Good morning, ladies and gentlemen. Welcome to the First Quarter 2020 Matador Resources Company Earnings Conference Call. My name is Danialle, 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 May 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, Danialle, and good morning, everyone. And thank you for joining us for Matador’s first 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 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 issued yesterday, I would like to remind everyone that you can find a slide presentation in connection with the first quarter 2020 earnings release under the Investor 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 out there, and thank you for participating in today’s call. We appreciate your time and interest in Matador very much. Today, we’re trying something new in this quarterly release on both our website and on the webcast planned for today’s earnings conference call is a set of five slides, identified as Chairman’s remarks, Slides A through E to add some color and detail. Please let me know if this additional information works out to be helpful to you. If you’ll begin by looking at Slide A, you’ll see that the first quarter of 2020 was another good quarter for Matador and a beat across the board. The Board of Directors and I would like to commend once again the Matador team for their focused and professional response to the dual crises of the novel coronavirus and the abrupt decline in oil prices. Since early March, we have worked together to identify ways that Matador can reduce capital spending and operating expenses while increasing revenues and cash flows to weather these challenging times. The officers of Matador are in here with me and they’re available for your questions too, and that we all spent a lot of time up here together in the last six weeks. At a meeting of the Matador Board on March 10, 2020, I volunteered to take a 25% pay cut. The Board joined me in taking a 25% pay cut too. Matador’s President and the Executive Vice Presidents all then took a 20% pay cut, the other Vice Presidents took a 10% pay cut, and the rest of the staff took a 5% pay cut. According to one prominent energy industry compensation study, Matador was the very first oil company to announce any such cuts. Among the other first steps we took were to hedge 90% of our anticipated 2020 oil production, including all of our forecasted oil production in the second quarter at oil prices ranging from $35 to $48 per barrel, and to cut our capital spending by roughly 35% by reducing our rig count from 6 to 3. We are prepared to take additional steps to further reduce spending, if necessary. If you will now look at Slide B, throughout the first quarter, the operations group led the way to our goal of achieving lower than expected capital spending and operating expenses. Our capital expenditures for drilling, completing, and equipping wells this past quarter were $25 million less than our original estimates for the first quarter of 2020, and we estimate that $15 million of these savings were attributable to improved operational efficiencies and lower-than-expected drilling and completion costs. Drilling and completion costs for all operated horizontal wells completed and turned to sales averaged just over $1,000 per completed lateral foot, a decrease of 13% from average drilling and completion costs of $1,165 per lateral foot achieved in 2019. We expect drilling and completion costs per lateral foot to continue to decline throughout 2020, reflecting improved operational efficiencies, reduced service costs, and the impact of drilling longer laterals, with most being 2-mile laterals. These results bring us to Slide C, which indicates by the fourth quarter of 2020 Matador could be approaching cash flow neutrality. And that’s down there in the lower right hand corner. You can see that we’re steadily bringing those costs down. And we think the outlook is positive there. At the end of this quarter, we achieved the first of four important production milestones we set for Matador in 2020. Matador had previously predicted in early 2020 we would incur a significant surge in production when the first six Rodney Robinson wells in the western portion of the Antelope Ridge asset area were turned to sales. As recently reported in a separate press release, Robinson wells achieved record 24-hour initial potential test results for Matador from all three different formations tested, collectively testing at rates of approximately 15,000 barrels of oil per day and 25 million cubic feet of natural gas per day. The other three production milestones should occur when the five Ray wells in the Rustler Breaks asset area and the five Leatherneck wells in the Greater Stebbins Area are turned to sales during the summer and when the 13 Boros wells in the Stateline asset area are turned to sales beginning in September and October. These are objective measures of our progress. These Boros wells are likely to be even better than the Rodney Robinson wells, and there will be twice as many of them. Collectively, these four groups of wells make up almost 60% of our expected completions in 2020 and should account for more than 60% of our incremental production this year. As we move forward in 2020, our priorities are to protect our balance sheet and our liquidity and to strengthen our exploration and production and midstream businesses. We will do whatever is required to protect our balance sheet and preserve the necessary liquidity to meet our goals. Many of you have wondered about our bank relationships. If you will look at Slide D, you will see that we had approximately $340 million of our elected commitment available at the end of the first quarter and another $200 million available under the total borrowing base of our reserves-based loan. We wish to express here our sincere appreciation for the support and encouragement we have always received from our bank group and especially this year. These are obviously challenging times for all of us, but challenging times can bring about unexpected opportunities, and we will remain open to all such possibilities as we navigate the remainder of 2020 and position ourselves for 2021 and beyond. We consider Matador’s current stock price to be a good buying opportunity. Matador’s assets include two successful businesses, one in exploration and production, and one in midstream as well as 152 million barrels of oil and 646 BCF of proved oil and natural gas reserves, respectively, and 128,000 net acres in the Delaware basin for its 117 million shares outstanding. Slide E shows the steady growth in our proved reserves and the amount of reserves each individual shareholder proportionately owns. The Board, the staff, and I remain confident that the outlook for Matador is very positive when you combine these assets with Matador’s financial position, proven management team, and operating staff. As I mentioned, our staff, the officers are here, I’m here, and we would be happy to take your questions at this point.

Thank you. Our first question comes from Scott Hanold from RBC Capital Markets. Your line is now open.

Yes. Thanks. I appreciate that and great quarter, guys. I think a lot of the narrative for the industry in the next couple of months is really going to pivot to the full storage in the U.S. and the curtailment of production. You all obviously have factored some of that into your guidance. Could you give us a sense of exactly how you see that progressing for Matador? And first question, have you guys shut-in production yet, when do you think it’ll start? And what is your sort of base case and maybe stretch case on what the shut-in levels could get to?

Hi, Scott. It’s David Lancaster. Good morning. Let me address your questions in order. Regarding the percentage of shut-in production, we have shut-in or will shut-in some of our production in the Delaware and Eagle Ford in May and June. We expect that, compared to our initial expectations for that production, approximately 10% to 15% of our production will be shut-in on average during those months. As for whether we have already begun this process, we have just started to shut-in our production in the Eagle Ford over the last few days, and we will begin to shut-in our production in the Delaware starting tomorrow.

I appreciate that information. With the strong wells coming online in the second half of the year, how do you intend to manage those wells during the remainder of this year and into next year? Will you adjust the flow rates until prices improve, or could you provide some insight into what your strategy will be?

Yes. I think, Scott, what we are thinking right now is the most likely thing we will do is probably something similar to what we did with the recent Rodney Robinson wells, and that we will go ahead with frack and get those wells drilled out and put online, get initial tests on them and then if need be, we may turn the production back on some of those wells for a period of time. I think that a lot of that will depend on how prices are looking as we go through the rest of the year, and those will be kind of game-time decisions as we go along. But as things exist now, and particularly with the Stateline wells and the other wells, which was talked about, in particular the Rays and Leathernecks, our plan is to go ahead and complete those wells, drill them out, get them tested and then we’ll make decisions as to the level of production on those wells as we go through the year.

I just wanted to add to what David is saying there in regards to how we’re setting these wells in and which wells are getting shut-in. I think, Glenn Stetson, he’s our Head of Production, he and his team have done a really nice job of putting together all the wells that we operate and what the operating expense is on those wells and where they’re economic and where they’re not. And so, we’re kind of poised to react to whatever the market does in regards to increasing that amount or decreasing that amount. We’ve got all that stuff teed up and ready to go.

Okay, just to clarify, in your guidance, do you expect there to be continued curtailment for the rest of this year on the Rodney Robinson and Boros wells?

I think it's reasonable to say that we expect to bring those wells back into production at levels closer to their original rates in the second half of the year. One reason we plan to update our third quarter and fourth quarter expectations during the next earnings release is to give us a chance to assess how things unfold throughout the quarter. Some decisions may be made as we go along, and we have accounted for that in our current guidance. Overall, we anticipate that we will be able to produce those wells closer to our initial expectations in the second half of the year.

Okay. I appreciate that. Thank you.

Thank you. Your next question comes from Jeff Grampp from Northland Capital Management. Your line is now open. Please go ahead.

I wanted to discuss the topic of shut-ins. Can you share your expectations or insights from past experiences regarding the return of shut-in wells? Is this a significant risk that you are considering or planning for in the process of bringing these wells back online? I'm interested in how you envision that process unfolding.

I’m sorry. Joe, go ahead.

Yes, Matt, I’ll start and then you can finish. Jeff, we have conducted multiple scenarios to avoid relying on just one approach. We consider various what-ifs and develop a comprehensive plan. This involves looking at several variables, including price, lease terms, and hedging strategies. Consequently, there are multiple potential scenarios for our actions at different times. However, we aim to maintain consistency; we prefer not to fully open the wells and then shut them down again. We strive to be consistent and methodical throughout the process. Additionally, being on pipeline simplifies things compared to being on truck in certain situations. Matt?

Yes, Joe, thank you. Jeff, I’ll add to what Joe is saying. There are some mechanical issues concerning which wells are shut-in that we are seriously considering, and I’ll provide a couple of examples. If we have a legacy vertical well that’s on a rod pump producing about 20 to 30 barrels a day, shutting it in is quite straightforward; we simply secure the pumping unit, turn off the wellhead, and we're ready to proceed. Another example is a well in the Delaware that has an ESP requiring an overhaul. We previously discussed this and decided it would be best to remove the ESP, inspect the tubing, complete the overhaul, and then prepare to reinstate it. These examples illustrate the range of our approach. Glenn and his team have done an excellent job identifying which wells to shut in and the procedures for doing so.

Got it, great. Great details there. My follow-up on the midstream side, release mentioned San Mateo going to a free cash flow positive position next year. I assume that the two likely decisions with that free cash flow is either to pay down that bank debt or maybe extract some cash back to the parent. So, I was just kind of wondering how you guys look at the optionality of that free cash flow, and is that a Matador decision, is that a conversation you have with your partner? And I guess this may be reminding us how much control you have over what to do with that free cash?

Hey, Jeff. It’s David. San Mateo has its own Board of Directors composed of representatives from Matador and Five Point, and we have a great working relationship with our partners at Five Point. I believe that any decision we make will be unanimous between the partnership, and they will certainly be consulted. We have the option to use the cash flow to pay down some of San Mateo’s debt or to increase the distributions to each party. Ultimately, we will decide together as a partnership. It is likely that we will increase the distributions, which each party can then use as they choose. For Matador, this would create a significant amount of free cash flow that we can leverage, along with the larger incentives we anticipate next year, to manage any expenditure we may face in drilling and completing wells in 2021.

Got it. Sounds good. I appreciate the time, guys.

Thank you. Your next question comes from Irene Haas from Imperial Capital. Your line is now open. Please go ahead.

Yes. Hi. Good morning. I was wondering, as you look towards the fourth quarter, you have D&C CapEx of $56 million with three rigs, probably likely near completion. Can you give us a little color as to how 2021 might unfold? How would you kind of step back into a more normal routine if oil were to stabilize, right, $40 or $50?

Yes. Hey, Irene. This is David. Well, I think it’s probably a little early yet to speculate on that. So, I would be pleased for oil to be back at $40 or $50 in 2021. And if it were, then I’m sure we would probably consider perhaps adding a rig back. But at this point, we don’t have any plans to that. And I think certainly through the remainder of this year, we’re going to stay with the three rigs. And, I think our initial plans for going into next year would probably be similar and I think we would be cautious as we always are in terms of when we decided to either to move forward with increasing activity. I think that actually in the fourth quarter, if I recall correctly, you’re right, the number of completions is down, but we still do have a few wells being completed even in the fourth quarter with the CapEx estimate that we have. And then, we would have additional wells being completed in the first quarter of 2021 as well, because I think most of our Bonnie wells at Stateline would be beginning to complete a lot of those wells. We’ll have some additional Rodney Robinson wells by that time too.

Okay. I have one follow-up. How does the G&A look on a per barrel basis? Do we kind of use the first quarter number for the rest of the year? And that’s all I have.

Can you ask it again, Irene? I’m sorry. It kind of cut out and I didn’t understand it completely.

G&A outlook for the rest of the year.

Okay. If you look at the slide deck we provided, you'll see a clear indication of our expectations for G&A for the rest of the year. We anticipate that our G&A per BOE will be lower than what we reported in the first quarter due to some additional measures we've implemented, particularly the pay cuts that Joe mentioned earlier, which started on April 1st. Therefore, these will reflect in the second quarter. Additionally, we have made some changes, as we've mentioned in previous releases, with staff moving into field positions or roles in our measurement area in San Mateo. We’ve had about 27 employees transition from our Dallas office to other assignments. Overall, this is working out well as it's aimed at reducing some of our contract expenses, and we expect to see this reflected in the G&A numbers moving forward.

Irene, I just wanted to tag on to what David’s talking about these folks transferring job responsibilities. A lot of them are people that have gone through our MaxOps or Billy’s MaxOps and MaxCom programs, and they’ve been out in the field, that’s where they learned. They spent the first two or three years in the field. And so, we’ve asked them and they were very excited about being able to go back and run drilling rigs and run frack spreads and do all that stuff. I think that from a timing perspective, it’s worked out really nice for us to have experienced field folks that we could bring into the office for a couple of years and then send them back out into the field, so they’ll continue to gain experience in it. They will be even better when they come back.

Thank you. Your next question comes from John Freeman from Raymond James. Your line is now open. Please go ahead.

Thank you. Good morning, everybody. Not belabor the shut-in thing. But, I just wanted to verify, David, when you said that roughly 10% to 15% of production shut-in is kind of what you’re assuming. When you say shut-in, does that include in that number what I would view as sort of your curtailments for these restricted flow rates, like on the Rodney Robinson? Is that included in that number or is it just physical shut-ins?

Yes, John. It’s David. Yes. Thank you for giving me a chance to clarify that because that is true. I mean, when I said shut-ins, I’m thinking shut-ins or curtailments or restricted flow. I’ve got that all sorted in the same bucket.

Okay. Is it possible to break down how much of that you think is physical shut-ins versus the curtailments like what's happening with Rodney Robinson?

I would say that probably around half to two-thirds of it is due to physical shut-ins, while the rest is related to curtailments.

Okay, great. And then just my follow-up question, just to make sure that I’ve got the completion cadence right. So, based on the details you all gave with the five Ray wells and the five Leatherneck wells, which you said summer of this year. If we take the prior guidance that had those coming on roughly around July, so, I assume you get those 10 in 3Q, and then 13 Boros wells, which basically straddle 3Q, 4Q with September-October, you just take half of those Boros and put them in 3Q for right now and the other the remaining half in 4Q?

I believe the Ray wells will likely be completed in Q2, while the Leathernecks will probably be completed in Q3. For the Boros wells, I anticipate that around two-thirds will come online in September and one-third in October. There are a total of 13 Boros wells, and they will be introduced gradually over the coming months. We plan to start with three or four wells at a time during September and early October for several reasons. First, we want to avoid overwhelming the facilities at the start. Second, we need to gauge the expected volumes. Third, these will be the initial flows traveling north on the new pipeline to San Mateo. Therefore, we want to carefully stage the introductions rather than immediately opening all the wells at once.

That’s great. I appreciate, Dave. And congratulations to everybody on a great quarter.

Thank you, John.

Thank you. And your next question comes from Neal Dingmann from SunTrust. Your line is now open. Please go ahead.

Good morning, all. My first question is probably for David or Matt. I’m just wondering, David, when you think of that, we haven’t heard too much you’ve made some curtailments and shut-ins. I’m just wondering what’s the time or cost needed to bring that back? It sounds like or at least appears like on your press release there is really not too much timing or cost involved. But, I just wanted to sort of double check that from the experts.

Neal, I didn’t exactly understand your question. Are you just asking about how difficult is to bring the well back on or what it might be looking like in terms of cost?

Yes. Matt, regarding the shut-ins, we've heard that there is a significant amount of stimulation required to bring things back. I understand the need for curtailments, but I'm curious about the associated costs or timing. From your perspective, it seems like there isn't too much involved, and I just want to verify that.

Yes, Neal, I believe the situation will differ from well to well. Generally speaking, for the legacy wells operating with pumping units, it's quite straightforward. You turn off the unit, close the valves, and when you're ready to resume operations, you simply return to open them. For wells utilizing different types of artificial lifts, there may be some variations in cost. Focusing on gas lift, when we shut down a well on gas lift, we will shut it down and leave the valves in place, with the compressor set to standby during that time. When it’s time to resume, we will go back, open the well, and if it has built enough pressure to flow naturally, it will do so. If not, we will start the gas compressor and begin gas lifting. For wells that are currently flowing, which is a limited number that we would consider shutting in, I think they would build enough natural pressure to start on their own. Therefore, we don’t expect significant complications. There may be some wells where we see an opportunity to either replace the artificial lift system or refurbish the existing setup.

Very good details. And then, my second question is for David. David, around that CARES Act and tax credit, I’m just wondering if you all might be eligible for any AMT tax credits in 2021 and you could look to potentially accelerate these into 2020?

Yes, the answer is yes to that. We have not had a significant amount of AMT credits, even with the new tax act in place. However, I believe we have applied for approximately $3 million to be accelerated into 2020 as part of the CARES Act. Additionally, there is another $3 million we expect from the regular cycle for 2020. In total, that could amount to around $6 million.

Very good. Thanks. And Joe, I just wanted to say, nice job leading by example of the salary reduction and all. I think, you guys really stand out.

Thanks, Neal. I appreciate it. I felt a bit hurt when I wasn't asked that question, but we truly appreciate it. It was just the right thing to do. Prices have dropped from $62 a barrel at the beginning of the year to $20, and our shareholders have seen their shares lose 90% of their value. What else could we do? We were prepared to make further cuts, but it seems things have improved, and perhaps that won't be necessary. We want to make sure our alignment with shareholders is clear. I don’t want anyone thinking I'm a saint because I’m not; it was just the right thing to do. The impressive part was our Board's immediate response without any prompting. Our Audit Committee Chair volunteered to take a 25% pay cut, and everyone in the Boardroom agreed. I think that demonstrates more about doing the right thing than anything I or the executive team did, as everyone contributed. In the past six weeks, there has been considerable effort from everyone to reposition Matador and demonstrate that we had a solid plan to navigate through the coronavirus and poor pricing. The best move was David and the team restructuring the hedges to achieve 90% to 100% coverage for this quarter, with a base price of about $35 to $37, and a few at $48. This significantly reduced risk going forward, and everyone has been fully engaged to keep things moving. The credit really belongs to others, but I appreciate you giving me that recognition, Neal. I'll accept it.

We all still consider you a saint, Joe.

Thank you. And your next question comes from Noel Parks from Coker & Palmer. Your line is now open. Please go ahead.

I’m wondering about the mention you made earlier about Boros wells, and that you expected that they would be even better than the Rodney Robinson ones. So, I was wondering what you attribute that to. And also wondering, with the outperformance you saw in the first six wells, would love to hear some more about what the components of that was, whether it’s just rock, frack effectiveness.

I believe that's accurate. It primarily relates to the rock formations. The Stateline area appears to have some of the best reservoir quality in the entire Delaware basin. Therefore, we feel very optimistic about the potential of those wells. We have been impressed with the section from the Avalon through the lower parts of the Wolfcamp since we started working in the basin, and we see significant opportunities there. Time will tell, of course, but our optimism remains high. So far, the drilling of those wells has proceeded well, and we are eager to complete that phase and begin fracking these wells soon to see the results.

I’ll just add to what David has said there. One of the things that we’re excited about is having those rigs on there at the same time. There’s lots of synergy, a lot of the efficiencies that you get just by having all the rigs right there close by. We’re sharing some of the mud systems; we’re able to share some of the supervision. We’re able to reduce some of that. Our superintendents, our troubleshooters, if you will, they’re staying on location. They’re able to access all four regions at the same time. There’s just a lot of efficiencies that go along with that. And this is a big batch of long laterals for us, but it’s not the first. We drilled well over 30 of these 2-mile laterals already. So, Billy and his team are doing a really nice job on the drilling. And I know Chris and his team will do well with completions, and Glenn and his team will do well in production. So, we’re excited about those wells.

This is Billy here. I’ll just add on to that. In the MaxCom room, you see the different asset managers; you see the geologists in there; you see the engineers. And we have that many rigs running in the same place at the same time. You get all this group energy and they’re all looking at different things they’re doing. And out of that, I mean, I know you see in the slides there, we’ve had 84 records across the different asset areas and categories to the tune of saving $9 million already. And you just feel it and see it, and you’re getting more time and in zone 94% of the time, and zone and all good.

I wanted to discuss hedging for a moment. The gas market appears to be improving after a long time. Are you considering being more aggressive with gas hedging in the near or longer term, especially as we hopefully move past the pandemic? Is it becoming more likely, or do you prefer to wait and see what the spot market offers?

I think, Noel, it’s probably more likely. I mean, we already, as you know, in the release have entered into some hedges for natural gas in the winter months. So, we’ve got some hedges down between November and March already that has 250 floors, and I think they’ve got about 375 on the top end. And we certainly have begun to monitor the move in gas prices. And I would expect that things continue to look favorable, and I think we feel like that they will, but that’s probably something that we would that we would look to do. To be able to lock-in a little bit better natural gas price for next year would help us out quite a bit. So, we do have 40% of our production that’s natural gas. And when you’re talking about producing 60 BCF or 70 BCF a year of that, an extra dollar is $60 or $70 million. So, I think it’s important and something that we’re paying attention to.

This is Joe. The other thing is just to note that we’re right now about 60% oil, 40% gas, and we have a number of knobs that we can turn either in the Haynesville or the Eagle Ford or out there in New Mexico, particularly in the Rustler Breaks area, where we could rapidly increase our gas production, if we should choose to do so. So, we’re monitoring the hedging. But, we kind of like to have a backup to use the hedging to backup what we’re doing, either in oil or gas, to try to reduce the risk of commodity pricing.

Great. Thanks a lot.

Thanks, Noel.

Thank you. And your next question comes from Richard Tullis from Capital One Securities. Your line is now open. Please go ahead.

Thanks. Good morning, everyone. Joe, congratulations on the strong quarter, particularly on the cost side. Something back to 2021 a little bit. I know you talked about a little earlier. But, with the 4Q production benefiting from the Stateline wells coming online later this year, what level of drilling completion CapEx do you think would be necessary in 2021, or rig activity, if you’d rather look at it that way, to kind of keep production flattish with the new oil production outlook for this year, around 41,000 a day?

Good morning, Richard. It’s David. I believe we can achieve small growth next year, likely in the low-single-digit range, even if we maintain three rigs. Some of this growth will be related to timing. As you mentioned, we have a significant increase in production from the first 13 wells at Stateline, which will mostly come online in the fourth quarter and carry into early 2021. Additionally, we expect the first batch of wells from the western side of Stateline, referred to as Bonnie, to come online around the beginning of the second quarter, adding another boost to our production early in the year. The Antelope Ridge team also plans to drill four more wells on the Rodney Robinson track towards the end of this year, with those wells likely being fracked and brought to sales around the same time as the other Rodney wells did this year. Overall, we anticipate a notable increase in production in early 2021, which should help sustain some level of growth, even with just three rigs in 2021.

And just for my follow-up. At San Mateo, adjusted EBITDA kind of flattish the last couple of quarters. What are current thoughts on potentially monetizing all a part of the interest there over the next one or two years, if you could update us on that?

Yes, Richard, we're a public company and we aim to be transparent. We've made sales in the past, including our first sale of Matador, a portion of our Haynesville to Chesapeake, and a plant to EnLink. Predicting further sales is challenging, especially due to fluctuating prices. However, if we receive a serious offer, we would consider it seriously. Regarding EBITDA being relatively flat, the reduction in rigs has led to fewer third-party contracts than we would prefer. Nevertheless, we have a growing production profile, and we need that capacity to meet our own requirements, while hoping to enhance it through more third-party contracts. Our field staff have done an excellent job servicing other companies, and we aim to maintain a strong reputation for providing quality service. Over time, as we build pipelines, we expect to attract more gas resources. We have developed pipelines, particularly the expansion through the Stateline and into the Stebbins Area, which are promising regions. While we are not dependent on external factors, we believe that the combination of our production profile and existing third-party relationships will yield positive results. There may be a temporary stall where things stay flat, but we anticipate growth to resume, especially as gas prices rise and drilling activity increases. Water production has remained consistent, as has oil, making for a positive outlook. David, do you have anything to add?

No. I think that was a good answer.

I would just do that, Joe, and you kind of said it. But, San Mateo contemplated this expansion, what we would look at is the anchor tenants to make economics work and the anchor tenant to Matador. And so, the fact that we’re running the rigs on San Mateo acreage does make the economics work for the expansion going forward. And I would say that at some point in time things will come back and we’ll be there and San Mateo will be there with the capacity and ready to go for third party.

Thank you. And your next question comes from Sameer Panjwani from Tudor Pickering. Your line is now open. Please go ahead.

Hey, guys. Good morning. This is a bit of a hypothetical question, but on the shut-ins, if the hedge book wasn’t in place, would you guys have decided to shut-in more? And following onto that, what price do you think the Company needs to generate full cycle returns on new drilling on an unhedged basis?

Hi, Sameer. It’s David. It's always challenging to address a hypothetical scenario. Currently, we are where we are. There are many factors involved in the decision to shut in wells. Each well has different operating costs, produces from various zones, and has varying artificial lift durations, which can complicate the shutdown decision. Additionally, each well is subject to its own lease obligations. Therefore, operators must consider numerous factors when deciding what and how much to shut in, and it's not merely about price. There are also volume commitments for gas production to consider. All these factors need to be taken into account, and while the hedge book does help, it's just one of several considerations in making such decisions.

Okay. That’s helpful. And the second part of that question was, as you think about what price do you think the Company needs to be generating full cycle returns on new wells?

I think that's a difficult question to answer because price and service costs are closely related. Currently, the prices we expect for drilling and completing these wells are the best we've ever seen. However, I can't promise that means we'll achieve $20 costs for every well we drill. It's not a simple situation with just one variable. We have a range of wells, as all operators do, and some will yield higher returns than others. In a time of low prices and costs, these factors significantly influence which wells we choose to drill and their long-term economic viability. Therefore, I'm hesitant to provide a specific price since many elements contribute to those decisions, and it’s not solely about price. Costs are also crucial. Looking back at previous years, such as 2016 when prices were very low, we saw subsequent price increases, and those wells turned out to be some of the most economically viable because we constructed them at a low cost. This aspect should not be overlooked when evaluating the situation.

Maybe switching gears on San Mateo, there was a question earlier on liquidity and free cash flow implications for Matador as the midstream business turns free cash flow positive. But, can you talk a little bit about how San Mateo 2 could further enhance this one, some of the facilities come online, both in terms of liquidity and free cash flow?

I believe we can achieve both objectives effectively. Regarding the liquidity aspect, our current credit facility related to San Mateo is solely based on the assets of San Mateo 1. The assets of San Mateo 2 are not yet included in this credit facility. We anticipate that once the merger between San Mateo 1 and San Mateo 2 occurs, which is currently in progress, San Mateo 2's assets will be incorporated into the credit facility. At that point, we think it is highly likely that the bank group will agree to increase the facility size due to the significantly enhanced collateral. Consequently, this will provide us with much greater liquidity under the credit facility associated with San Mateo. Additionally, there is no doubt that once the new plant and pipelines are operational, we will see a notable increase in revenues from San Mateo, particularly from San Mateo 2, as gas from Stateline moves south and oil from Stebbins flows in. We have also added a few more saltwater disposal wells in the Stebbins area, which are already boosting the revenue for San Mateo 2. Therefore, we expect and project a substantial improvement in San Mateo's financial performance starting in the fourth quarter and continuing into 2021, as we bring everything online at Stateline and Stebbins.

Thank you. And our last question comes from Gail Nicholson from Stephens. Your line is now open. Please go ahead.

So, Rodney Robinson and Boros wells have a higher NRI. Could you remind me on the ‘20 activity level what is the average NRI and then how do you think that could potentially change in ‘21?

You’re right. The Rodney Robinson wells have the 87.5%, all the Boros wells have 87.5%. Anything on Statelines, so the Bonnies will have a 87.5%. The wells at Rustler Breaks probably tend to run between 75% and 80% on the NRIs, and that’s probably pretty good elsewhere too. I mean, we have wells that run, if their fee leases, they’re mostly 75%; if their state leases, they tend to be a little better than that, maybe plus or minus 80, and if they’re the federal leases, we often have the full one-eighth or 87.5%. And so, as you think about next year, I mean, we probably will continue running a couple of rigs at the Stateline and those wells should all have the 87.5%. We’ll drill a few more Rodneys. But we’ll also have I’m sure, 8 or 10 other wells, but we’ll have something closer to 75%.

Okay, great. And then, just a follow-up on San Mateo. When you look at third-party MVCs for ‘20, do you believe that that upticks in ‘21, the amount of MVC for third-party, is that correct? And can you just kind of quantify that change, ‘21 versus ‘20?

The answer is, it’s correct. I probably would prefer not to quantify the amount just from the standpoint that, consider that’s sort of confidential between the San Mateo and its customers. But to answer your question, yes, we would expect an uptick in the volume in 2021.

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

Thank you very much to all of you listening in and participating. We appreciate it. The final thought is, is that the most encouraging to us is everybody on the various areas drilling, production, marketing, land, land administration, every group, accounting, divisional orders, everybody has really pitched in and made the extra effort. And I know our processes are working better, the communication is better, coordination is. And we think we're going to finish this year strongly, and next year will be even better. And challenging as these times are, there are going to be some good opportunities come up. As David mentioned, our drilling costs are down, they’ll lead to better rates of return. We think there will be some opportunities come up. Midstream is growing and it’s a fee-based business. So, it’s not as subject to the volatility. Our marketing group is encouraged by the outlook for gas prices to rise. So, while $20 oil does present a lot of challenges, we also think there will be some opportunities to come out of this. So, we appreciate your interest. And anytime we can help you or answer questions for you, please give us a call. And thank you very much for joining this call. We appreciate your interest very, very much.

Ladies and gentlemen, thank you for your participation today. This concludes the program.