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Operator: Greetings, and welcome to the Kimbell Royalty Partners Fourth Quarter Earnings Conference Call. And as a reminder, this conference is being recorded. It is now my pleasure to introduce to you, Rick Black, with Investor Relations. Thank you, Rick. You may begin.

Rick Black: Thank you, operator, and good morning, everyone. Welcome to the Kimbell Royalty Partners’ conference call to review financial and operational results for the fourth quarter and the full year ended December 31, 2022. 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. Information recorded on this call speaks only as of today, February 23, 2023, so please be advised that any time-sensitive information may no longer be accurate as of the date of any replay listening or transcript reading. 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’s 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 earnings 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. With that, I would now like to turn the call over to Bob Ravnaas, Kimbell Royalty Partners’ Chairman and Chief Executive Officer.

Bob?

Bob Ravnaas: Thank you, Rick, and good morning, everyone. We appreciate you joining us on the call this morning. With me today are several members of our senior management team, including: Davis Ravnaas, our President and Chief Financial Officer; Matt Daly, our Chief Operating Officer; and Blayne Rhynsburger, our Controller. We are pleased to report another very strong year for Kimbell, which included new records for revenue, EBITDA, distributable cash flow per unit and net income in 2022. In addition, we strengthened our financial flexibility by increasing our borrowing capacity and maintain a conservative balance sheet with net debt to trailing 12-month adjusted EBITDA of 0.9x. We also completed a highly attractive and accretive acquisition in one of the highest quality and most active parts of the Permian Basin in December.

The Hatch acquisition reestablished the Permian as the leading basin for the company in terms of production, active rig count, DUCs, permits and undrilled inventory. For the fourth quarter, including a full quarter of production from the Hatch acquisition, run rate daily production exceeded 17,000 BOE per day for the first time in our history. To put that in perspective, when Kimbell IPO-ed in 2017, production was 3,116 BOE per day. This massive growth in production represents a 5.5x increase largely a result of our continued consolidation of the mineral space. Today, we also declared a cash distribution of $0.48 per common unit. Again, looking back to 2017 through today, the total cash distributed to common unit owners since we became a public company is $8.45 per common unit.

Turning to the operating environment in the fourth quarter. We had a record 92 rigs actively drilling on our acreage at the end of the year, representing 12.1% market share of all rigs drilling in the Continental United States. We also had a record number of net DUCs and permits, which is unique given the massive drop in DUC inventory nationwide. While the U.S. rig count increased during the year and is now approaching pre-COVID levels, we do not expect much in the way of significant oil production growth from U.S. operators. A primary reason for this is that the number of DUCs in the U.S., one of the best indicators for near-term production growth has dropped precipitously since 2020. In fact, in the Permian Basin alone, DUCs have dropped from a peak of over 3,500 in July 2020 to just over 1,000 a day, levels not seen since 2015.

While many companies will focus on replenishing their DUC inventories in the short term, we believe that inflationary pressures in the drilling, completion and labor side of their businesses will continue to temper oil production growth during 2023. Production stability, profitability and quality of inventory will continue to be the primary themes of energy investing rather than the hyper growth models of the past. At Kimbell, we updated our detailed portfolio review that we initially introduced in May of 2021, and we are very pleased to report that the results of the review confirmed an estimated 19 years of drilling inventory, a superior five-year annual average PDP decline rate up 12% and only 4.5 net wells needed per year to maintain flat production.

We continue to believe that Kimbell has a shallow decline rate of any public minerals company. This characteristic is no accident. We designed Kimbell this way so that we can more easily generate organic growth and stable production through various market, environments and cycles. We will continue to drive growth through our disciplined acquisition strategy that is both a consistent and proven method that has been in place for over 20 years. We employ a strict set of time-tested acquisition criteria focused on adding quality production with low PDP decline rates and upside drilling locations in a transaction that is accretive to our unitholders. We are now realizing the benefits of this acquisition strategy as reflected in our record profitability, record production, high-quality inventory and conservative balance sheet.

Turning now to the commodity environment. We remain structurally bullish on oil over the long term due to years of extremely low investment, especially among energy companies outside of the United States and strong global demand trends that we expect to accelerate later in 2023. For Kimbell, we maintain a strong competitive advantage of being a pure royalty company, namely we have zero inflationary risk in terms of drilling and production costs, yet we received the upside from higher commodity prices. We expect to continue our role as a major consolidator in the highly fragmented U.S. oil and gas royalty sector that we estimate to be over $700 billion in size. And as I’ve stated in the past, there are only a handful of public entities in the U.S. and Canada that have the financial resources, infrastructure network and technical expertise to complete large-scale multi-basin acquisitions.

We believe that we are still in the early ages of this consolidation and will actively seek out targets that fit within our acquisition profile. Finally, we are very grateful to our employees, Board of Directors and advisers for their contributions to our company achieving record results in 2022. We are excited about 2023 and the prospects for Kimbell to generate long-term unitholder value for years to come. I’ll now turn the call over to Davis to review our financials in more detail before we open the call to questions.

Davis Ravnaas: Thanks, Bob, and good morning, everyone. We are very pleased to report record performance during both the year and the fourth quarter. In addition, today we are providing our full year 2023 guidance. I’ll start by reviewing our financial results from the fourth quarter, beginning with oil, natural gas and NGL revenues of $64.4 million a decrease of 13% from the third quarter primarily due to a decline in realized commodity prices. Kimbell’s fourth quarter average realized price per barrel of oil was $82.04, per Mcf of natural gas was $5.02, per barrel of NGLs was $30.55, and for BOE combined was $43.65. Our record fourth quarter run rate daily production was 15,394 barrels of oil equivalent per day on a 6:1 basis, an increase of 3% from Q3 2022.

This daily production was comprised of approximately 61% natural gas, again on a 6:1 basis, at approximately 39% from liquids, 26% from oil and 13% from NGLs. The fourth quarter run rate daily production includes only 17 days of production from the company’s $270.7 million acquisition of mineral and royalty interest held formally by Austin-based Hatch Royalty that closed on December 15, 2022. Including a full Q4 2022 impact of the acquired production, the revenues from which will be received by the company, run rate production was 17,176 BOE per day, a new record for Kimbell. As of December 31, Kimbell’s major properties had 882 gross and 3.67 net drilled but uncompleted wells as well as 675 gross and 3.27 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 inventory.

The total amount of net DUCs and permits at year-end was 6.94, which is higher than the 4.5 net wells we need to maintain flat production. Based on this metric, we are optimistic about the production profile we expect for Kimbell as we progress through 2023. On the expense side, general and administrative expenses for Kimbell were $7.2 million in the quarter, $4.2 million of which was cash G&A expense or $2.97 per BOE. Fourth quarter net income was approximately $35.2 million. Total fourth quarter consolidated adjusted EBITDA was $46.2 million. You will find a reconciliation of those consolidated adjusted EBITDA and cash available for distribution at the end of our news release. Today, we announced a cash distribution of $0.48 per common unit for the fourth quarter.

This represents a cash distribution payment to common unitholders of 75% of cash available for distribution and the remaining 25% will be used to paydown a portion of the outstanding borrowings under Kimbell’s secured revolving credit facility. Since May 2020, excluding this upcoming Q4 payment, Kimbell has paid down approximately $86.1 million of outstanding borrowings under its secured revolving credit facility by allocating just a portion of its cash available for distribution for debt paydown. Commenting further on our balance sheet and liquidity, As of December 31, Kimbell had approximately $233 million in debt outstanding under its secured revolving credit facility. And also had a net debt to fourth quarter, 2022, trailing 12 months consolidated adjusted EBITDA of approximately 0.9x and remained in compliance with all financial covenants under its secured revolving credit facility.

Kimbell had approximately $117 million in undrawn capacity under its secured revolving credit facility. We believe the company is in a stronger financial position today than it has been at any point and the last five years. Today, we are providing full year 2023 guidance, which includes production guidance that at its midpoint reflects roughly flat daily production relative to our fourth quarter 2022 run rate daily production including a full quarter of the acquired production from Hatch. We believe that most operators will focus their 2023 budget on replenishing their DUC inventories with a goal of flat to low single digit production growth in 2023. We also anticipate in our guidance a slightly higher production contribution from oil in 2023 compared to last year.

This is due to the Hatch acquisition, which is, primarily liquids focused. We expect an approximately 68% of the Q4, 2022 distribution declared today will be considered return of capital and not subject to federal income taxes with the remaining considered a qualified dividend for tax purposes. We continue to believe our tax structure provides a highly compelling competitive advantage in terms of generating superior after tax returns to our unitholders. We began the year having grown our borrowing base and elected commitment on our revolving credit facility to $350 million with enhanced liquidity and a conservative capital structure. In 2022, we paid out $1.88 in tax-advantaged quarterly distributions during the year and paid down approximately $41.5 million on our credit facility.

We are confident that Kimbell is well positioned for continued growth in 2023 with a resilient business model that continues to perform very well in the highly cyclical energy industry. We will continue to benefit from a dynamic and diverse portfolio, which is largely the result of strategic acquisitions, both recent and historic. We are focused and energized in pursuit of continuing to generate long-term unitholder value for years to come. With that, operator we are now ready for questions.

Operator: Thank you. Thank you. And our first question comes from the line of John Annis with Stifel. Please proceed with your question.

John Annis: Hi, good morning, all. And congrats on a strong quarter.

Bob Ravnaas: Yes, thank you.

John Annis: For my first question, I wanted to ask about your views on an optimal leverage ratio. As you continue to paydown debt, how should we think about the use of cash once that level is met? Do you put it on the balance sheet with near-term macro uncertainties or providing dry powder for M&A or would you consider increasing the payout?

Davis Ravnaas: Yes, great question, John. That’s probably the thought that we – and the conversation that we at the management and Board level, have most often. It’s a high-quality problem, obviously. What — what does the company do with its cash flow? And I think the first priority will always be to send distributions on a quarterly basis to our unitholders. That being said, we started during COVID allocating 25% of cash flow to debt paydown. We’re very happy and pleased that we did that historically. For the time being, we intend to continue that same policy, which would be to allocate 75% of cash flow to distributions and 25% to debt paydown. We had originally targeted a leverage ratio of – frankly, looking back over time, the leverage ratio that we’ve targeted just continues to get lower and lower.

It seems like the investor appetite for leverage in this business just continues to get lower and lower. And credit facilities and debt in general, has just become much more difficult to come by in the space due to a variety of factors, many of which are unfounded, in our opinion. But we’re at a nice milestone, currently which is less than one times to EBITDA. I think we will continue to drive that down lower over time. Obviously, with natural gas prices dropping, we think it’s even more important, so precipitously, I think, 65% since mid-December. We think it’s even more important in that environment to pay down debt, particularly when the — when interest rates have risen so rapidly that – the return you get from paying out our revolver is better today than it obviously was really at any point since we’ve gone public.

So locking in kind of a guaranteed all-in 8% cost of capital by paying down our revolver is not a bad way to allocate capital and allocate that cash flow. So long winded answer to the question, but I think we’ll continue to drive debt lower. There may be a point at which we consider buybacks or allocating capital to third-party acquisitions will obviously weigh the relative benefits of buying an external asset and relative to buying our own assets or stock, which we know better than anyone does, of course. Then we’ll make a judgment call into – what we think would generate better returns at that point. But for now, continuing to paydown debt, I think, is what we as management and the Board believe is the best and highest use of our capital at this moment.

John Annis: That makes sense. And then for my follow-up, understanding the ink is still wet on the Hatch deal. I wanted to ask for your thoughts on Kimbell’s role in consolidation in the mineral space. You highlighted being one of the few companies that can execute on large multi-basin acquisitions. In your view, which basins screen most attractive? And are you starting to see seller expectations come in with the pullback in the commodity?

Davis Ravnaas: Yes, great question. I could go on and on. I’ll try to keep it short. Hatch was a fabulous deal for us. It was the right asset at the right time. Given the outperformance of oil relative to gas, it’s even more accretive to us today than it was at the time of underwriting. I’ll also share that production volumes are slightly ahead and underwriting expectations. So it’s always nice to see when the deal is off to a good start. We’re proving to be very conservative in how we’re forecasting DUC completions. So looking at the environment today, this could be from a – from the folks that we speak to and the relationships we have on the banking side. This could be a little bit of a tougher year from an A&D perspective that tends to always happen when you see huge fluctuations in price one way or the other on either the oil or the gas side.

So I think we look at this environment and say, we’re never going to be the largest mineral company out there. We don’t want to be the largest mineral company out there. We’re not going to win every deal that we look at. In fact, we lose 95% of the ones that we bid on. But every once in a while, we’ll find an acquisition at the right time that’s accretive to us and meets our underwriting criteria, and we’ll execute. So we continue to believe that, that strategy of being patient and being conservative has worked out for us for 25 years of doing this. So I think we’ll just kind of continue down that path going forward. What was the second part of your question, John, forgive me?

John Annis: Related to which basins are screening most attractive?

Davis Ravnaas: Yes. So it fluctuates. I would say that we haven’t done a gassy deal in quite some time, the largest of which obviously was Haymaker, which was, in our opinion, the best mineral footprint in the Haynesville and continues to be the best mineral simply in the Haynesville. So — but then again, we got priced out of the Delaware for, what was it, three or four years, Bob and Matt? And then finally, we’re able to pull off Hatch in the fourth quarter, which I think speaks to the fact that, that basin is maturing in such a way that you can buy a nice balance of existing cash flow, which is immediately accretive to distributable cash. But then you also have enough inventory to make it NAV accretive as well. So in this environment, I’d say Permian is still competitive, really tough to buy gas assets.

I don’t think people really want to sell when the strength is down so much and especially spot being — pushing that $2 barrier, I think, is going to be tough. So we look at everything. But if I had to guess, I’d say that opportunities in less favorable contrarian basins, like the Eagle Ford or the Mid-Con, maybe even the Bakken a little bit tougher to buy there with inventory concerns. But I’d say those basins, maybe the Mid-Con first frankly, I think, in terms of value opportunities there, but certainly also the Eagle Ford. And then the Permian is obviously just going to continue to be the big deal source there. It just happens to be more competitive. Bob or Matt, anything you guys want to add there?

Bob Ravnaas: Yes, this is Bob. The only thing I’d like to add too, on that is, I think sometimes people get confused on looking at mineral companies versus operating companies. We don’t operate — if we’re able to get and screen our criteria of — in a basin, we’re able to buy something that is more accretive than in the Permian. And of course, we love the Permian, just like everybody else does. But we aren’t going to buy a dilutive acquisition in the Permian just to grow for growth’s sake. We only do accretive acquisitions. And if we can get a more accretive acquisition and pass all of our screening criteria in other basins, we’ll do that. And by screening criteria is that obviously, we do an acquisition in another basin other than the Permian.

It has to have a lot of runway for — first of all, it has to be accretive, but then has to have long life. We always buy properties that have at least 30 to 40 years of economic life even on low pricing cases. And then it has to have a significant room for development. So that’s how we screen things, and that’s why we’ve grown our company to not focus just on one basin, frankly, because we’re asset managers, we aren’t an operator. And if we can buy something that’s extremely more accretive, and like Davis said, a basin that isn’t as popular as the Permian, we’ll do that. We are not going to do a dilutive deal just to get bigger.

John Annis: Great, color. Thanks for taking my questions.

Bob Ravnaas: Thanks John.

Operator: And the next question comes from the line of Tim Rezvan with KeyBanc Capital Markets. Please proceed with your question.

Tim Rezvan: Good morning, everybody. And thank you for taking the questions. I wanted to start on the production guidance for the year. It’s essentially in line with your current run rate. And you’ve talked about how Hatch is outperforming your underwriting. So I wonder if you could kind of step back a bit and talk about kind of what you’re seeing across the rest of your portfolio? Are you starting to see DUCs getting, kind of, rebuilt a little bit? Are you seeing activity slow down? I’m just trying to understand kind of how you landed on that guidance for the year.

Davis Ravnaas: Yes. No, it’s a good question. First and foremost, I’ll say that we’re — we’ve historically established a pattern of being very conservative with guidance. We think that is prudent and frankly, just the right way to run your business. So if you look back over time, we’ve generally been in line, if not above, kind of the midpoint of our guidance range on just about every factor going back since we started providing guidance a few years ago. Your point raises — your question raises a good point, which is that we’ve made the observation in this press release that our net DUCs and permits are relative to the amount of permits or the amount of completed wells necessary to keep production flat, which is 4.5 net. Our net DUCs and permits, which is over six currently, is that ratio has never been higher.

So that would suggest, assuming historical patterns of DUC completions remain constant, that would suggest that we have some amount of organic growth this year. We feel very good about that number. Let me just put it that way more directly. That being said, in an uncertain environment, our company is still majority gas by revenue and production on a 6:1 basis. And so when you see gas spot at $2, it’s just a harder environment for us to provide, to really get aggressive about what production growth will be. So our hope is that three months, six months from now, you’re on this call and you’re looking at our production numbers and we’re hitting what we’re putting out there. And if we happen to be above those numbers because the operators have been more aggressive on either accelerating completions or drilling new wells that we don’t even have in the queue right now, so be it.

So conservative numbers. We don’t think it’s overly conservative, but we think it’s a conservative number. And we feel good about the ability to maintain or grow production volumes on our asset even without making any acquisitions. Matt, Bob, anything?

Matt Daly: No, I mean, I think that’s right. I think it’s interesting that this is the highest spread we’ve ever had between line-of-sight wells and our maintenance wells of 4.5 net wells per year. So everything you say was correct, Davis. I mean it’s a — we do, do conservative guidance. In 2022, the midpoint was 14,400 BOE per day, and we exited at 17,176. So that’s beating my point a bit. But yes, it’s very conservative, we think.

Tim Rezvan: That makes sense. Gas at $2 should drive one to be conservative, so I appreciate that. And then just one, that 12 — I guess, 12.4% is the PDP decline you’ve highlighted, which I do believe is — stands out among the public minerals companies. Obviously Hatch, with the activity this year, will be much higher. I mean, should we just — we can do weighted average production. I mean should we think about that decline rate kind of going to like a mid-teens as you look out a year?

Davis Ravnaas: Yes. So I’ll take a stab at this, and I think you’ll love this color, and I’ll turn it over to, obviously, Bob is the was the fore engineer, arguably the best in the country in this field, to provide more color, it’s interesting. So it really doesn’t affect the much as one might expect. And I was a little bit curious looking at the numbers yourself initially. So Hatch has a lot of — it has an existing PDP base, which has been accretive to our distributable cash flow. But because it’s not an overwhelming component of our overall production mix, it really doesn’t drag down that — it’s not such flush production that it drags — with such a high decline rate, then it drags down the overall company decline in a really meaningful way.

So there’s that. So it doesn’t really affect the initial PDP decline rate in a material way. If we were at 12.5% before and now it’s — we were like 11.9% before, now it’s 12.4%, it still hasn’t moved at more than 50, 60 basis points. So not enough to create a rounding difference on that initial decline rate. So then the next question is, well, what happens with all these wonderful development catalysts materialize on Hatch and all these DUCs? And so that, you would assume, because it’s flush production coming online at a higher decline rate, you’d assume that would have an impact on increasing our decline rate. But you have to keep in mind that the rest of our portfolio, a lot of which is more mature in nature, the decline rate there has flattened out.

And so it’s kind of offset that increased decline in Hatch assets with a lower decline on the more mature existing legacy KRP assets. And so the net effect, in our view, is actually not material enough to really make much of a difference. Then I’ll turn it over to Bob for any additional color. I articulated that in a way that makes sense. Go ahead, Bob.

Bob Ravnaas: No, really nothing I can add to that. I agree with everything Davis just said.

Tim Rezvan: Okay. That makes a lot of sense. Thanks for your time everybody.

Bob Ravnaas: Yes, thank you.

Davis Ravnaas: Yes, thank you.

Operator: And the next question comes from the line of Trafford Lamar with Raymond James. Please proceed with your question.

Trafford Lamar: Hi, guys. Thanks for taking my question. To kind of follow up on that last comment about the base decline rate. Obviously, the flush production from Hatch has offset the legacy decline of Kimbell’s majority assets. I noticed that the net DUC and permit in total kind of reverted back to the number prior to 3Q at 4.5. Is that simply due to the influx of DUCs via Hatch and just the higher decline rate of those initial wells?

Davis Ravnaas: Bob, how would you answer that question?

Bob Ravnaas: Yes, I think that’s a good analysis. I think — yes. In looking at it, we thought that possibly it would go down because of Davis’ comment about our production maturing and taking less net wells to maintain production being flat. But that didn’t go down, I would say, as a primary driver of what you alluded to is the new wells that are coming out all the DUCs that are coming on in Hatch.

Matt Daly: Yes. And I would say that without Hatch, it would probably be closer to 4.1, 4.2 net wells, I’d say flat. So Hatch probably added 0.3 to that.

Trafford Lamar: Okay. And then last question, kind of circling back to kind of M&A, M&A landscape. Obviously, Hatch was higher unconventional versus your — the rest of your asset base. Does that kind of affect your mindset going forward with regards to potential acquisitions? Or is it still — I know you all mentioned it’s accretive. That’s priority number one. So I guess — are you all looking more to lower decline assets moving forward or in the near term? Or is it simply agnostic accretive?

Davis Ravnaas: Agnostic-accretive. It’s been our experience that when you try to get too selective on hey, we’re going to go out and buy a low-decline, Central Basin Platform asset, that has to be our next deal. If you get that mindset, it just becomes very difficult to transact on anything and you end up missing out on nice opportunities that aren’t necessarily in your — in what you’re immediately targeting. I would extend that to hydrocarbon streams. So we have folks that come into our office all the time and say, oh, you just got a liquids-focused asset with Hatch. Should you guys go out and buy a gassier asset now and to balance it out? And the answer is no. I mean, we’re going to look at everything. And I think that’s a big advantage that we have.

We’re not pigeonholed into one basin. We’re not pigeonholed to gas versus oil. We are — we look at the entire landscape. We try to look at as many opportunities as we possibly can. And we’re not in the business of predicting which commodity is going to outperform. So we take the view of we’re going to look at as much as we can, and we’re going to underwrite deals in such a way that they’re accretive to us and we have a conservative price put into it. And we’ll buy whatever opportunities give us the highest and best return on capital amongst that larger landscape. This business is hard enough and competitive enough as it is. I can’t even imagine having to only buy oil-based assets in the Permian Basin only, or only being able to buy oil and gas assets in the Haynesville only.

I just think that’s a much harder business to run. It would — you’d lose out on opportunities if you didn’t have a more geographically diverse footprint. That being said, I will say this, we would absolutely love, love, love to be able to go out and buy a single-digit decline to pick on the one place, but Central Basin platform asset that just had a long life reserve base. I mean that’s how Kimbell started. That’s how we made our money historically, is buying these very predictable, very conservative oil-based assets that all sorts of nice things end up happening in terms of enhanced oil recovery and workovers and re-completions and all that on these assets that people think are melting ice cubes but ultimately aren’t. So we would love to do that.

It’s just hard to find those opportunities. I mean the people that own those assets don’t want to carve out overrides. The people that own those minerals have typically at least the larger positions, have owned them for generations. And so again, they’re not — they’re just as acute as we are in terms of how predictable and wonderful that cash flow is. So they are harder deals to get. But no, nothing would make us happier than to underwrite a $100 million to $300 million conventional oil asset on the platform and some world-class units. That’s how we got started.

Trafford Lamar: Right, awesome. Well, appreciate the color guys. Thanks again.

Davis Ravnaas: Thank you.

Operator: Thank you. At this time, there are no further questions. Now I would like to turn the floor back over to the Kimbell Royalty management team for closing remarks.

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

Operator: Ladies and gentlemen, thank you for your participation. This does conclude today’s teleconference. You may disconnect your lines at this time, and have a wonderful day.