Greetings, and welcome to the Kimbell Royalty Partners First Quarter 2021 Earnings Conference Call. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Rick Black. Thank you, Rick. You may begin.

Thank you, operator, and good morning, everyone. Welcome to the Kimbell Royalty Partners conference call to review financial and operational results for the first quarter 2020. This call is also being webcast and can be accessed through the audio link on the Events and Presentations page of the IR section of kimbellrp.com along with a supplemental presentation. Information recorded on this call speaks only as of today, May 6, 2021, so please be advised that any time-sensitive information may no longer be accurate at the time of any replay. I would also like to remind you that the statements made in today’s discussion that are not historical facts, including statements of expectations or future events or future financial performance, are forward-looking statements made pursuant to the safe harbor provision of the Private Securities Litigation Reform Act of 1995. We will be making forward-looking statements as part of today’s call, which by their nature, are uncertain and outside of the company’s control. Actual results may differ materially. Please refer to today’s press release for our disclosure on forward-looking statements. These factors and other risks and uncertainties are described in detail in the company’s filings with the Securities and Exchange Commission. Management will also refer to non-GAAP measures, including adjusted EBITDA and cash available for distribution. Reconciliations to the nearest GAAP measures can be found at the end of today’s earnings release. Kimbell assumes no obligation to publicly update or revise any forward-looking statements. I would now like to turn the call over to Bob Ravnaas, Kimbell Royalty Partners’ Chairman and Chief Executive Officer. Bob?

Thank you, Rick, and good morning, everyone. We appreciate you joining us for this call. I’m joined here on the call with several members of our senior management and technical team, including Davis Ravnaas, our President and Chief Financial Officer; Matt Daly, our Chief Operating Officer; Blayne Rhynsburger, our Controller; Marco Pena, our Associate Engineer; Michelle Scarborough, our Associate Geologist; and Ryan Pollyanna, our Head of Data Analytics. I will begin today’s discussion by providing comments about our first quarter. I will then discuss the exciting results from our extremely detailed review of Kimbell’s extensive acreage portfolio, which we are releasing today after over a year’s work by our technical team. Before we turn the call over for questions, Davis will walk you through our financials for the quarter in more detail. Let’s start with looking at our performance in the first quarter. Improved pricing in the quarter as compared to the fourth quarter of 2020 was the primary driver for our significantly improved cash distribution of $0.27, which was up 42% as compared to the fourth quarter of 2020 distribution. Realized oil prices were up 37%, realized natural gas prices were up 62% and realized NGL prices were up 63%. Operators generally appear to be maintaining discipline with their capital expenditure programs with a greater focus on free cash flow generation and distributions to their shareholders. During the first quarter production curtailments due to the February 2021 freeze across a large part of the United States resulted in approximately 1.2 days of lost production or 188 BOE per day. With these curtailments now behind us and increased activity as evidenced by the 26% increase in the rig count on our acreage compared to year-end 2020, we are optimistic that Kimbell will experience improved production levels on its acreage as we progress through 2021. Now I would like to discuss our detailed portfolio review and the results that have come from it. This morning, we posted a new supplemental presentation on our website that provides further details of what I will be discussing. The presentation can be found on the Investor Relations section of our website. More than a year ago, we began this deep dive review into our extensive acreage portfolio. The resulting information that we discovered was that as of March 31, 2021, Kimbell had 10,160 gross and 68.1 net undrilled upside locations on our acreage – on our major acreage. This represents an estimated 15 years of future drilling inventory based on the pace of well completions during 2019, which we believe is a more normalized rate of well completions given the pandemic slowdown in 2020. Approximately 80% of the total undrilled net inventory is located in the Permian, Eagle Ford and Haynesville, which has some of the best economic returns and lowest breakeven costs in the U.S. Let’s now discuss the methodology we used for this detailed portfolio review. We implemented this review in order to quantify the number of undeveloped drilling locations, both gross and net located on our acreage. Across our 13 million gross acres it is very time-consuming to track upside for all of our minor properties, which we define as generally having a net revenue interest of 0.1% or below. Therefore, only major properties were identified during this exercise. We believe, however, that including our minor properties would have added up to an additional 20% to our net undrilled locations, which could be potentially as high as 85.2 net locations. This analysis was reviewed by leading third-party independent engineering firm, Ryder Scott. In terms of background, Kimbell does not book any upside reserves in the year-end reserve report filed with the SEC. However, for the purpose of this exercise and based on the general reserve categories defined by the SPE Petroleum Resources Management System Guidelines, we believe that these upside locations fall under the general classifications of proved undeveloped, probable and possible reserves. With regard to KRP’s underwriting criteria, upside development spacing was determined utilizing offset development trends by surrounding operators, consistent with a conservative underwriting approach. Development spacing varies basin by basin and takes geology, operator, and current rig counts into consideration. The average range of gross wells per DSU fluctuates between 5.9 in the Haynesville to 12 in the Permian. These figures were derived from Kimbell’s internal reserves database, which we believe are conservative spacing assumptions when compared to our peers. And it is important to note that DSUs can vary in size. Again, the locations reviewed only include Kimbell’s major properties and did not include Kimbell’s minor properties, which generally have less than a 0.1% net revenue interest and are time-consuming to quantify. But in our judgment would add up to an additional 20% to Kimbell’s net inventory in the aggregate. So just to reiterate our conclusions from this detailed portfolio analysis review, in major properties alone, a total of 10,160 gross and 68.9 net, 100% net revenue interest, upside locations were identified in the seven major basins, which KRP owns interests, including the Permian, Eagle Ford, Haynesville, Mid-Con, Bakken, Appalachia and Rockies. Kimbell has consistently demonstrated a strong track record of producing a stable growth profile organically in legacy assets, as well as through strategic acquisitions in the most active basins within the lower 48. We believe our low PDP decline and diversified royalty portfolio is a core competitive advantage for our company in the mineral and royalty space that provides long-term stability for Kimbell. In addition to the location analysis that we completed, we were also confirming today that we have concluded that Kimbell only requires approximately 4.5 net wells each year to keep production flat, given our superior PDP decline rate. It is important to note that I’m extremely proud of the skilled and dedicated effort and the 19 months of hard work spent by our engineering, land and geological teams to carefully analyze our 13 million gross acres across the U.S. As we continue to move forward in 2021, I like to reiterate that we remain focused on our role as a major consolidator in the highly fragmented U.S. oil and gas royalty sector, assembling a high-quality, low PDP decline and diversified royalty portfolio generating recurring cash flow with significant growth potential and no capital requirements. Our vision for Kimbell since inception has always been long-term focused on sustainability and growth. In summary, we are very optimistic about the future of our industry given rapidly improving fundamentals across the U.S. energy sector. We are also excited about the opportunities to further expand our acreage footprint and deliver compelling value to our unitholders for years to come. And with that, I’ll now turn the call over to Davis.

Thanks, Bob, and good morning, everyone. As Bob mentioned, we are very excited to share the results of our deep dive detailed analysis review of Kimbell’s current portfolio. We have been extremely acquisitive over the last couple of years, so it’s important for us to take a step back, perform the analysis in a careful and deliberate way. This analysis was reviewed by a leading third-party independent international engineering firm, Ryder Scott, to assist us and finally conclude and communicate to our investors where our portfolio stands today with regard to future drilling inventory. Before commenting further on that, I would like to provide an update on the company’s first quarter results. We’ve been very pleased with pricing improvements through the first quarter of 2021 with realized oil prices up 37%, realized gas prices up 62%, realized NGL prices up 63%. Based on positive trends and improving cash flows in the quarter, we announced a substantially higher cash distribution of $0.27, up 42% from the Q4 distribution in 2020. As we have done in previous quarters, the company utilized 25% of its Q4 2020 cash available for distribution to pay down a portion of the credit facility in Q1 2020. Since May 2020, the company has paid down approximately $25 million in debt by allocating a portion of its cash flow to debt repayment. We expect to continue to allocate 25% of our cash available for distribution for debt repayment in the future. Also, we believe our hedging strategy is a prudent methodology for managing the company’s future price risks on oil and natural gas. Having substantial hedges in place on a rolling two-year basis before the price shocks that occurred in 2020 proves to be a very effective risk mitigation strategy. For the first quarter of 2021, the company’s oil, natural gas, and natural gas liquids revenues were $36.4 million, which reflected first quarter average realized prices significantly higher at $54.52 per barrel of oil, $3.31 per Mcf of natural gas, and $24.45 per barrel of NGLs, for a total combined BOE of $29.45. Our first quarter average daily production was 13,721 BOE per day comprised of approximately 61% from natural gas on a 6 to 1 basis and 39% from liquids or 26% from oil and 13% from NGLs. Impacting the first quarter, we recorded identifiable weather-related production curtailments in February from freezing temperatures over a substantial cross-section of the U.S. We estimate that this resulted in approximately 1.2 days of lost production or approximately 188 BOE per day. Production activity quickly rebounded in Q1 and rig counts grew 26% compared to the end of Q4. The company had 49 active rigs at the end of Q1 2021, led by Permian and Haynesville basins. Based on the level of activity we are seeing on our acreage and improved pricing, we are affirming our 2021 guidance that we outlined with our Q4 2020 earnings release. As of March 31, Kimbell had 761 gross and 2.2 net drilled but uncompleted wells, as well as 669 gross, or 2.54 net permits on its acreage. This data does not include our minor properties, which we estimate could add an additional 20% to the DUC and permit net inventory. As I mentioned earlier, Kimbell’s rig counts increased from 39 at the end of the last fiscal year to 49 active rigs on our property at the end of Q1, up a solid 26%, which represented an approximate 12% market share of all rigs drilling in the lower 48 at that time. On the expense side, general and administrative expenses were $6.8 million in the quarter, $4.1 million of which was cash G&A expense or $3.32 per BOE. First quarter consolidated adjusted EBITDA was $26 million, an increase of 46% compared to the prior quarter. Net income for the first quarter was approximately $537,000 and the net loss attributable to common units was approximately $704,000 or $0.02 per common unit. The $0.27 per common unit distribution this quarter reflects a 75% payout of cash available for distribution. We will use the retained amount to pay down a portion of the outstanding borrowings under Kimbell’s credit facility. As in previous quarters, our focus is to manage our liquidity and balance sheet in a disciplined manner, especially given the broader market shocks experienced in 2020. You will find a reconciliation of both consolidated adjusted EBITDA and cash available for distribution at the end of our news release. Looking now at the balance sheet and liquidity. As of March 31, 2021, Kimbell had approximately $168.5 million of debt outstanding under a secured revolving credit facility. In addition, the company’s net debt to trailing 12-month consolidated adjusted EBITDA was approximately 2.2x. And Kimbell was in compliance with all financial covenants under its secured revolving credit facility. Our liquidity position was strong with $96.5 million of undrawn capacity under our secured credit facility as of the end of the first quarter. Adding to Bob’s comments about the detailed portfolio review, our team, in coordination with the leading third-party independent international engineering firm, Ryder Scott, did an outstanding job on this detailed review. We are very pleased with the results and believe that with a drilling inventory of over 15 years, we hope that Kimbell investors will number one, be even more comfortable with Kimbell’s long-term business model and its ability to generate future cash distributions and cash flow. And number two, be pleased with the increasing visibility and transparency that this information provides both in terms of undrilled well locations and the relatively small number of wells needed to keep production flat given our superior PDP decline. We are very proud of our team, and it’s the culmination of hundreds, if not thousands of man-hours over the course of the last 19 months. We believe that Kimbell offers a compelling investment opportunity with growth opportunities and a robust distribution yield, which we expect our distributions to be substantially free of dividend income taxes through 2023. And instead, to be considered a return of capital to the extent of a unitholders basis and its common units. Kimbell will continue with our goal and focus of generating long-term value and cash generation with transparency to investors for many years to come. With that operator, we are now ready for questions.

Thank you. Thank you. Our first question comes from Harry Halbach with Raymond James. Please proceed with your question.

Hey guys, congrats on the strong quarter.

Thank you.

So you all mentioned your strategy of hedging kind of two years in a row forward basis. I know that the oil hedges have kind of dropped by around 15% each in the last few quarters, is that a function of the backwardation in strip or is it more about leverage improvements increasing your appetite for exposure, and should we expect the hedges to keep falling?

Yes. Pretty simple formula, we just take our debt plus our preferred divided by our enterprise value and every quarter roll forward that percentage of our production hedged, so market cap is up 40% or whatever so far this year or so. The denominator in that equation has increased, therefore, making the percentage go down. So yes, as leverage becomes less of an issue overall to the enterprise, we feel more comfortable taking more exposure to the commodity directly.

And also Harry, this is Matt. As you know, as we roll the hedges into Q2 of 2023, it is in a pretty steep backwardation. The prices are in the high-50s right now, so that will probably be the next sort of price level we will be hedging out in 2030.

Great. Thanks for the color. And then, I was kind of looking at the slide deck on the inventory deep dive. Certainly, seems very conservative. I mean, you all exclude the formations like the Austin Chalk, where we’ve seen a lot of success lately. Could you maybe just talk about some of the upside potential sort of baked into this and what’s got you all excited across the portfolio?

Yes. We were very conservative in the inventory analysis, so thanks for mentioning that. I think a couple of things on that, and then I’ll open it up to – we’ve got Marco and Michelle in here, the engineer and geologist, respectively, that did this work and had it reviewed by Ryder Scott. So, when we say 15 years of inventory, that’s based on 2019 drilling pace, which resulted in, I think, 8% organic growth. If we just wanted to keep production flat on the asset, it’s actually 19 years of inventory, so this is mind-boggling and took us 19 months of work to do this. And clearly, nobody is paying attention because our stock price is down today, so I recommend that people start talking about this. But yes, we did not do loony-tunes assumptions on the spacing, which is why we actually included per DSU what we’re doing and that’s how we did the detail on the assumptions in the units. Our peers, for example, book anywhere from like 15 to 24 wells per section in the Midland and Delaware Basin. I think we’re assuming 12, but maybe a few exceptions. We gave – did we give any credit to the Austin Chalk at all?

Only if it was a DUC or permit.

Only if it was a DUC or permit. Okay. So there’s a lot of I would say, there is additional upside that we haven’t captured. There’s Three Forks upside up in the Bakken we haven’t talked about, additional density in the Haynesville we haven’t discussed, that could be justified with higher gas prices. Anything else guys?

Yes, there are zones in the Delaware.

Other zones in the Delaware, other zones in the Midland, other zones in the Midland. So I think it’s extremely conservative and I think the conclusion should be, man, these guys have 19 years of inventory to keep production flat, using conservative assumptions, and I think basically what we’ve proven and again, it’s been audited by or reviewed by an outside engineering firm, Ryder Scott, we basically have production upside on our properties until the end of hydrocarbons. I mean, that’s effectively what our portfolio has. So again, this is something we started doing almost two years ago. It’s been a mind-boggling amount of work and I think that the results speak for themselves.

Yes. Great, guys. Thanks for all the color. I appreciate you taking my questions.

Thank you. Our next question comes from Derrick Whitfield with Stifel. Please proceed with your question.

Good morning, all and congrats on your quarter. And certainly thanks for the detailed asset disclosure you provided with this release.

Thanks, Derrick. I appreciate that.

Perhaps picking up with the last question, while you guys clearly know your asset base better than anyone else, did the third-party assessment meaningfully change your view on any given area?

Marco? Can we get the mic over to Marco?

Yes, we went to Ryder Scott back in March and really we provided them our full 3P database but since we did not disclose these 3P reserves, there is more so just going through our locations, putting those on the map and comparing the type curve areas versus the PDP offset, just to make sure that they are comfortable with our forecast, our scheduling, the number of locations per DSU. So, the final deliverable that they sent us was a signed letter stating that the 3P reserves fall within all the SPE.

Is there anything they said that changed our – do they have any like pacing, where they cut back on us dramatically or felt we were too conservative that comes to mind or do they think of it generally, I think that’s what…

Yes. There might have been a couple of type of areas like in the Bakken for the Three Forks, for example, where the offset PDP wells were a little under our tighter forecast and so we agree with them and we did a deeper dive. So we did cut back on a couple of type of areas, but for the majority of it, our view was in line with that.

With the independent assessment. Yes, couple of tweaks here and there, which always happens, but generally, in agreement. And Ryder Scott’s about as conservative as it gets, softer than in there too.

Absolutely, and the asset base is exceptionally deep and thanks for that disclosure. And maybe for my follow-up, wanted to shift over to your rig count market, as your gains have been exceptional as noted on Page 12. As you evaluate the near-term permit backlog and with the long-term resource assessment with Ryder Scott, would it be fair to assume that you guys can likely sustain that level of success for the next several years?

I mean, Derrick off the top of my head – this is Davis. I mean, I think what we’re showing is kind of what we bought every single one of these deals, right? So this goes back to 1998 when my dad was – started this with him. We’ve always known that there was a ton of upside on our properties because we engineered each one of these assets individually. What’s been challenging for us is we’ve always targeted a business model that has low decline and growth and I think that’s unusual. There are very few companies like ours. I think the closest companies are up in Canada, candidly. There are very few U.S. companies that have that kind of nice blend of low decline but then upside. And so, it’s always been frustrating for us and I just got tired of hedge fund guys beating up on us on well, you’ve got a great decline that’s shallow, but you don’t have the 80% growth every year that some of these other peers are guided toward. And so, we just sat down together and we just said, is there a way that we can actually go through every single one of our units and quantify the upside. And Bob kind of rolled his eyes and was like, man, that’s going to take years to do and so we staffed up. We hired Marco recently or actually a couple of years ago and basically just full-time job, 50-hours a week was building out these maps. I mean, we did over 1,000 units across our 13 million acres and I asked that question yesterday and I was mind-blown and individually cut it up every single one of them and then showed that to Ryder Scott so that we can show you guys that we had somebody independent look at it. We’re not just making this up and so long answer to your question is, I think we have confidence that our production rates can be sustained like I said for 15 to 20 years. I mean, I really – we really do have that confidence and we’re not going to get – I think, look through the detail on the assumptions we use, I think after you spend some time looking at it, you’ll hopefully agree.

I do and I’ll tell you my quick gut reaction when I first kind of flipped through the presentation was the asset quality in the Midland Basin and Haynesville are exceptional. So, we certainly look at your position and see it in your market share and see that as something that’s quite sustainable. So very helpful guys. Thanks for your time.

Thanks, Derrick. Thanks for paying attention. Thank you.

Thank you. Our next question comes from Chris Baker with Credit Suisse. Please proceed with your question.

Solid update on the inventory side, maybe just to take a little bit of a different angle to it. Still working through all the details provided but clearly, a lot of undeveloped potential there. Wondering if you could share your thoughts at this point around the potential consideration of share buybacks or perhaps maybe a small divestiture to kind of help demonstrate this value to the market. Just any thoughts there would be helpful.

Great point. I think my thoughts – our thoughts on divestment, we’ve only sold assets once in our entire history as an enterprise going back 25 years and that was non-producing assets in Delaware that we sold, I think in 2018 for just like a ridiculous price to an undisclosed buyer. I think our view is that we need scale and that’s I think the most critical weakness in the mineral sector is that you’ve got these five companies and really only one or two of them have meaningful scale and even those companies need to get bigger and I think they would agree. So when we divest, it kind of runs counter to that. Now that being said, are there certain assets that we could look at and sell for eye-popping valuations? We did that in the past with kind of the low-hanging fruit that we saw when people were paying just outrageous multiples for non-producing assets. We don’t have much in the way of non-producing now. Chris, you know, our strategy has always been, we have to have at least one producing well on a unit for us to buy it. We like to get our money back on PDP alone and then the upside is something that we pay for, but we at least get our money back on the existing development. The weakness in this model that nobody likes to talk about is that we don’t have control over the drill bit. We could have the absolute best section in Midland County and we can’t force Pioneer to develop it, right? So the only way we get comfortable is buying stuff that has production. So that being said, we don’t have any kind of easily divestible assets that are all just non-producing, where we’re going to get another home run kind of sale like that. So I think we are a little bit against divesting the assets. I think that runs counter to our view that we need to continue to consolidate and get bigger and capture synergies and just increase liquidity. But on your point of buybacks, we talk about it all the time. I think our view – and we talk to our shareholders about it all the time and I think that the consensus view from our shareholder base, and they’re the folks we work for, is they’d rather see us pay down debt as opposed to buying back stock. Paying down debt is something that’s concrete, that’s something that improves the balance sheet. It is accretive to equity. Enterprise value is the same, debt goes down, equity goes up. When we think about buying back stock, the problem with that is you could just – we could spend $10 million a quarter buying back stock and that’s great, but if somebody could just sell right into it, that – just out of nowhere and it’s kind of like man, I wish we had paid down debt instead of doing that. So the tax benefit of buying back stock versus sending cash flow back or paying down debt is not lost on us. But I think what’s unique about our company, Chris, is that our dividends are tax-free, so we send money back to our investors. We’re giving them the opportunity to buy back stock. If they want to buy more stock in our company, they can take our dividend, they don’t have to pay any taxes and they can buy our stock. We don’t think we should be making that decision for them at the corporate level. I hope some of that makes sense and we talk about this all the time.

And Chris, also these buybacks, as you know that, that reduces our float. We try to increase our trading volume well.

Nailed it, good point. That’s right.

Okay, great. And then, can you just remind us in terms of the leverage target? Just in terms of how quickly you think you can get down to that level? Just thinking about the potential to take out the preferred with the revolver and potential timing for when you achieve that leverage target would be helpful.

So we’re going to take out the preferred next quarter. We talked about that on the last call, that’s going to bump our leverage up and then we’re going to continue to pay down debt until we get to at least below 2x, probably closer to 1.5x as we previously disclosed. Do we have – does anybody know off the top of your head when we anticipate that happening?

I wouldn’t want to give guidance right now. I mean, there are so many variables in there in terms of commodity prices.

The other thing, Chris, too is just kind of tough to answer that question because we can make one acquisition that’s $300 million and by $50 million of EBITDA and then all the sudden – do that with equity and all of a sudden we’re below 2x or 1.5x immediately. You see what I’m saying, so it’s kind of like you’d have to assume for us to give that question, we have to assume that we don’t buy anything ever again, which obviously isn’t going to happen. So anyway.

Great. Appreciate the color guys.

Thanks, Chris.

Thank you. There are no further questions at this time. I would like to turn the floor back over to management for any closing comments.

We thank you all for joining us this morning and look forward to speaking with you again when we report second quarter results. This completes today’s call.

This concludes today’s conference. You may disconnect your lines at this time. Thank you for your participation. Have a wonderful day.