Kimbell Royalty Partners, LP (NYSE:KRP) Q4 2025 Earnings Call Transcript

Kimbell Royalty Partners, LP (NYSE:KRP) Q4 2025 Earnings Call Transcript February 26, 2026

Kimbell Royalty Partners, LP misses on earnings expectations. Reported EPS is $-0.11045 EPS, expectations were $0.14.

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

Rick Black: Thank you, operator, and welcome, everyone, to the Kimbell Royalty Partners conference call to discuss fourth quarter financial and operational results. This is for the time period ending December 31, 2025. 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 26, 2026, 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 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 press release for our disclosure 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 press release. Kimbell assumes no obligation to publicly update or revise any forward-looking statements. And 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 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. To start off, we are pleased to report strong fourth quarter results that helped cap off another outstanding year for Kimbell. We began 2025 with a $230 million acquisition of mineral and royalty interest beneath the historic Mabee Ranch in the Midland Basin, strengthening the Permian Basin as our leading area for production, activity and inventory. During the second quarter, we redeemed 50% of the Series A cumulative convertible preferred units, simplifying capital structure and lowering our cost of capital.

In the fourth quarter, we grew production organically from the third quarter and exceeded the midpoint of our guidance. The favorable fourth quarter performance allowed us to declare a Q4 2025 distribution of $0.37 per common unit, up 6% from Q3 2025 as we continue to focus on returning value to unitholders. For the year, we returned $1.60 per common unit through quarterly distributions, all classified as return of capital and 100% free of dividend income taxes while also reducing debt through disciplined balance sheet management. I’m also pleased to report that our proved developed reserves increased approximately 8% in 2025 to a record level of nearly 73 million Boe. Our active rig count remains strong with 85 rigs drilling across our acreage, representing a market share of U.S. land rigs at 16%.

In addition, our line-of-site wells continue to be above the number of wells needed to maintain flat production, giving us confidence in the resilience of our production as we progress through 2026. Now before turning the call over to Davis, I’d like to take a moment to provide some high-level comments on a topic we have received considerable investor interest about recently, which is our Barnett-Woodford potential across the Permian Basin. We own all depths across the vast majority of our massive acreage position in our portfolio, which means that we stand to benefit considerably from any development in new formations, including the Barnett-Woodford. As a mineral owner, we do not have to pay for test pilot programs or delineation projects, making this a meaningful catalyst for increased free cash flow from our unitholders for our unitholders in the future.

We have already seen development of the Barnett-Woodford on our assets from some of our major operators, and we expect this to accelerate. Finally, as we reflect on 2025, we are grateful to our employees, Board and advisers for another successful year at Kimbell as we remain focused on generating long-term unitholder value. And now I’ll turn the call over to Davis.

Davis Ravnaas: Thanks, Bob, and good morning, everyone. As Bob mentioned, 2025 was another excellent year for Kimbell. I’ll start by reviewing our financial results for the fourth quarter. Oil, natural gas and NGL revenues totaled $76 million during the fourth quarter and run rate production was 25,627 Boe per day, which exceeded the midpoint of our guidance. On the expense side, fourth quarter general and administrative expenses were $10.4 million, $6.2 million of which was cash G&A expense or $2.63 per Boe, within our guidance range. For the full year 2025, cash G&A expense was $2.51 per Boe, below the midpoint of guidance, reflecting operational discipline and positive operating leverage. Total fourth quarter consolidated adjusted EBITDA was $64.8 million.

You will find a reconciliation of both consolidated adjusted EBITDA and cash available for distribution at the end of our news release. This morning, we announced a cash distribution of $0.37 per common unit for the fourth quarter. We estimate that approximately 100% 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. As a reminder, on December 16, 2025, Kimbell amended its existing credit agreement to, among other things, reaffirm our borrowing base and elected commitments of $625 million, lower the cost of bank debt financing by a combined 35 basis points and extend the maturity to December 16, 2030.

At December 31, 2025, we had approximately $441.5 million in debt outstanding under our secured revolving credit facility, which represented a net debt to trailing 12-months consolidated adjusted EBITDA of approximately 1.5x. We also had approximately $183.5 million in undrawn capacity under the secured revolving credit facility as of December 31, 2025. 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 releasing our financial and operational guidance ranges for 2026. Our production guidance at the midpoint remains unchanged from 2025 at 25,500 Boe per day and demonstrates the ongoing development, diversity and stability of our production base.

We remain confident about the prospects for continued development in 2026, given the number of rigs actively drilling on our acreage, especially in the Permian, as well as our line-of-site wells exceeding our maintenance well count. In closing, 2025 marked a period of significant industry consolidation across our U.S. peer group. Looking ahead to 2026, we are excited about our position as a leading consolidator in the highly fragmented U.S. oil and natural gas royalty sector, which we estimate exceeds $650 billion in size. Long-term demand for U.S. energy is expected to continue to grow, and we are well positioned to benefit through our diversified portfolio of high-quality royalty assets across the leading U.S. basins. With that, operator, we are now ready for questions.

Operator: [Operator Instructions] Our first question comes from the line of Nick Armato with Texas Capital.

Q&A Session

Nicholas Armato: So for the first one, maybe regarding your 2026 guidance, while I realize you don’t provide quarterly guidance, could you perhaps speak to your expected production cadence for the year from 4Q ’25 levels?

Davis Ravnaas: I would say relatively stable. It’s difficult to predict, obviously, because we don’t control development. But I think you can assume a relatively stable development cadence over the course of 2026.

Nicholas Armato: Perfect. Makes sense. And then for my follow-up, I wanted to ask about the competitive landscape for M&A. After last year’s industry consolidation, how would you characterize the competitive landscape outside of the Permian now that there’s maybe less competition?

Davis Ravnaas: Yes, it’s a great question. I’d say that we have 2 advantages the way we see it in terms of our competitive positioning. First, we can target deals that are very meaningful to us in the $100 million to $500 million size range. And we can also focus as we have historically in every basin across the country. So we’re not just focused on one basin. So I think the combination of those 2 factors puts us in a unique position to be competitive on high-quality assets that are within that medium-sized range that can be meaningfully accretive to us, but they are also perhaps in out-of-favor basins. And a good example of that would be the LongPoint acquisition that we did a few years ago, which has been tremendously successful for us.

A large portion of that acreage was the Mid-Con. And I think a lot of folks that are focused on the Permian only weren’t interested in buying that package because of the significant Mid-Con component. The Mid-Con is an area that we are extremely bullish on. There’s a favorable dynamic now with gas and NGL price improvement. We’ve seen recent consolidation within that basin, specifically within Oklahoma. And we remain very confident that that’s going to be a basin of significant growth and will add a lot of value to our business going forward.

Operator: Our next question comes from the line of Tim Rezvan with KeyBanc Capital Markets.

Timothy Rezvan: First one, I saw your net line-of-site maintenance well assumption increased to 6.8 from 6.5. We thought that was interesting given that you’re still heavily exposed to the Permian and lateral lengths and EURs and IP rates are all going up significantly as operators push longer laterals. So I thought that net count might actually come down a bit. A [ till ] is different from what it was 7 years ago in terms of the production profile. So can you walk us through kind of what drove that change?

Davis Ravnaas: Sure. Pretty simple explanation. We determine that calculation once a year because a lot of work goes into it. And last year, in the first quarter in January, we acquired Boren, so 100% high upside unconventional horizontal properties. So when you add that into our mix, you would expect to see a very modest increase in the maintenance level.

Timothy Rezvan: Okay. So just folding that in. Okay.

Davis Ravnaas: Yes, exactly.

Timothy Rezvan: Okay. That’s helpful. And then as a follow-up, I noticed your net debt, and I think you’re allowed to use net debt now in your numbers, so we’ll look for that going forward, down $30 million in the last 6 months. I know there’s no rush or urgency on the mezzanine equity. I’m sure, all else equal, you prefer to kind of clean that up. If we continue to see kind of the steady free cash flow whittling down debt and improving liquidity, how are you thinking about maybe addressing that? Would you look maybe in the back half of the year to take some down? Or is it more like leave it as is to give you optionality if there’s M&A? Just trying to understand those dynamics.

Davis Ravnaas: No, no, no. It’s a good question. So there is a minimum threshold for the amount that we can redeem at any given time. We would probably anticipate redeeming some portion of it in the latter half of the year, but we’ll be opportunistic about when we choose to do that and weigh the balance between cash interest expense on our RBL and what we’re paying on the mezzanine.

Operator: Our next question comes from the line of Noah Hungness with Bank of America.

Noah Hungness: I wanted to start off here on realizations. Can you maybe just help us how to think about the natural gas realizations as a percent of Henry Hub, NGL realizations as a percent of WTI and differentials for crude for this year?

Davis Ravnaas: Sure. Noah, Matt, maybe I’ll turn that over to you. I know we almost always see some seasonality as we see realizations quarter-to-quarter. But Matt, maybe you can add some more detail to that.

Matthew Daly: Yes, yes. So the oil differential was flat at 2% between Q3 and Q4. natural gas was 18% in Q3, went to 24% in Q4, and then NGLs was flat quarter-over-quarter. And you’re right, David. Generally, we see for natural gas differential sort of a seasonal increase in differentials during the winter months. So Q4 and Q1, you’ll see higher differentials. And as we get into Q2 and Q3, it will likely go back down closer to 18%. Obviously, with Waha and the takeaway capacity being built out of the Permian over the next couple of years, we expect that will certainly improve the long-term differentials for natural gas as those pipelines get in place. But again, it’s more of a seasonal item. Again, Q4, Q1, a little bit higher differential for gas and drops in Q2 and Q3.

Noah Hungness: And the NGL realizations, should we just kind of assume it’s flat versus what 4Q was?

Matthew Daly: I would assume flat between Q3 and Q4.

Noah Hungness: Great. And then kind of building off of the realizations questions here. Can you guys maybe just talk about what the Waha price inflection in ’27 will mean for you guys and kind of what your exposure to that theme is?

Davis Ravnaas: I mean it should be a significant improvement for us and everyone else that’s in the Permian. But Matt, I’ll let you answer that question.

Matthew Daly: Yes. I mean over 85% of our gas production is outside Waha. So you have — you do have 15% that’s exposed to that pricing, which is obviously was very low recently. So can we quantify the impact? I mean it’s certainly going to be a catalyst, I think, for improving differentials as you get into the latter part of this year and into ’27. We haven’t quantified the improvement, but we’re looking forward to seeing those differentials sort of long term much lower as those pipelines come into place.

Davis Ravnaas: No, I think what we’re more excited — about I think what we’re more excited about in the Permian is just the continued development of different benches. So we’re seeing what seems like a rapid acceleration of delineation within the Woodford-Barnett area. So I know Bob commented a little bit on that in his opening comments, but that’s a real opportunity for us to drive production growth across our basin at no cost to us. We’re seeing just tremendous interest in developing the Woodford going forward. And I think that’s a huge tailwind for our business.

Noah Hungness: And do you guys — I guess, just responding to that, do you guys think that — is this more of a story where the activity will improve production? Or do you think you’ll receive a bit of a revenue tailwind on the lease bonus side first? And if so, like do you have a rough idea how much that might be?

Davis Ravnaas: More on the production side, good question. Almost all of our acreage is leased. So we will probably get some lease bonus impact from that. And when I think about that, it’s going to be acreage that we own in areas that could be prospective for Woodford-Barnett, maybe more on the platform side than the Midland Basin that are currently unleased. But on the leased acreage, I mean, it’s pretty easy just to go to our investor presentation and look at our Permian map. I mean, we just have tremendous exposure at all depth to that specific formation. So to the extent that, that continues to be developed, and we’ve already seen some developments. So on the Mabee Ranch, for example, Conoco has drilled a couple of wells that have been very good, and then we’re surrounded by activity from other operators like Oxy and Fasken.

So it is real. It’s something that we’ve noticed in speaking to operators, their interest level increasing dramatically on that play. And I think you’ll — I’m sure across your coverage universe, you’ve seen other Permian operators talk about their development plans pursuant to that. So it’s just a great example of why minerals are a wonderful business model. Operators that are on our properties are some of the most innovative people in America, and they’re just constantly looking for ways to improve production, whether that’s enhancing production techniques or drilling at different depths and different formations. And the good news is that as a mineral owner, we don’t have to pay for any of that experimentation or proving out the best areas in which to apply CapEx. So it’s going to be a nice windfall for us, and we believe in it.

Noah Hungness: Are those leases HBP? Or are they set to expire, which means that the operators are kind of on the time line to get those drilled?

Davis Ravnaas: Almost all of our acreage is HBP.

Operator: There are no further questions at this time. I’d like to pass the call back to management for any closing remarks.

Davis Ravnaas: Thanks to all, and have a wonderful rest of your week. Thank you.

Operator: This concludes today’s teleconference. You may disconnect your lines at this time. Thank you for your participation.