KRP - NYSE

Greetings, and welcome to the Kimbell Royalty Partners First Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. 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.

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 of 2025, which ended on 03/31/2025. This call is also being webcast and should 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, which is May 8, 2025. So please be advised that any time-sensitive information may no longer be accurate at 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 considered forward-looking statements made pursuant to the safe harbor provisions 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 disclosures on forward-looking statements. These factors, as well as 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 of these forward-looking statements. And with that, I will now 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 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 start the year by reporting a record first quarter, which achieved several milestones across key metrics, including record oil, natural gas, and NGL revenues, record consolidated adjusted EBITDA, and record cash available for distribution. Other 2025 milestones so far also include completing a highly attractive and accretive acquisition in the core of the Permian Basin on 01/17/2025, increasing the company's borrowing base and elected commitments on our credit facility from $550 million to $625 million on 05/01/2025, and redeeming 50% of the Series A cumulative convertible preferred units on 05/07/2025, further simplifying our capital structure and reducing our cost of capital. Even with the uncertainty occurring across the broader geopolitical landscape, activity on our acreage remains robust with 90 rigs actively drilling on our acreage at quarter-end, representing 16% market share of all rigs drilling in the Lower 48, which is unchanged from Q4 2024. Permitting also remained strong. In fact, one notable example this quarter was from one of our oldest properties that we acquired in 02/2006 from an East Coast College endowment. This royalty asset, which we have owned for nearly twenty years and has generated profits that are multiple times its original investment, recently permitted 17 additional wells in Martin County, Texas, with NRIs above 2%. This shows not only the strength of our diversified portfolio of assets but also the benefit of the perpetual nature of minerals that can often provide surprising upside decades beyond the original investment at no cost to us. Line of sight wells continue to be above the number of wells needed to maintain flat production, giving us confidence in the resilience of our production for 2025. Our superior five-year annual average PDP decline rate of 14%, including the acquired production, requires only an estimated 6.5 net wells annually to maintain flat production. Today, we are pleased to declare our first quarter distribution of 47¢ per common unit, an increase of 17.5% from the fourth quarter of 2024 and reflecting an approximate 16% annualized tax advantage yield. We estimate that approximately 70% of this distribution is expected to be considered return of capital and not subject to dividend taxes, further enhancing the after-tax return to our common unitholders. Turning to the remainder of the year, despite the current volatility and uncertainty in the broader economy and its impact on commodity prices, we remain confident in achieving our goals for 2025. As a pure-play mineral company with ownership of a diversified portfolio of high-margin, shallow decline assets, with zero capital requirements needed to support resilient free cash flow, we remain bullish about the US oil and natural gas role of the industry, and our role as a leading consolidator in the sector. We are encouraged by the opportunities we see in 2025 and beyond to continue to grow and expand our industry-leading portfolio of assets to generate long-term unitholder value. I'll now turn the call over to Davis.

Thanks, Bob, and good morning, everyone. As Bob mentioned, this is another strong quarter for Kimbell. We generated several new quarterly records for oil, natural gas, and NGL revenues, consolidated adjusted EBITDA, and cash available for distribution. We also increased our borrowing base elected commitment and redeemed 50% of the Series A convertible preferred units, which I'll discuss in more detail in a moment. I'll now start by reviewing our financial results for the first quarter. Oil, natural gas, and NGL revenues totaled $90 million during the quarter, which includes seventy-four days of contribution from the acquired production and is a new record for Kimbell. Including a full Q1 2025 impact of acquired production, first-quarter run rate production was 25,841 BOE per day. In addition, we exited the quarter with 90 rigs actively drilling on our acreage, which represents approximately 16% market share of all land rigs drilling in the Continental United States and is flat from Q4 2024. On the expense side, first-quarter general and administrative expenses were $9.6 million, $5.8 million of which was cash G&A expense, or $2.52 per BOE. Total first-quarter consolidated adjusted EBITDA was $75.5 million, which includes seventy-four days of contribution from the acquired production and is also a new record for Kimbell. You will find a reconciliation of those consolidated adjusted EBITDA and cash available for distribution at the end of our news release. As Bob mentioned, today, we announced a cash distribution of $0.47 per common unit for the first quarter. We estimate that approximately 70% of this distribution is expected to be considered return of capital and not subject to dividend taxes, further enhancing the after-tax return to our common unitholders. This represents a cash distribution payment to common unitholders that equates to 75% of cash available for distribution, and the remaining 25% will be used to pay down a portion of the outstanding borrowings under Kimbell's secured revolving credit facility. Moving now to our balance sheet and liquidity. At 03/31/2025, we had approximately $299 million in debt outstanding under our secured revolving credit facility, which represented a net debt to trailing twelve-month consolidated adjusted EBITDA of approximately 0.9 times. We also had approximately $251 million in undrawn capacity under the secured revolving credit facility as of 03/31/2025. Subsequent to quarter-end, on 05/01/2025, the borrowing base and aggregate commitments on our secured revolving credit facility were increased from $550 million to $625 million in connection with our spring redetermination. In addition, on 05/07/2025, we redeemed 50% of the Series A cumulative convertible preferred units outstanding. This further simplifies our capital structure and reduces our cost of capital. After giving effect to this redemption, along with the expected pay down from the remaining 25% of Q1 2025 projected cash available for distribution, Kimbell expects to have approximately $462.1 million in debt outstanding under a secured credit facility and have net debt to first-quarter 2025 trailing twelve-month consolidated adjusted EBITDA of approximately 1.5 times. We continue to maintain a conservative balance sheet and remain very comfortable with our strong financial position, the support of our expanding bank syndicate, and our financial flexibility. Today, we are also affirming our financial and guidance ranges for 2025. As a reminder, our full 2025 guidance outlook was included in the Q4 2024 earnings release. We remain confident about the prospects for continued robust development as we progress through 2025 given the number of rigs actively drilling on our acreage, especially in the Permian, as well line of sight wells materially exceeding our maintenance well count. Lastly, as evidenced by our track record of ongoing acquisition activity, we expect to continue our role as a major consolidator in the highly fragmented US oil and natural gas royalty sector, which we estimate to be over $700 billion in size. And as we have stated in the past, there are only a handful of public entities in The United States and Canada that have the financial resources, infrastructure, network, and technical expertise to complete large-scale multi-basin acquisitions. We continue to believe that the overall demand for energy, our well-established and diversified asset portfolio, and the attractive opportunities to further expand and add scale within our basins will continue to enhance value for our unitholders in the years to come. With that, operator, we are now ready for questions.

Thank you, sir. We will now be conducting a question and answer session. If you would like to ask a question, please press 1 on your telephone keypad. A confirmation tone will indicate that your line is in the queue. You may press 2 to remove yourself from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the One moment, please, while we poll for any questions. And the first question comes from the line of Tim Rezvan with KeyBanc Capital Markets. Please proceed with your question.

Good morning, folks. Thank you for taking our questions.

Good morning, Tim. I want to start your last comments about continuing as a major consolidator. No surprise there. But I was wondering if you could kind of talk about your interest in M&A today. Everything we're hearing on the oil side is things are kind of on a pause right now.

You know, the mineral space, there's been a lot of new capital being deployed, especially on the gas side. So can you talk about kind of your interest today and maybe how you know, your equity currency is not really what it was a few months ago. As shares are pulled back across the industry. So kinda your interest in how maybe where your shares are trading today would factor into that. Thanks.

Yeah. Great question, Tim. Always looking at M&A opportunities just to stay right out of the gate. Your comments notwithstanding, which I totally agree with, we've had a hard time transacting on natural gas deals over the last couple of years. Seems like we've gotten blown out of the water. I don't know if people are baking in higher price decks than the future strip or what exactly is happening there. But that's been challenging on the natural gas side. I'd say that if M&A activity for us, it's a high bar, to state the obvious. We would be interested in doing deals where and we have a long history of doing this, where we could use our equity accretively to buy assets that would delever the business and just accelerate not only the scale of the company but also the deleveraging process. So if you look back historically, we've done that quite well and have been fortunate a lot of success in doing that. In the past, and I would expect us to you know, I'd be surprised if we weren't able to execute on some sort of M&A on that front. Know, let's call it over the next six to eighteen months, which I think would be to everybody's benefit. Okay. Okay. So I guess we'll stay tuned on that front. Then I appreciate the comments on leverage. It seems pretty clear that the residual free cash flow will work that balance down. Do you have a target number you're looking to or the plan just steady state, pay that down? To give you more dry powder for the next deal? How are thinking about the, you know, target debt leverage?

Yeah. Absolutely. So one advantage of the prep that we have that I think is lost on a lot of people is that for covenant purposes, it doesn't apply. Right? So the reason that we have the pref, which is more expensive than bank debt, is because we've seen this we've seen this movie several times in the past. The oil and gas industry goes through cycles. We like to and put it of paramount importance, the ability to protect common distributions. We paid a dividend all the way through COVID. Even when oil went negative, we paid a dividend. So what we're doing is just carefully managing leverage so that we can stay at that 1.5 times target for the foreseeable future. And, again, if we're able to execute like we have in the past on equity-based M&A, we would expect to be able to accelerate that payment down. So keeping leverage at one and a half times or less, we've gone considerably lower than that in the past. And then just reload the balance sheet for future M&A down the road where we have to use cash consideration to find something that's particularly attractive like LimePoint or something else. So the goal is absolutely to continue to delever. Our business is more than most purpose-built for an environment like this. We have by design, a very balanced portfolio between oil and natural gas. It's funny. I think a lot of people forgot that 50% of our production is gas-weighted, which is obviously benefited quarter over quarter. We also have diversity across every base in The United States. And then last and certainly not least, we have the lowest PDP decline rate of pretty much any company that I'm aware of. So I think the combination of all of that plus 90 rigs still actively drilling on our acreage, keys us up at least on a relative basis to outperform most companies in the upstream space. I'd also add just anecdotally, just so I thought this is interesting. We're in a unique position just given how diverse our exposure is throughout The United States. You know, we have acreage in pretty much every county, if not every county that produces hydrocarbons in The United States, and there's been a lot of talk in the last couple of weeks about drilling activity slowing down and what's happening. What's interesting is we're looking forward to Q2, don't wanna get ahead too much. But we might have the second-highest lease bonus payments we've ever had in company history in Q2. And so, you know, I don't wanna read too much into that, but we were a little bit surprised to see that lease bonus activity was picking up. Considerably at least quarter one to quarter two. And most of that's been in the Permian Basin. So it just runs a little bit counter to the narrative that things are slowing down. That isn't to say that things won't in the future. But from our perspective, we not only have we not seen a slowdown, we've actually seen kind of a dramatic improvement in leasing activities, which I think is surprising, and I hope you find interesting.

So

No. That's good. That's great color. I'd like to add to what Davis said. This is Bob. Been doing this since '98. Love this business model, obviously. And what we're with regard to organic growth and production increases on our properties, we're very diversified. We've put together a portfolio with considerable thought through all the years to maintain a really low PDP decline rate. And what we're doing is really taking a bet on how smart the engineers and geologists and landmen are and finance with that that are employed by our operators. Their job depends on increasing production and maintaining production. Their salaries depend upon it. And their bonuses depend upon it. So every day, those engineers, geologists, landmen, Midland, Houston, Dallas, Oklahoma City, Denver, are trying to figure out they're some of the best and the brightest in The US, and they're trying to figure out a way to maintain production because they maybe wanna buy a new F-150. They maybe wanna get a nice Christmas gift for their kids and wives with a nice bonus, and that's dependent upon them figuring out ways to maintain and increase production. I'll bet on that all day long. Okay. That's excellent color. I appreciate the context. If I could just sneak one last one in. Related to that comment on natural gas. I would have thought with debt up and some significant contango in the gas strip, we might see you all take advantage of that. I know you layered in some 2027 hedges, but you seem about 20% hedged going forward. Just kind of curious on your thoughts on hedging with higher debt. Yes. That's a great question. We actually talked about that at the board level yesterday.

We run stress tests internally on our production, and we look for you know, we stress oil and gas down to very low levels. We look at our ability to protect that cut you know, the ability to pay distribution to common unitholders, and we feel that 20% hedge level is a good place to be. That is something that we actively think about, though. And your point is well taken with, obviously, the natural gas strip increasing should you layer on more hedges. It's something we think about. On the other hand, we try to take judgment out of the equation when we hedge. We don't try to time oil and gas prices when we layer on hedging. We have a very methodical, formulaic approach to layering on hedges. So we do that thought is not lost on us. It's an intelligent thought. But at this time, we still like that 20% hedging level. We think that it protects us even in a very draconian pricing environment.

Okay. I'll leave it there. I appreciate all the answers.

Yeah. Thanks, Tim.

And the next question comes from the line of John Annes with Texas Capital. Please proceed with your question.

Hey, good morning, guys, and congrats on the strong quarter.

Morning, John. Thank you. John. Good morning. For my first one, you mentioned the activity dashboard for both your line of sight activity and your market share of active rigs is quite supportive of growth in 2025. With the strong volumes in the first quarter, how do you see volumes trending throughout the year? And is there anything that has left you a little more conservative just given the net well inventories are above maintenance levels? Great question. And fair. We have a history of being conservative with our guidance. We're reaffirming our guidance. And I don't think there's anything at this time that we see that would cause us to alter guidance one way or the other. I think that in an environment like this, prudence is warranted. We're just unclear what's gonna happen with drilling schedules and CapEx.

Again, based on everything I said on the preceding ten minutes, we're not seeing any evidence of a slowdown, which I think might be surprising to people. And, you know, maybe it comes in the future. But just based on near-term activity we've got from ducts and permits, the amount of rigs that are running, lease bonus activity, everything else. We feel very good about hitting our guidance numbers this year and would like to just keep them the same. So that's why we're reaffirming them.

Oh, that's terrific color. For my follow-up, just regarding your attractive tax structure, how much runway do you have where your distributions can be conveyed on a tax-friendly basis?

That is a great question, and it's a very complicated one. Obviously, we have a considerable tax shield, and we do feel that is a very unique attribute to our business. When oil and gas prices go up, more of our dividend is subject to taxes. When oil and gas prices go down, less of it is, and that's why we have that wonderful, you know, preponderance of our dividend, return of capital as opposed to ordinary income or dividend taxation. The runway on that is hard to predict. Because it depends on so many different variables, production, oil and gas prices, which we can't predict. But it is considerable. I'll put it that way. And we see no near-term end to that runway, so to speak. In the foreseeable future.

Thanks, guys.

Thank you.

And the next question comes from the line of Paul Diamond with Citibank. Please proceed with your question.

Thank you. Good morning, all, and thanks for taking the time. Yeah. Just a Morning, Bob. Quick one for morning. Just a quick one for you on the I know you can or pay down or redeem 50% of the converts. Just wanna get an understanding of how you all think about, you know, what's left long term and how that fits into the cap structure over time.

Yeah. So the game plan is to pay down debt every quarter. I think we paid down $17 million of debt this quarter. And then every two to three quarters, we'll redeem out at least 20% of the face value of that pref. That's the way that it's structured is that we can do it. 20% increments. So you'll see us continue to allocate 25% of cash flow available for distribution to debt pay down. Then we will periodically every couple quarters or so, chip away at that pref. All the while maintaining that kind of ceiling of, you know, called plus or minus, depending on oil and gas prices, a plus or minus 1.5 times EBITDA. So the goal is to just chip away at that over time. We did that The only other time we've had a prep is back when we did that Haymaker acquisition in 2018. Where we bought into our, what is the most important natural gas part of our company, which is in the Eastern Haynesville and Louisiana. And we did that quite successfully that way, and we just like the way that works. It gives us a lot of optionality to pay down the debt prudently and to manage our debt levels. Or covenant levels.

Understood. Makes perfect sense. And then just drilling down a bit more on some you had said prior where you've gotten getting blown out of the water. On the M&A side for nat gas. I guess, you is there any bifurcation in that narrative between Haynesville or Appalachia? And has it kinda shifted over time, or is it all pretty much, everyone's walking in a higher future price?

Good nuanced question. I would say it's been more competitive in the Haynesville than it has been in There's a lot of interest in these days. And p I mean, look. We like the Marcellus too. Everybody loves the Marcellus. But Just The Ability To Ramp Growth There Given Infrastructure Constraints Is Just Obvious To Everyone. So I Would Say If I Had To Handicap That, I'd Say That We Have Been More In The Money In Appalachia than we have been in the Haynesville recently. And, look, we've seen these waves before. I mean, there was a long period of time where we were just getting crushed in the Permian, for example. And then and then say, you know, as that place started to mature, things became more accretive to us, and we've been able to rattle off you know, a series of acquisitions in the Permian. And that wasn't because we were deliberately targeting the Permian. It's just because that's where we saw the opportunity set. I wouldn't be surprised to see, for example, the Western Haynesville, you know, East Texas, those prices are really high right now. And it's still a relatively undeveloped play. There's still a lot of running room there. It's more difficult for us to make things accretive on a cash flow basis. I think as that play gets delineated, as we get a better understanding of how things are developed, would expect for that to become a more competitive place for us to allocate capital. But good question. I think one other thing I'd add, everybody forgets about the MidCon. MidCon has tremendous gas volumes without any of the infrastructure constraints. The Longpoint acquisition that we did a few years ago really underscores almost the entire state of Oklahoma in terms of mineral ownership. We've seen a lot of really great natural gas revenue coming in NGLs coming out of Oklahoma too. So that's an area where there's less competition. And, frankly, just some really good repeatable well results. So I think that's one other plan to kinda put on your radar of interest on the M&A front.

Understood. Appreciate the clarity. I'll leave it there.

Of course. Thank you.

And the next question comes from the line of Noah Hungness with Bank of America. Please proceed with your question.

Morning, everyone. My first question here,

morning. I just wanted to ask Hey. Hey. Good morning, Noah.

Good morning. Good morning, Noah.

Hey, guys. I just wanted to ask on the first question here was just on NGL and natural gas realizations. You guys seem to come in a lot stronger than maybe what we were expecting and what we had seen you know, at similar times in prior years. Could you maybe talk about what drove that beat and then also kinda how to think about where NGLs as a percent of WTI and natural gas a percent of Henry Hub would kind of trend through the balance of '25? Yeah. I would use I would use this quarter's numbers as a goalpost for the rest of the year. Fourth quarter differentials, you know, they're traditionally worse for royalty companies for everybody. But for royalty companies in particular, I think one q number is gonna be more representative going forward. And I actually asked that same question, Noah, to our technical team about, you know, where are we seeing the biggest uplift and differentials, and it's really been across the board. We've seen that pretty much in every basin across our portfolio and improvement. In both NGL and natural gas differentials. So there really is the one area that I could attribute that improvement to. It's really been across the entire portfolio. Great. And then, for my second question here, you guys gave us some great color on kinda where net DUCs were at the end of the quarter, but I'm sure as you guys are well aware, a lot has happened since March 31. So could you guys give us an update on where the net ducks kinda stand today? Yeah. I think that's in our materials. We pulled that up. Give me a second. Yeah. I mean, we no. This is Matt Daly. We disclosed we had, 4.67 net DUCs at three-thirty-one, and that's the latest data we've disclosed publicly. Oh, okay. Yeah. I was just wondering if you had any color on maybe how that was trending in the first month or two. Into the quarter?

No. I mean, it's as you can imagine, it's an incredibly time-intensive endeavor to go through our tens of millions of acres, and quantify those DUCs and permits. So we do it once per quarter. Again, activity remains very solid. I wouldn't say there's a trend one way or the other. Most of the DUCs are in the Permian, but we've got a significant number, almost the remaining or spread throughout the other six major basins that we're in. So good trends there. Haven't again, just haven't seen any indication of a slowdown. Not to say that it isn't gonna happen, nationwide, but, you know, continue to feel very good about our production profile. Yeah. And I would just add. This is Matt again. I mean, the Conoco, you know,

commentary this morning indicated that production is gonna remain flat you know, in their Permian assets and overall, and then the Diamondback, you know, down one So you're we're not looking at this sort of a dramatic drop off here in terms of Permian production. And, again, half our production is natural gas. So in some ways, we're a lot more insulated from could be happening in the Permian in terms of a slight slowdown.

No. That makes a ton of sense. I appreciate the color.

Thank you.

Thank you, Noah. Noah,

thank you for your time.

This now concludes our question and answer session. I would like to turn the floor back over to management for any closing comments.

Thank you for your time, everybody, and have a great day.