jeff.
Good morning, Jeff.
I was curious, Joe, I think you might have just touched on it a minute ago. In regards to the free cash flow, kind of, objectives that you guys might think about balancing spending levels. I'm wondering, how important you guys view maintaining positive free cash flow as we look into 2021 and beyond? If there was a scenario where returns were just so good where you guys might think about adding activity levels is staying free cash flow positive, I guess, an overarching theme that you guys would look to maintain?
Jeff, we're a public company with public shareholders. We pay attention to them. And if that's where the value creation is, is to be free cash flow that leads to a better evaluation, then we're going to be listening to that. We're not in a growth for growth's sake. As Matt Haiford likes to say, we're for profitable growth at a measured pace. And we hope someday to go to three to four -- from three to four rigs, but we don't want to do it at the cost of evaluation or something that exposes us to too much debt.
I think that we are always try to be in balance. And I think the situation now comes from absent a very, very compelling opportunity. We're going to work on reducing debt. And now that the midstream is -- doesn't need the capital. It's an important part of that free cash flow. The rock that we're drilling in, that's why we emphasize these A-plus locations is strong enough to give us some growth without expanding beyond three rigs. The capital efficiencies we've achieved allow us to get more footage in without having to go to a fourth rig.
So there's no hurry until I think you're in a stronger price and economic environment to really give that a whole lot of thought. And so what you're going to continue to see for us is to find these efficiencies to take advantage of the midstream position and keep drawing this good rock, and we're adding A-plus locations all the time. As an example, down there in Wolf, we drilled a third Bone Spring carbonate that has added double-digit growth in A-plus locations in and around it. And we'll have more detail on that at our next conference call or through these conferences.
But we have always been -- I've been in the business 40 years. And we've always been -- say a stable the strong balance sheet, but we saw an opportunity, when we did the Bureau of Land Management lease acquisition to change -- to take Matador a step forward, to where it had more capital efficiency opportunities. And make it a capital efficiency story and convert ourselves from drilling 29% longer than two-mile laterals to 83%.
Well, that couldn't happen without it. Also, if we hadn't done that deal, we would have missed out on $175 million and incentives and capital contributions from our Five Point, our midstream partner. So that was a step-up for us and made us much more competitive. And helped us grow to number eight in New Mexico, in oil production.
So I think David has done a great job, in navigating us through here. And the technical team and give shout out to Glenn Stetson and Tom for combining with David and coming up with these programs that not only save money, but still increased production. So we'll have a little growth but now, it's the time to keep building up the balance sheet, but not stopping in our track.
So I think they put together a good program. We're beginning to see the fruits of it. And I think you'll have an even better report, as we bring in those Stateline wells. And we'll be glad we did that, at a time of low-cost, because these will become some of the most profitable wells we'll ever drill, even though they were born at a time of low oil prices.
But they're going to produce for a long time, just like the Rodney Robinson, early days, has produced over one million barrels of oil or gas equivalent. But they're going to remain out there for years to come, just like the Stateline and our other long-term wells. And that's why we like our chances.
Great, I appreciate that, Joe. And my follow-up, I talked on the 8-plus location. I'm glad you kind of ramping me there. Can you just talk about the opportunity set to kind of grow that, either through coring up lower working interest areas, extended laterals?
Or maybe like that third Bone Spring well you talked about where you're finding areas that are maybe better than you initially thought? I guess just, generally wondering the level of servicing you guys baked in there? And the opportunity set to grow for that?
Well, Hi Jeff, its David. Good morning. Look, I think we're certainly optimistic that we can continue to grow that. I think you've kind of touched on some of the things that are important to be able to do that. One, I think, is just part of the continuing geologic effort that has always been a hallmark of Matador's work in the Delaware Basin.
I think even in times like this, we've tried to continue to support the teams, the geoscience, and the asset teams, in their recommendations to step out here and there. And try to make yet another target work. The third Bone Spring was a case in point. And we went ahead and did that and got a very strong result from it. I think the Wolfcamp B, up in the Stebbins area is another case in point. That's pretty big step out relative to any horizontal well that's been drilled in the Wolfcamp B before. But our teams like the potential of that. And so we decided to go ahead and include 1 of those in this group of 5 Stebbins wells that we drilled. So that's a way that we'll continue to work on that.
And then on the land side, our land group continues to do a very good job of helping us to block up more of our acreage. I know that if you looked at a map between 2 years ago and today, you would see much more blocking as seen, you know, in terms of our key asset areas around Rustler Breaks around Stebbins, of course, Stateline, those kind of things that you can definitely see the blockiness improving.
And look, that's a lot of good land work. That's trading with others. Where we have things that make other operators work and they have stuff that makes us work a little better from an operating side. It's a good thing to do. It's a good thing to put together. And so, we're continuing to work on those things. And I think as a result, we're optimistic that we can make that number grow.
Yes, Jeff, this is Matt, and Ned may want to weigh in here. But I think our toolkit is getting better and better as we go along as well. So we've got seismic over the majority of our assets. And so the team is doing a nice job of identifying targets and staying more in target. So it's, again, back to the capital efficiency, the more we stay on targets, better our wells are.
I also think that just -- and this is just kind of a general statement, but success leads to more success. So the more that we're able to go out and identify which of these zones are working and making a plus locations gives us more confidence in what we might try next.
And then I think, again, getting back to the MAXCOM guys, and just the overall operational efficiencies, as you drive these costs down, more and more wells move into that A plus location because as you know, it's a 15% rate of return at $30 oil. So I think that number will grow over time even as we drill some of them up.
Matt, your group really has done a great job, and I want to give you the opportunity to acknowledge it.
Well, I appreciate that. As Matt said -- Matt and David said, we do have a broadly increased toolkit between the seismic and petrophysical work being done at Matador really is leaps and bounds beyond where it was a few years ago. Those tools really help us identify the best targets and hopefully grow that a plus location count significantly.
It also really helps on the execution, too. And I know MAXCOM has been mentioned several times here, but having the geologists and the engineers working side by side. Analyzing every well that gets drilled, relative to the seismic data, relative to the petrophysics, relative to the drilling performance, really helps us go faster and stay in better rock.
Great detail, but working CapEx.
Thank you. Our next question comes from John Freeman of Raymond James.
Good morning Dave. Good morning Joe.
Hey John.
[Technical Difficulty]
Yes, John we were -- that's a great question. And we've talked about it many times, and it's a constant deal that we're really proud of the way they're drilling them faster and making all the wells more capital efficient. And so it's hard to be really precise on the capital expenditures, because not only is it a high-class problem, as you're drilling them faster. But as you complete them that means, you've spend some more money, but you convert them to PDPs. So overall, you don't want to slow down on that. You do want to take that into consideration as you do your budget. And probably, this is a good time just to note that in the past, our production has been lumpy at times, as we brought wells on. It's going to be the same thing with cash flow in some respects as you do this pad drilling.
But overall, you don't -- you don't want to slow down your people from being more capital-efficient and say, go home for the month of December, we've exhausted our budget. You just try to leave yourself enough flexibility or cushion that you can take advantage of your groups being more capital-efficient, or picking up some non-op or interest that's good that's outstanding or picking up some interest in your wells from people wanting to make trades or other activities. And you just kind of have to manage it a little bit, and leave yourself a little bit of cushion, and that's why the extra liquidity we have with our banks is important, because that allows us to adjust the timing.
So it's more of a timing question, John. I think than anything else, you don't want to turn down or slow down your troops from doing that extra -- the good work, and I just -- when you have a guy like David, he's just putting more pressure on him. Make it all work somehow on the cash. David?
Well, look, I want to just echo what you said. I really think, John, that it seemed like there might have been a little bit of concern that we didn't reduce our capital expenditures, estimates for the rest of the year. And I think that, just what Joe said is very correct. I mean, for one thing, we still got five months to go in this year. So we'll see how that goes. I think we're optimistic it's going to go well. And there will be opportunities for us down the road. To reduce our numbers, if it looks like it's going to come that way, but I do know that, I do think that what's going to happen is we will see that as the group is drilling these wells a little faster, but there will probably be a few more operated wells that get spud right at the end of the year that, we hadn't counted on. So that could add some additional drilling dollars.
In addition, probably won't surprise you that we're seeing the non-op side of things, kind of beginning to tick-up a little and so even though we took our turn in line count down slightly. What that -- what we're really seeing is that some of our operating partners that we're in wells with have decided to go ahead and initiate drilling in the latter part of the year on those wells. But defer the completion into next year.
So there's a couple of wells that we thought would be completed next year, that were in -- this year, excuse me, that we're in our TIL count that we've kind of pushed into next year, but we still expect to have those wells getting drilled. And in fact, we expect that we'll have twp or three more wells that will be -- that may get spud on a non-op basis.
So maybe, we didn't -- maybe we didn't have a chance to get quite as clear on all that in the written release. So I appreciate your question to kind of allow us to expand upon that in the call this morning.
No, that's very helpful. And then just my follow-up question on the acreage trades that happened during the quarter. Were those concentrated in any one specific operating area for you all?
I would say no. I would say that they are pretty well diversified across our acreage portfolio.
And John, there not just initiated by us, but other companies. And the silver lining -- one silver lining to this COVID-19 and the price war is that everybody is trying to work on their capital efficiency and improve it. And so there's a lot more cooperation on data and trades and non-op interest and the like during times like this because everybody is trying to get better and people are helping. And as you cooperate and help, it just gets better. So that's made doing business a lot easier. And we -- you just find a lot of help is what I'm saying is people can be reached, returning calls because everybody knows that it's in everybody's interest to help each other improve their capital efficiencies.
Thanks a lot, guys. Well done.
Thank you, John.
Thanks, John.
Thank you. Our next question comes from Mike Scialla of Stifel. Your line is open.
Good morning, everybody.
Good morning, Mike.
If oil prices were to remain around $40 longer term, and you stay at three rigs. From a midstream perspective, with the 0.5 Bcf a day of processing capacity, is it fair to think that the $15 million to $20 million of San Mateo CapEx, as David mentioned, for 2021? Would that be a decent maintenance CapEx number for the midstream for the next few years? And I guess if that is the case, Matt mentioned third-party volumes, is there enough visibility there to fill the Black River processing plant?
Okay. Mike, it's David. I'll start and Matt may want to chime in too. But I would say with regard to -- is that a pretty good maintenance CapEx number for San Mateo, I think that it is. I think it's a pretty good maintenance number going forward. I also think that even with the three rigs, we had always anticipated having a couple of rigs running at the Stateline. So as long as we have two rigs running at the Stateline, that has a big impact and doesn't really change a whole lot, our outlook for San Mateo. Clearly, when we had six rigs in the program, we would have had a little more drilling probably in the Rustler Breaks area, for example. But some of that drilling was going to be in an Antelope Ridge, some of that drilling was going to be elsewhere, which wouldn't have had as big an impact on San Mateo anyway. So I think that the San Mateo volume growth should continue to be good even as we run three rigs. In addition, bear in mind that when we design this 200 million a day plant expansion, we did so with the thought in mind that over time, Matador would need pretty much all of that additional capacity. And so I think that it's not going to be tomorrow or right away. But with the continued development of Stateline, we think that, that capacity will be needed.
Now, I will say regarding the latter part of your question, when you ask does the $15 million to $20 million include third-party opportunities. The answer to that is mostly no. It would include maybe some small ones here and there. But if we had any sort of a significant third-party opportunity, what we've always said is that that would probably entail some additional CapEx but that we wouldn't enter into that kind of a deal unless we felt like it was well supported by volume commitments, acreage dedications, whatever we needed to make us feel very comfortable with the return on that capital.
And so that's the advantage that we have by having all that now is that we can kind of plan that way. So, I think if we make a bigger deal for a third-party -- a bigger third-party customer, which I hope that we're able to do, it will entail some additional CapEx, but it will also be part of a very well thought out business decision.
Yes, Mike, this is Matt. And David said it well; just I'll restate one of the things he said. When we put San Mateo II together, the only volumes we contemplated for the economics were Matador volumes. And so the idea was Matador is the anchor tenant will make this expansion fly, but we will have third-party opportunities on this greatly expanded footprint.
Also, one of the things that we do have an advantage with Matador having most of the reserve capacity in the San Mateo II plant is if a laser, Brian Willey and their team are able to go out and find some third-party volumes that want to come on sooner than later, we can bring them into the plant, Matador can temporarily release some of that capacity to a third party. And it gets to the point where we need to add another training, say, another $200 million, we would have the volumes again contracted before we would ever start construction on that. So I think we're in a really good spot on scale for San Mateo.
Great. And I wanted to ask on the federal locations that are permitted, I'm assuming the permits and progress are approved before a new administration were to make any changes, do you have an estimate of the percentage of your federal leasehold that could potentially go undrilled? And also wondering about the exploration on those federal permits?
Federal format. Yes, we put in the news release, a little information on that. But basically, is this, is that we think the chances of them saying you can't drill on your leasehold are fairly slim because that probably be it taking in the form of constitution, which there is imminent domain or whatever they do, but they've got to pay for it.
And particularly, if there's a permit there, I think they're going to allow you to drill it. The Federal Government is going to need the money. So, for leases already granted or permits already issued, I don't see much of a problem. And we put in the release that when we bring on -- just one of those BONI leases online, and we will have HBP 70% and of our federal acreage.
And the rest is soon to follow in this next two-year period where you have all your permits that are -- that have been issued, you have two years to drill the wells. So, don't see much risk there.
But the other thing that we've been trying to know is that we've Matador drilling program has a lot of A-plus wells that are not on federal leases. And we have explored the concept. What do we do if we had a whole year's drilling or two years drilling on all non-federal leases? So you have no federal leases, what would our drilling program look like. And that's the concept of that and the outline of that is already happening. And you've got to feel, have confidence in your geoscience group that if that were to occur, there's still plenty of opportunities out there. This is a basin 5,000 feet pick that just like we're finding new zones all the time when we came out here from the Eagle Ford, I spent almost my whole career out here, there were two or three zones that we were looking at. And now we're producing from 17 or 18 different zones. So there's a lot of opportunity.
One reason we were attracted to the federal leases at the time is our 87.5. So the net is a lot better. But don't think they're going to go away for particularly the lands granite and the permits, but additive to that are a lot of other locations we have on feed leases that are HBP and state leases that are HBP. We see those continuing.
So Mike, I think we're in pretty good shape. And we took that into account and have taken it into account. And I don't see much reason in New Mexico, the Governor, while Democrat has been very supportive to the industry, which we appreciate. And I think there'll be some changes, but I think we're nimble enough to change with them and keep up the caliber of our drilling program.
Sounds good. Thank you, Joe.
Thank you. Our next question comes from Neal Dingmann of SunTrust. Your line is open.
Good morning Joe. Just quickly, I want to [indiscernible] you guys put out an operations plan a quarter ago, and you certainly continue to hit those targets. That's until David added just one after that Joe you and your team have done a great job hitting all those targets. But my first question is really on San Mateo. David mentioned about that potentially coming online, the additional part of that coming online in mines. Taking the question to David and Joe, or you do you bring it closer to some sort of sale transaction for this or to quickly lower leverage? Or maybe just talk about M&A consideration on San Mateo once that's even ramps higher?
Neal, I'll take it first, and then David can bat cleanup. And I'd just tell you this is that we're a public company, and we try to play a straight game. If you look at the 40-year history of Matador, we sold first Matador. And then in this Matador, we sold a good part, the biggest part of our Painesville acreage to Chesapeake. We've done -- we've sold our first midstream plant to Enlink, and we brought in a partner for half interest on this San Mateo II -- on the San Mateo project.
So we've always played a straight game. If an offer comes in, whether the big or small, and we've sold off pieces of our Eagle Ford on a case-by-case basis. If it's a strong offer, we're going to give it strong consideration. We've always said that. And sometimes you have properties with Chesapeake or Haynesville or Eagle Ford or out here. That makes more sense for somebody else to have it. So we play a straight game. We're not out there with a for sale sign, because we see a lot of benefits to having a midstream program that's complementary to our E&P, and we're working very well.
Matt Spicer and his group, they're there with a pipe when we're ready to bring them online. We're not flurry. It's a complementary because that's a fee-based business to our E&P, which is a commodity-based business. So we feel at this point, it enhances, but we would consider but I tell the power kickers, they're wasting their time.
They need to come and be serious, and we'll listen, but we also see how it enhances. So that's the way we'd look at it. And everybody here has an opinion in the way we make decisions is we really get together and hash it out. It won't be something that I decide or David will be in the room and really talk about the pros and cons, try to be clinical and try to see what adds the most value for our shareholders. David?
I was just sort of reminiscing a little bit, Joe, as I listened to your answer, which I thought was great. And I was sitting here because Greg Craig is sitting across the table from me today, just by happenstance as he was, probably seven years ago, explaining what he wanted to do. And I can remember saying, you want to do what? With regard to building midstream.
And now, I look at him and Matt Spicer and James Meier and all the people, Matt Hairford, all the people at Matador, who've had such a an impact and a vision to bring San Mateo together and look at what it is now. I mean, my goodness, 335,000 barrels a day of water disposal, 13 state-of-the-art saltwater disposal wells, gas gathering, oil gathering, water gathering, a big water -- I mean, big oil transportation system, a big natural gas transportation system and almost 0.5 billion a day of natural gas processing capability.
Wow, I don't even think Greg thought it was going to be that, seven years ago. So I think that we're really very proud of San Mateo and the business and it's been and all the hard work that's gone into getting it to this point. And I'm so excited for just the next six weeks of time to run off the clock, so that we have all this stuff put together all these pipes that are just about to get screwed together to the plant and everything.
It's kind of like the 5 Bones are going to connect to the lead Bone, and we're going to start running. And I really just -- sorry to be a little old home week here, but it's kind of a cool time and something I think we're really excited about. And so we might sell it someday, but it's time for us to have right now.
What you think -- and Neal, you may remember this, we really got serious about the idea of building the midstream when we were on our IPO roadshow back in 2012. And because we're getting all these questions about transportation processing and we weren't having problems at that time, but it's clear, others were.
And so Greg has been a good friend of Matt and he worked here before. They went through a great school together in Hooker, Oklahoma. And Greg knows everything there is about the gas business. As he explained it, we started giving it a try a little bit at a time. It just built up. And now it's over $1 billion business. And it's only going to get more valuable as we bring this second plant on the line. So, it's a very exciting asset for us.
And I think, to Neal, just one last thought on it is it's provided a lot of operational control to Matador too. It's been really very integral to our ability to get wells on quickly and get things turned to sales more quickly, meet our targets. I mean, it's -- I think the coordination between the Matador teams, the San Mateo teams, the planning -- I mean, look, from the time we put together the current plans with regard to how we were going to develop Stateline and Stebbins and all this. The San Mateo was right alongside it in terms of how they were going to put that together and our partner Five Point as well. So, I mean it's been a very important part of our business.
Yes. Neal, this is Matt. I just add one more thing here, maybe a couple of things. I think it's -- the way these two businesses work together, I think, is unique for us. I mean we didn't put together a bunch of midstream assets and then sell them to somebody or even -- I mean, we started kind of crawling before we walked. Like David said, now we're running, but we're to the point now we're these two business lines really do work together.
I mean, from the operational efficiencies, like David was talking about, when you're putting on these 13 wells in Stateline, you want to make sure that your midstream partner is going to be there. You want to make sure that they're going to do what they say they're going to do. And we're certain of that. I mean same as it operates as an independent midstream company, but we're the anchor tenant, and we get a lot of attention from those guys and may need the volume. So, it's been really nice -- we've gone from, like Joe likes to say, in 2012, we have 400 barrels a day. Now, we're well over 40,000 barrels a day and midstream is the same thing. We went from maybe moving a little gas in the Eagle Ford to where we're at now. So, it's been a nice write-up on both sides.
No, definitely good to see all those bones -- go ahead guys.
No, go ahead. What are you going to say?
I would say definitely going to sell those bones connected, just as David said.
Thanks, but it has been an interesting, and that's one that been one advantage of being public. As you go on the road, you get these good questions, why are you going to do this? And what's happening here? And you hear about other challenges, that has made, I think, our business plan sharper. So, we appreciate your questions. We really appreciate your interest, and it's got a lot of value that isn't fully recognized in the market. It's like our Stateline and Rodney Robinson wells are really performing. And we released that on the Rodney Robinson in first 100 days, 1.2 million BOEs, and that this is good rock, and the teams are working together.
The outlook is good in either area, but I want to emphasize whether it's Haynesville or Eagle Ford or a midstream project, we're going to do what's best for the shareholders. As it's been pointed out many times by you and others, this management group has got a lot more skin in the game than virtually any other public company. I'm the largest single shareholder. And most of the senior group owned about 5 to 10 times what their counterpart and other companies own. So, we're shareholders too. And when Matt has his mother, mother-in-law involved, you see there's an added level of the visibility. It gets tricky as the Matt said it.
My quick follow-up. Just follow-on that slide 8, you talked a lot about the 8-plus locations. What's notable is not only how much in the various locations, such as Ranger and Arrowhead, but Joe has us had all the various formations based on this diversification, does this allow you to do much more -- just more development mode going forward and potentially see even lower cost because of that. Maybe just talk about the overall ops plan because this diverse inventory base now.
Well, hey, Neal, it's David again. I think that, I think where we have comfort is that, we have a lot of options and a lot of opportunities, right? We're currently focused on and have been focused on the work we were doing at the Stateline, at Robey Robinson, at Stebbins. There was a time two years ago when we were more focused in on the Rustler Breaks area, we probably will be again. There are parts of Arrowhead and Ranger that we've known for a long time. We're going to be good areas for us. But we -- that acreage up there tended to be more held by existing production, and so there wasn't quite the same urgency to sort of work through that as there was some of our acreage that wasn't as held.
But I think we've done for a long time, as I've said many times, that area was sort of the bread basket for the Bone Spring, and we knew we were going to have good second and Bone Spring targets all the way through there. Think back to our Mallon wells, when we drilled those a number of years ago. I think those wells are all getting close to 2 million barrels a day of reserves each. And so there's been some -- there are some really great wells that can be drilled up in that that part of the basin. And we've also, I think, begun to demonstrate that the Wolfcamp is going to work up in that area, too. So we're going to continue to -- continue to work through the basin. I just am comforted by the fact that I think that we have lots of opportunities, lots of good wells to go drill. As we've often said, we don't think we're an opportunity constrained company in any way. So -- and I wish we could be running six rigs today, because we'd have plenty good spots to put those rigs.
We have plenty of good spots, Neal, but I couldn't take all the questions we might get on that -- is ranking how we were going to pay for growth. So we're going to stay the -- and talk about our opportunities.
Very good. Thanks so much, guys. Congrats.
Thanks, Neal.
Thank you. Our next question comes from [indiscernible]. Your line is open.
Hi. Thanks for taking my question. Just looking at your bond prices -- your bond investors so $75 is getting a 25% discount. Has any thoughts been given to maybe buyback as you have still capacity on the credit facility? Even up to your CapEx plans?
I think that -- this is David. I think that one thing we've sort of noticed about how our bonds have traded through this period of time, is that they seem to kind of move obviously, they moved down and then back up. But the moves have been on fairly limited volumes. And I think that we are uncertain as to whether that we could if we initiated some sort of a buyback program that we would really be able to buy enough that would be of significance before it would potentially just cause the price to pop back up further.
So, I might be wrong on that. But I also think that we feel like that preserving liquidity has been important during this period of time. And it just didn't feel like the best thing for us to do at the moment. I suppose that could change with time. But for now, I don't think we have any immediate plans to buy back any of the bonds.
Great. And then just second question on leverage. How do you think about if oil prices remain at $40 oil, what do you think is the long-term leverage targets?
Well, I think that consistent with the way we can always run our business, we've always tried to have our leverage target at 2% or below. I mean, I think if you kind of look back over the history of Matador, we really didn't have much debt until just before we went public. And then after we went public, our debt-to-EBITDA was traditionally below 2%. I think the only time that it got above 2% was back in 2016 when prices were low again, and it got up toward 3%. And then as prices improved, we were able to bring it back down again. And I think we're optimistic that we'll see the same sort of thing here. I mean, I don't -- we had projected, of course, that we'll go above 3% before the end of the year. That's not where we would like to be. And as Joe said, we're going to focus on trying to pay down our debt and move our leverage back in the other direction. So I would say long-term that we would and the Board would probably be comfortable with 2% or less. Obviously, the lower we can get it, the better, of course. But I think that that's where we would be the most comfortable. Joe may want to weigh in on that, too. But I think that, that's sort of the way we've always tried to run things.
Yes, we want to lower the debt. Just as David said, we've always had a practice of being 2% or lower. The difference being the Bureau of Land Management deal, the BLM deal. That was a once a lifetime opportunity. If you didn't buy those leases then, you weren't going to buy them in your lifetime, yours or mine, then you may live a lot longer than me, but it certainly wouldn't be in my lifetime. And those are 12.5. And we've added so many -- I'm going to come up with a slide that shows that on the day we did that deal, we added hundreds of millions of dollars in PUD locations. It also set us up that if we hadn't done that deal, we wouldn't have done San Mateo II, which brought in $175 million into the company, a $50 million carry and the drilling incentives and as well as some of the best wells they're being drilled in the basin by others or by us.
So that was a strategic deal that looks better and better each month it goes along. But we're not satisfied. We're going to be much more temporal as we work it down to 2%. And more of that is because of the price problem, the commodity price, than the debt level because what I said earlier, if you had a rise to $10, and I use that because it's easy to multiply times our production -- oil production next year $13 million or $14 million, that's $140 million. You add that on, and you are back down there in the 2s. So we -- looking at a number of things to reduce debt, a mineral deal all those are on the table. Anything that can help move that down there is going to be on the table. So I appreciate your question. And once you know we're bondholders, too, all the officers around here besides being stockowners, we got bonds. So our skins completely in the game.
All right. Appreciate that. Thank you.
Thank you.
Thank you.
Thank you, ladies and gentlemen. This ends the Q&A portion of the morning’s conference call. I’d turn the call back over to management for any closing remarks.
Okay. I have three very quick great remarks. First, I want to extend to you all again, everybody out there listening, come see us. We'll be happy to meet with you in person, give you a tour of the office, let you meet some of the teams, see the MaxCom room. And I think you'll see instantly -- how remarkable that room is to work with our drillers and everybody else. A year ago, people thought, can you even drill 2-mile laterals. So I think building them -- we felt very confident, and they have, they've gone out and done it, but come and meet these people yourself. They're very nice people, you like those neighbors, and they're very capable in their respective jobs.
The second thing, I want to thank Moody's for the upgrade in our credit ratings and on our bonds. We appreciate that and the acknowledgment that that they can clearly see things are getting better here.
And finally, the last group, I haven't fully recognized or given the shout out to as our accounting group. They got through the -- getting through the audit, all the 10-Qs. They're out there. They have collected the accounts receivable. Their audit group has made paid -- more than paid for itself. And a lot of good work through the coronavirus, and they're the ones that have sometimes real deadlines. They got to meet. And you come around at the quarter. They'll be here on Saturday, Sunday or doing whatever it takes. And Rob, thanks again for your leadership with that front.
So with that, that's all I have. But say -- if you got more questions, come see us, and we'll spend whatever time you need to get your questions answered. And now you have a choice in these moments, and we appreciate you choosing to listen in to this conference call.
Thanks, again. I hope to see you soon.
Ladies and gentlemen, thanks for your participation today. This concludes the program.