Thank you, Justin. Good morning and welcome to Viper Energy Partners' Fourth 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' fourth quarter 2019 conference call.

2019 was an important year for Viper as we successfully leveraged our size and scale to acquire more than 9,000 net royalty acres and most importantly, doubled our expose to Diamondback operated royalty acreage. As a result, Viper expects to have exposure to roughly 70% of Diamondback's 2020 gross completions with an average net revenue interest of greater than 5%.

This increased exposure directly translates to at least 12 Diamondback operated 100% net royalty interest wells expected to be turned to production on Viper's acreage this year versus less than eight in 2019, offering Viper the most exposure to Diamondback in years. Outside of Diamondback operated acreage, Viper's premium acreage position under other well-capitalized operators has continued to attract strong activity levels despite the overall decline in rig count seen across the Permian basin.

Viper today has a stronger near-term inventory of net wells currently in the process of active development as well as additional line of sight wells that have not yet been spud then at any time in our short history. However, in an effort to be conservative, we have contemplated slower than normal timing assumptions for both spud to first production and permit to first production in our 2020 production forecast.

Even with these slower timing assumptions, which have been pushed out by three months on average per pad versus historical actual conversion rights we're assuming over 10% more net wells turned to production in 2020 owner acreage not operated by Diamondback compared to 2019. As a result Viper is initiating full year 2020 oil production guidance that implies 28% growth relative to full year 2019 oil production.

Separately, in addition to the strong production growth expected in 2020 oil realizations are also expected to be a tailwind this year as the last of Diamondback's fixed differential contracts rolled off in December of 2019. Realizations are expected to move closer to the current Midland market with the potential improvement should Brent or MEH spreads widen versus local Midland pricing given Diamondback's position on the Gray Oak and EPIC pipelines.

Given this and assuming $55 WTI in 2020, Viper is projecting aggregate 2020 distributions of greater than $2 per unit implying a greater than 9% annualized full yield at the current unit price. Further, given Viper's cost structure and high cash margins, the company is still expected to generate a free cash flow yield that is 70% higher than the current S&P 500 sector average even at $40 oil.

In a difficult energy landscape, Viper's resilient free cash flow yield and unique relationship with Diamondback will further distinguish it from its peers. We will continue to be active in acquiring Diamondback operated acreage ahead of the drill bit to further enhance the embedded high-margin long-term growth potential of our asset base that requires zero CapEx and we look forward to continuing to generate significant organic production growth in 2020 and for many years to come.

Operator, please open the line for questions.

Regarding your more conservative third-party cycle time assumptions, would it be fair to view the production impact from a planning perspective is more one time in nature, assuming cycle time outlook remains static. If that's the case, do you guys have a view on factors leading to longer cycle times in aggregate across the basin?

Derrick, with non-op being about a third of our volumes and Diamondback operated being two thirds, we are using the exact Diamondback drill schedule on production forecast for about two thirds of Viper's production. For the other third on the non-op piece, traditionally our spud to first production in the Midland basin is average between six and seven months and our spud to first production in the Delaware basin is average five to six months.

In this guidance here given that it's early February and it's been a tumultuous 2020 already, we're going to be conservative and guide to spud to first production of nine months and not a lot of permit conversion in 2020. We certainly expect for all our permits to be converted.

We have a very high permit conversion ratio. Just at this juncture in the year this is the hardest -- this is the hardest guide for Viper for the year to guide for the full year.

So we're pushing those spud to first production assumptions up by about three months.

That makes sense and as a follow on to that question, could you comment on how your spud to pop and permit to pop cycle times have trended over the last couple of years for your operated program.

The operated program is pretty consistent in that five or six month timeframe. We'll say we wait on filing permits at the Diamondback levels so that our Viper team can get ahead of buying minerals before that permit is filed because the price of minerals -- the price of poker for minerals goes up dramatically once that permit is filed.

That's helpful. Makes sense.

Thanks for your commentary.

Wanted to see what expectations for well performance you built in and 2020 relative to 2019 and how that trend may differ or not when you look at third-party operators year-on-year versus FANG with the operator?

Yeah Brian I'll speak for Diamondback. We view the exact type curves we're using at the Diamondback level.

We've risked those type curves. We traditionally new type curves in general, but also we guided the water fact that we're going to see throughout our different various field throughout the year and that's been reflected in the Viper guidance.

Certainly, not looking to on third parties assume the best type curve possible particularly in this environment, but I'll say that our third-party type curves are probably on average double-digit percent below expectations, but really that's more about a lower IP rate in our model than what we traditionally see on the non-op side.

Are you seeing anything that would suggest that beyond conservatism there is reason for either material degradation or improvement year-on-year in well performance at this type curve.

No, I don’t foresee a significant change. I think certainly more and more operators are developing more zones on larger pads and that has a different production profile than just single down the parent wells, but I think that's well reflected in what we're projecting here.

And then my follow-up is on the acquisition front, have you contemplated any incremental acquisitions when you think about guidance and production trajectory and have you seen character the market in your interest?

Yes so we always guide for the assets that we have today. So there is no incremental production or cash flow contribution from projected acquisitions.

We certainly will continue to be acquisitive, I would say we're being a lot more selective on third-party acquisition opportunities, but that doesn't mean we haven’t stopped continuing the acquisition machine on the Diamondback side. I think there's a significant amount of opportunities remaining for us on the Diamondback side.

We just have to be careful in this environment but also we set some price expectations from the market that gets -- sometimes gets pretty heated. So for us saying no to deals is going to be more the norm than the exception in 2020, but that doesn’t mean we can't keep buying aggressively under the Diamondback drill bit.

Wanted to circle back first on a comment Kaes, I think you made at the beginning here, saying that I think two third of production is in the Diamondback side in the third -- on the third-party side. Is that I guess first I want to make sure I was hearing that right, that was on the production front and is that a decent split for 2020 completions that are baked into guidance or is that dramatically altering given the drop in some of the acquisition you’ve done lately?

No I think that's fair Jeff. I kind of have production increasing and the Diamondback's percentage of total production increasing throughout the year, but about two thirds is a fair number for where we're going to be in the fourth quarter.

On a net well basis, in our model right now, Diamondback is 65% to 70% of the net wells, but it [indiscernible] with a non-op net well inventory pretty low in the fourth quarter given where we are today in the first quarter. So in general 50% of the assets are operated by FANG are going to generate two thirds of the production.

And my follow-up and hopefully a quicker one, do you guys have an estimate of kind of what the PDP decline rate of the asset base if we were to look at 4Q '19 to 4Q '20?

It should be about mid-30s on BOEs and high 30s on oil.

So the street consensus models the 1Q '20 simply at the midpoint of the first half production guidance, can you maybe help us understand the cadence of the 20 net completions your visibility on and how that can translate into oil growth throughout the year? Should we think about maybe modest to flattish quote growth in 1Q but a pickup in 2Q?

Yeah I think that's fair. We from a Diamondback operated perspective, the number of net wells in Q1 will look very similar to Q4 about two net wells, that's up by about 50% in Q2 and then from a Diamondback operated perspective, we're almost averaging four net wells a quarter in the back half of the year.

So I think from a growth perspective, we expect to grow modestly off of the released Q4 numbers in the single digits and I have a pretty meaningful step up in Q2 from a oil and BOE production perspective into the mid-single digits from Q1 to Q2. The way we have it modeled right now there are some large pads coming on in the back half of the year, which should help the year exit very strong with an exit to exit number Q4 '19 to Q4 '20 mid-to-high teens on the oil and the BOE side.

And then regarding the updated oil realization guidance of 97% to 100% of WTI, can you may be just clarify the moving parts there You'd indicated that Diamondback represents about two thirds of Venom's volumes. You had a reduction in the net back with Diamondback legacy Spanish Trail sales agreement, I think that was linked to MEH now that the MEH WTI differentials have been moving around?

So maybe just help us understand the moving parts that you're assuming to updated realization guidance?

Yeah, so spreads are going to move. It's hard for us to guide to WTI when really not a lot of our barrels get priced on WTI.

So if you think about Spanish Trail the MEH versus WTI is greater than $3.50. You should equal about 100% of WTI on that number for that operated piece.

The rest of our position particularly when EPIC and Gray Oak start up is going to be priced off of Brent, so Brent WTI is wide, we'll benefit to be higher than the WTI, but I've seen a lot of noise about the 97% to 100%, I think you can just think of it as some conservative and also looking at spreads where they are today, Midland Cushing has been a $1 or more over the last couple months and today it was $0.15 this morning. So these spreads move around and after having a tough time going through the realizations we had to go through in 2019 I am just excited that we're going to be up 8% or 9% from where we we're in 2019.

And just to add on to that point because I think on Page 18 of the deck, it indicates that [indiscernible] viability of adding hedges. So that's pertaining to maybe locking in some of those space differentials?

Yeah, so we have received approval to add hedging to our program. We certainly if these prices aren’t going to be hedging oil but some sort of protection on both the spread side or even the gas Waha spread side given the outlook for permitting gases is pretty dire here in 2020.

I think we're looking to take that risk out of the Viper story. So we'll be looking at the market and now have approval to hedge from a downside and spread protection perspective.

Good morning. Lots of my questions have been asked, but I guess would it overall kind of taking a step back, I think like some market is kind of missing the value that Viper creates or can creates with so much play that yield be accruing.

Do you look at '20 versus '19? Can you just talk about confidence level and overall planning going forward and the ability to even in a variant oil price environment still deliver a really top tier yield not at the cost of energy but really the entire S&P [ph] sector?

Yeah Gail, we feel really confident about the 2020 forecast that we put in place. Again some of that confidence is because of increased exposure to Diamondback operated wells, but we included a new slide in the deck that shows, I think it's slide number 5 that really shows even at $40 well, this vehicle is going to have an annualized yield of over 6.5%.

And so I just think as the market understand pristinely how we've modeled our future and how this is still a robust return vehicle that requires no capital or operating expense, I think it's going to be a investment vehicle of choice because the merits of it sure look like it should be.

Do you think Viper's middle acreage is outperforming the Permian basin as a whole and looking at rig activity meaning has the rig count declined on a lower percentage level on your acreage versus the Permian basin at large?

Pearce that's tough to figure out. I can't say that while our non-op acreage increased last year, we're projecting 10% more non-op net 100% interest wells in 2020 than 2019 even at the conservative assumptions we put out there this year, so that point to acreage quality.

I will say we do think about buying minerals as if we were the operator and what are the areas that we would want to be operating in. So hopefully with our capital allocation and our knowledge of the Permian, we are buying minerals in areas that we think are going to be developed first rather than last.

And then my follow-up, the oil mix percentage declined during 2019 and looks to be roughly flat with Q4 '19 levels as we look at the 2020 guidance. So what drove the oil mix percentage change in 2019?

Was it just more Delaware basin completions and do you see the current oil mix is indicative of your production over the next few years?

Yeah Pearce, so we certainly have added more Delaware to our mix and the gas content of the Delaware is significantly higher particularly than the Northern Midland. I think as we go through 2020, we should have a higher percentage of plus production at Viper which will help oil mix, but overall we tried to guide to oil production separately, gas forecasted particularly in the Delaware basin have been outperforming expectations and therefore we decided to switch from a oil percentage guide to a oil total barrels guide particularly because the asset is now so diverse rather than just being Spanish trail only.

We've decided a lot of different type curves in a lot of different areas.

Obviously you saw a nice uptick in development in sight wells versus last quarter's release, but can you give us an idea as to the cadence. How much should that accelerate in January and February as new budgets came out?

We saw some activity pick up towards the end of December on some of our high interest areas. I think from a non-op perspective we think we're going to have a little more contribution in Q2 than Q1, but I think the little modeling right now is Q1 versus Q4 2019 is flat to a little bit up on the non-op side, but overall I think I said this in the last question that from a non-op net well perspective even at today's assumptions, we're assuming 10% or more net non-op wells than we got last year.

And the disclosure on the sensitivity of those I think that was on Page 5, that's obviously an illustration of why you don't need to hedge but if there is a recovery a review on that change at all? Would you look to lock anything in or are you sticking to your guidance as wanting to have that data?

Yeah I think we're only focused today on hedging differential exposure particularly on the gas side. So hopefully we can remove severe downside risk on the gas side from the Viper story and that'll leave investors full exposure to both oil and upside [ph].

I guess dovetailing on some of the previous questions, you all are obviously focusing a lot more on the net oil volumes to Viper. So I guess and looking at that, you all -- Viper has done a good job of growing oil volumes per million units outstanding over the last three quarters and as you think about financing acquisitions going forward, is oil production per million units going to be maybe the most important factor for deal accretion going forward or is it still kind of pretty evenly split across your historic metrics for deal accretion?

So I think broadly for the Viper story, oil production per million units growth is the key driver of the Viper story and that's what we're doubled down on here with our acquisition machine or focus there. Overall we think about oil deals of this payer equity funded today where our distribution go up over the next year by doing this deal.

And that hasn't changed. I will say our commodity assumptions have changed but it becomes more conservative on NGL pricing and essentially running gas to almost at zero.

So that does point us to more deals in the Northern Midland basin or the eastern portion of the Delaware basin particularly under Diamondback where we're very confident in the development program.

Just wanted to fall off on the commentary around acquisitions, obviously you had a couple of chunky deals closed in the fourth quarter with Santa Elena and the FANG were up-down, just wanted to get a sense is there much of an appetite for anything chunkier here in the short term or should we try to maybe just expect kind of a better stream and kind of the little tiny deals out there that add up over time?

I think we're really focused on -- we did some very large deals last year, especially relatively to the size of Viper and I think for our investors particularly in these uncertain times, it's important for us to prove that there is organic growth on the asset and production per million units is going up. I am not going to say we're not going to look at some small deals here and there particularly on the Diamondback, but today as I see it, there is not a kind of huge deals we're very interested in and I think bit [ph] asked me to just come in on some of these larger packages as we go through the next couple years.

That's helpful for sure here, I think just looking at the G&A side of the equation, I think you guys came out somewhere in the low to mid 70s per BOE in 2019 looking at your guide, you're saying under 80 for 2020, I guess that implies flattish, I guess that would have expected with the big production bump that you get from the acquisitions and 4Q it runs in a little bit into the first quarter of '20 that maybe your per unit GOE -- G&A per BOE would drop a little bit in 2020. Just a little potential for that to come down a little bit, is under 80 maybe just a conservative way of looking at it?

I think when you run a company, a $4.5 million company with $7 million of your cash G&A, you need to save some for the good guys and we've always been pretty conservative on the G&A guide. We're certainly not adding a ton of people this year, but we do have back-office and we get 300, 400 wells a quarter that we're adding, but we have to make sure we're going to be paid on.

So overall I think we're not going to increase G&A much on a gross basis that always will help a little bit, but we're saving that for the good guys.

Kaes, was just wondering -- appreciate all the detail but on the reserve side as you talk about booking pretty conservatively, what's the makeup of Diamondback versus the third parties in terms of the reserves?

Yes so on the PUD side, we really don’t like PUDs. The majority of our PUDs that we booked are 80% or 85% Diamondback operated, the rest are third parties and really those third-party PUDs are either dust that we now are going to get completed or wells in Spanish Trail that are operated by a [indiscernible].

So overall you’ve seen the PDP percentage of Viper go up from 72% in 2019 -- sorry 2018 to 78% in 2019 and given the liquidity the company has it's not a big push for us to continue to book PUDs aggressively either Diamondback operated or third party operated.

With the Railroad Commission coming out with a gas flaring report soon, how does gas flaring in the Permian or just the need to limit planning potentially impact your outlook for pace of development over the next couple of years if at all?

Yeah certainly the flaring has appropriately gotten a lot of attention out here in the Permian basin, but as it has actually translated into our forecast that's something we studied very, very closely and monitor weekly at the Diamondback level and we take mitigating steps across the board to eliminate any flaring that we're in control of. How it reads through the third-party -- third-party production forecast as of yet is still undefined.

We're all interested in Commissioner [indiscernible] report that's going to come out here shortly to see how each individual operator looks across the Permian basin, but so far TJ we're not taken into any of our forecasting the impacts of flaring or increased flaring regulation.

Just lastly if acquisitions do slow down potentially, just any guidance you can give on when you would expect to be a cash tax payer?

It's very dependent upon the well price at the moment at low 50s where we are today, I think we're okay for a couple years, should we see a massive ramp in commodity price that would change and accelerate but where we're today at strip I think we're okay for 18 to 24 months.

So to the pushback we sometimes get on the mineral space, is that organic growth isn’t sustainable if M&A is required to backfill net well location? You show on Slide 11 an inventory at 128 net locations or probably here inventory based on 20 net location this year with 50% of that FANG operated.

I am just curious like let's say Viper wasn't to do M&A in 2020, can you give us a sense on what organic growth would look like in 2021 and obviously this is not guidance but I am just trying to get a sense on could we still see double-digit organic growth in 2021?

I am not going to get talked into 2021 guidance here. We'll tell you for one thing, most of our assets we buy you're seeing the first or second well in a section be completed.

So we don't buy a full section that's just going to be a PDP blow down. Most of our reserves are in the 3P category that you don't see in the reserve report.

We got a long way to go. We got a ton of inventory ahead of us.

We've been two rigs in Spanish Trail for the last five years and we're still going to keep doing that the next few years. So we backfill that undeveloped inventory with undeveloped resource throughout both basins and we expect to be around and to grow organically for a very long time.

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