Good morning, ladies and gentlemen, and welcome to the Viper Energy Partners Third Quarter 2019 Earnings Call. [Operator Instructions]. As a reminder, this conference call is being recorded. I would now like to turn the conference over to your host, Adam Lawlis, Vice President, Investor Relations. Please go ahead, sir.

Thank you, Prince. Good morning and welcome to Viper Energy Partners Third Quarter 2019 Conference Call. During our call today, we will reference an updated investor presentation, which can be found on Viper's website. Representing Viper today are Travis Stice, CEO; and Kaes Van't Hof, President. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Travis Stice.

Thank you, Adam. Welcome, everyone, and thank you for your listening to Viper Energy Partners Third Quarter 2019 Conference Call. During the third quarter, Viper continued to expand its footprint in the most attractive areas of the Permian basin via multiple large and strategic acquisitions. After giving pro forma effect to the Santa Elena acquisition, we will have acquired over 9,000 net royalty acres to date in 2019. Importantly, with the drop-down transaction from Diamondback closing on October 1 and the Santa Elena acquisition expected to close tomorrow, Viper will have materially increased our exposure to Diamondback operations in both the Midland and Delaware basins to a level not seen since first going public in 2014 with our Spanish Trail asset. As a result of these recent acquisitions, Viper expects to have exposure to roughly 70% of Diamondback's expected 2020 gross completions with an average net revenue interest of over 5% versus exposure to only 53% of Diamondback's gross completions with a little over 4% net revenue interest so far in 2019. On the operations front, Viper experienced near-record levels of gross activity across our acreage position during the third quarter as represented by 171 gross wells being turned to production with an average net royalty interest of 2.7%. This strong activity, along with Diamondback completing a large pad in Spanish Trail, resulted in Viper growing organic production 9% quarter-over-quarter. This is particularly noteworthy given the backdrop of an over 20% decline in the Permian rig count this year. This production pro forma for the deals announced or closed in the third quarter was over 27,000 BOEs a day, as previously announced, due to the flush production acquired in these large transactions. When we make acquisitions, we make sure to set the effective dates for these transactions that deliver maximum…

[Operator Instructions]. First question comes from Jeff Grampp from Northland Capital.

I was wondering -- first for Travis or Kaes, and you guys kind of talk about lack of third-party visibility. Was wondering, as we look at the guide for the next 2 quarters and I look at Slide 9 with the 8.6 wells work in process, can you tell us what of the third party that you guys assume come on in the 6-month guide? Are all those still assumed to come on? Or is there some I guess services in the guide? Kaes Van’t Hof: Yes. Jeff, I mean we have pristine visibility on the Diamondback side of that page, but on the non-op piece, what had traditionally been completed in 3 to 6 months on average as everyone was humming along in the Permian and the first 3 quarters of the year, we took that completion cadence as essentially bold. And that's certainly slipped here in the back half of the year. So -- and I'd say, we're haircutting that by 1/3 to 1/2 from a timing perspective versus what we originally used to guide to on the third-party piece.

Okay. Great. Really helpful. And for my follow-up, just kind of sticking on that slide. If we look at that kind of 18 net wells in terms of kind of the near-term inventory, is that kind of a decent run rate or proxy to think about in terms of kind of annual completions for the Viper story, obviously, excluding future acquisitions but just kind of based on the current activity levels in the basin? Is that a decent proxy? Or would you guys think about that differently than that maybe overly simplistic view? Kaes Van’t Hof: Yes. I mean I think what's changed though, as you think about next year, Diamondback exposure at Viper is a little over 210 wells at a little over 5%. That's 11.5 net wells that's going to drive production in 2020. I'd say the third-party piece is anyone's guess. I don't think the Permian is going to slow much more than it slowed in the back half of this year. But it seems that the frac holiday that we've seen in the past couple of years has gotten a little more significant this year. I'm very confident that these work in progress wells that are good wells that are in good locations that are going to be completed. Really, the biggest issue we're facing is timing. And we decided to be very conservative, particularly in Q4, on that timing. I'm confident some frac spreads will tick up and operators will restart their budgets in 2020 and you'll see some completion activity. But Q4 was just something we've seen frac schedules slipping to the right versus original expectations.

Our next question comes from Gail Nicholson from Stephens.

In regards to realized pricing for oil next year, we should see a nice uptick in oil price realization. Can you just talk about the mechanisms that drive that improvement next year versus '19? And then also just kind of your outlook on NGL and gas price realizations in 2020. Kaes Van’t Hof: Yes. Thanks, Gail. So the big movement you'll see from Q4 2019 to Q1 2020 is that Spanish Trail is going to get about a $10 benefit from a realized perspective from Q4 to Q1. So as you look back 18 months ago in the Permian takeaway crisis of 2018, we decided to sign some fixed differential deals at the Diamondback level that essentially were out of the money as takeaway capacity came on. But we didn't sacrifice the long term. So as you think about Spanish Trail pricing come 2020 and beyond, January 1, that number goes to MEH minus about $2.50 plus some gathering. So a significant bump versus the back half of 2019. Also, the rest of Viper's production, whether it be on the Gray Oak pipeline or the EPIC pipeline should participate in the upside presented by those 2 pipelines coming online in early 2020 as well.

Great. And then is there -- when you look at just from a portfolio construct, is there anything in the portfolio that might be the best candidate for you guys? Kaes Van’t Hof: They tell you to never sell your minerals and we're very confident that we're buying minerals in Tier 1 areas that will be developed. While the basin is taking a little bit of a breath here in Q4, we feel confident that what we're buying under third parties is under active development and well-capitalized operators that are going to be around for a long time.

Next question is from Will Thompson from Barclays.

I know it's not your MO to provide production guidance beyond 6 months. But given the near-term noise associated with third-party budget exhaustion, the lack of immediate activity over newly acquired minerals and just the lumpiness in terms of quarterly NRIs, maybe can you help us understand how should we think about second half 2020 versus the 4Q, 1Q '20 guidance? Kaes Van’t Hof: Yes. Well, I mean we're going to come out with full year guidance in February of next year for the whole business. I think even if you conservatively assume 1, 1.5 or 2 net wells on third-party properties, you'll see this business continues to grow in 2020. I think with Diamondback's support next year and the exposure to Diamondback being such a large piece of production profile, probably 2/3 plus of it, that even if you assumed third party was flat or if you assumed a decline, the parent support next year will drive distribution growth. And on top of that, I want to make one more comment, Q3 2019 to the next 6 months, we increased our share count 17% this quarter by closing the drop-down and closing the Santa Elena acquisition. If you take the midpoint of our guidance for the next 6 months, even though it's weaker than original expectations, oil at the midpoint is going to be up 27% versus Q3. So you got a business that, from our -- oil production per million shares is up 8% or 9% at the midpoint versus the Q3 number, which should drive distribution growth.

Okay. And then maybe as a follow-up, I know Slide 11 of the deck shows about 4.5 net wells or about 44% of what's implied for FANG exposure in 2020. It looks like the TIL schedule is heavily weighted to 2Q and 4Q, but clearly, you don't have a full picture there. Just curious, I think, in terms of maybe the FANG TIL schedule, it should be more kind of level loaded or if we should just think about lumpiness associated with Spanish Trail or anything like that. Kaes Van’t Hof: Yes. We consciously took Spanish Trail out of Slide 11. There is a big pad, Pad A, which is just north of Spanish Trail that's going to come on in the second quarter next year. As we're going through the Diamondback budgeting process right now, we are trying to move some of these pads up as efficiently as we can. But for instance, Pad E and Pad D, those are Santa Elena acquisition pads that we've added in the last 3 or 4 weeks. So I think there will be some lumpiness, but you won't see the lumpiness that we used to have with Spanish Trail being 60%, 70% of the total production. Instead, you have a broader exposure to more wells at Diamondback in the 4% or 5% range, and these big, big NRI pads are kind of the kicker on top.

Next question is from Welles Fitzpatrick from SunTrust.

Can you talk a little bit about your appetite to buy non-FANG acreage? I mean presumably, it's going for a little bit cheaper than it used to in the drop in rig environment. But at the same time, maybe it's a little bit less appetizing to you all given the visibility you have. Kaes Van’t Hof: Yes. Well, I'd say the appetite has decreased a little bit. It was certainly not out of the game on third-party acreage. I just think Viper has the most unique market advantage in the mineral space due to the fact that all the wells you see in this presentation, there are no permits filed. So our competition can't really only figure out where all of those wells are going to be completed. And so that's kind of the core focus of the Viper team over the next 3 to 6 months is, let's get ahead of that drill schedule. We have this asset. Let's take advantage of it and buy minerals under Diamondback. Now I will say mineral prices tend to be sticky regardless of commodity price and sentiment. So private mineral owners, they have a number in their mind. So you need to be cognizant of that number. And that's why we need to be extra conservative from timing assumptions on third-party acreage right now, which naturally reduces what we can pay.

Okay. Makes sense. And then it seemed like NGLs jumped and gas didn't quite as much in the quarter. It looks like maybe that's processing kicking in. Is it fair for us to assume that going forward for you all? Kaes Van’t Hof: I think it'll level set a little bit. We had a pretty big jump in Q3 due to a true-up in shrinks and yields on non-op acreage. We don't see the final settlement statement until we start receiving checks from those particular plants. So a little bit of a true-up in Q3. I think it will normalize as we go back into Q4. But that brings up another point in that with the basin flaring and then not flaring and ethanes being rejected and then it's being accepted, I think we'll start guiding to oil production rather than oil percentage because that does move things around.

That makes sense. And then just one last one for me. I mean it seems like there is potential for kind of a catch up on these third-party completions. I mean like you said at the top, it's a frac holiday. It's not as though anyone is not going to complete these DUCs. Can you talk to -- I mean is there anything wrong with that interpretation of those eventually flowing through in the second quarter and second half of next year? It just seems -- it seems like a de minimis chance that these things don't actually get completed and hit production sometime next year. Kaes Van’t Hof: I think that's a very fair assessment. I think as we have that data and that visibility, we will certainly update our investors with that data. I think we, through Diamondback, have access to the completion schedule throughout the basin so that we don't frac into each other and Diamondback is not watering out somebody else's production and vice versa. And what's happened is that the frac dates on that schedule have just moved to the right. They haven't disappeared. They just moved to the right on the Gantt chart.

Next question is from Betty Jiang from Crédit Suisse.

Maybe just following up on that, can we -- is there any -- can we get some specific numbers of quantifying what that means in terms of the completion deferral? Like since the drilling activity is still very robust and then you're just deferring completions, so should we expect the net completion count -- how much should it go down in the next two quarters? And would it come back up to this 5 net wells per quarter beyond the six month period? Kaes Van’t Hof: Yes. Betty, I'm not throwing out Q1 here. I just based on what we're seeing as an operator, what we're seeing in the field, what we're seeing from frac companies, from drilling rigs, from drilling rig operators coming to us and looking for work. It's just Q4. I mean I think budget exhaustion is very real this year. I think operators are doing whatever it takes to stay within budget this year versus years past, and that's just resulting in a larger frac holiday. I'm not going to say that no wells will be completed on non-op properties in Q4. We just took what was an original assumption and chopped it by about 1/3 to 1/2.

Got it. But what would you say sort of run rate for 2020 net completions that will be benefiting Viper next year? Kaes Van’t Hof: On non-op property?

Yes, on non-op. Kaes Van’t Hof: I think anywhere from probably 1.5 to 2.5 is probably a fair assessment. I think Q4 are probably closer to 1. But come Q1, we'll be closer back to that 1.5 to 2 and in a good quarter, 2.5 net wells. Now Diamondback alone will be almost 3 net wells a quarter to help Viper through 2020.

And that's pretty steady throughout the year? Kaes Van’t Hof: There will be a little bit of lumpiness as you can see from some of those pads on the page we added. But given that, its exposure to over 200 wells, those pads make up 10% or 15% of that total. So you'll see more consistent performance out of the Diamondback operated piece.

Got it. That's helpful. And then one follow-up. Just on -- trying to understand how much of the pro forma production decline we're seeing at Viper is a function of lower NRI wells that you're just capturing a lower percentage of the growth. And how should we think the NRI varies in the coming quarters? Kaes Van’t Hof: Well, I think I'll frame it a little bit differently. The deals that we bought, and Travis put this in his opening remarks, we're always very cognizant of when flush production is coming on. So we always try to make sure the effective date of a transaction encompasses the flush production that's should accrue to Viper and Viper shareholders. Now you saw a lot of flush production from those 4 large deals in Q4 and those deals are going to decline into Q -- sorry, in Q3 and those deals will decline into Q4. That's not to say there's going to be activity next year. But for instance, on Santa Elena, we can't get back into that acreage until Q2/Q3 of next year and start completing those wells. So I think our overall NRI should be somewhat consistent throughout the year next year. I think we've gotten past the lows of average NRIs because with the drop-down, there's so much Diamondback exposure at a higher NRI.

Next question is from TJ Schultz from RBC Capital Markets.

Just one for me. You've indicated in the past to consider some hedges for downside protection or just support some minimum level of payouts. Just any more thoughts on that? Kaes Van’t Hof: Yes. Those conversations are still ongoing. I think some sort of downside protection is the right path for Viper. We just need to be opportunistic when the market allows it. We can't pay too much for these hedges. I think it's more of a deferred premium put type or put spread type product's that's being discussed at the Board level.'s

Next question is from Pearce Hammond from Simmons Energy.

Based on the recent drop-down acquisition and the soon-to-close Santa Elena transaction, how do you feel about your mineral inventory life, quality of inventory, exposure to various producers and then how do you think these acquisitions differentiate by relative to other mineral companies? Kaes Van’t Hof: Yes. Pearce, I feel great about inventory life. I mean this is -- the drop-down was a huge, huge addition to inventory life. Spanish Trail, it's no secret, it's been a very, very core development area for us for a long time and inventory life there is not as significant as areas like Pecos County or Howard County where we're going to be active for a long time. So I think from a confidence in production growth and inventory life perspective, the drop-down in transactions like Santa Elena add a lot of confidence to our long-term growth plans and development plans. I think, selfishly, we want to place the bet on ourselves and place the bet on Diamondback to continue to operate. Given that Diamondback is the low cost operator in the basin, I don't think Diamondback is planning on slowing down, and that should naturally support Viper through what is a -- somewhat of a tumultuous time here in the energy space.

And then how do you think it differentiates you, Viper relative to other mineral companies? Kaes Van’t Hof: It's just that visibility, Pearce, I mean we're dealing with really tough visibility issues on non-op properties here in the fourth quarter. I think that visibility will improve as things normalize. But we have a lot of confidence that half of our work in progress wells and 66% of our NRI permits are going to come to fruition in the next 12 months.

Great. And then my follow-up case is what is your long-term leverage target for the balance sheet? Kaes Van’t Hof: Under 2x, that's a Board mandate. We want to stay under 2x at the parent level and at the two subsidiaries. I think you're going to see a lot of EBITDA growth just naturally from all the deals closed Q3 to Q4. So I'd probably look at it on a Q4 run rate basis.

Next question is from Jason Wangler from Imperial Capital.

I was just curious. I mean you're still talking about a lot of drilling going on around you and obviously on your acreage. But do you see any lease expiration issues from some of the operators there that maybe opportunity -- or is anything like that happening either on the near term or as -- if things stay pretty slow into 2020, that may be an opportunity for you? Kaes Van’t Hof: Yes. Jason, that's a very important point and our team is spending a lot of time on lease expirations, particularly in 2020, particularly in the Delaware Basin. The Midland basin and a lot of cases, that acreage is held by production. It's held by vertical production. But in the Delaware basin, a lot of leases are new leases. And I think for us to be on top of our lease explorations next year and over the next 15, 18 months is going to be very important because as everyone knows, if a lease expires, it reverts back to the mineral owner, which is why being a mineral owner is the highest form of security in the oil field. And we either re-lease that acreage or extend it for a little bit of a bonus. But traditionally, we try to work with our lessors to get wells drilled because we're in the business of production and cash flow, so we usually work with them to get more wells drilled sooner.

Next question is from Phil Stuart from Scotia Weil.

I wonder if we could circle back on the Santa Elena acquisition. It looks like that's primarily on kind of legacy Energen acreage. And obviously, on Slide 11, Pad D and E are some pretty high NRI wells. Are you all seeing kind of a legacy Energen acreage footprint as kind of the largest opportunity set going forward on the acquisition front for Viper in order to kind of bring in some higher NRI properties? Kaes Van’t Hof: Yes. It's certainly newer, Phil, and there's certainly more opportunity available. I think I kind of see Diamondback and Energen as one company now, so it's really what the pro forma growth schedule looks like. But yes, in that Vermejo area, in Reeves County, you can see we don't have a lot of mineral interest yet. And I don't think we'll be a big buyer in Glasscock County outside of what's on the drill schedule. What was great about the Santa Elena deal is that we didn't have any wells planned on that acreage in 2020 or probably 2021. But now that we have a such a high NRI, we can drill some 15,000-foot laterals next year and have a great pro forma return. So I think there's still a lot of wood to chop on Energen properties, particularly Northern Delaware Basin and Northern Midland Basin.

Appreciate it. That's really helpful. And then I wonder if we could circle back to Slide 9 again. On the work in progress wells, I think you mentioned that you kind of haircut the third-party completions by 1/3 or 1/2. Just wondering, was that a blanket kind of haircut? Or was -- did you all factor in some operator-specific information that you might have? Kaes Van’t Hof: No. That's just a rule of thumb. We go specifically pad by pad, interest by interest based on the frac schedule that we see or an operator's traditional tendency to complete a well. I would just say that even on a pad-by-pad basis, we move things to the right in the Gantt chart more conservatively than we have in the past.

I am showing no further questions at this time. I would now like to turn the conference back to Travis Stice, CEO.

Thanks again to everyone participating in today's call. If you have any questions, please contact us using the contact information provided.

Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may all now disconnect.