Kimbell Royalty Partners, LP (NYSE:KRP) Q3 2024 Earnings Call Transcript

Kimbell Royalty Partners, LP (NYSE:KRP) Q3 2024 Earnings Call Transcript November 7, 2024

Kimbell Royalty Partners, LP beats earnings expectations. Reported EPS is $0.22, expectations were $0.19.

Operator: Greetings, and welcome to Kimbell Royalty Partners Third 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, Mr. Black, 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 third quarter of 2024, which ended September 30, 2024. This call is also being webcast and can be accessed through the audio link on the Events & Presentations page of IR section of the kimbellrp.com. Information recorded on this call speaks only as of today, which is November 07, 2024, 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’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 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 of these forward-looking statements. 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; Matthew Daly, our Chief Operating Officer; and Blayne Rhynsburger, our Controller. We are pleased to report solid results for the quarter, which include declaring a third quarter cash distribution of $0.41 per common unit. Returning value to unitholders is always our priority, and we are proud of the record we have established. Including the declared third quarter distribution, Kimbell has returned $11.45 per unit in total cash distributed to common unitholders since our IPO in 2017.

During the third quarter, drilling activity remained strong with 90 rigs actively drilling on our acreage, which represents 16% market share of all land rigs drilling in the Lower 48. In addition, we had a record number of lease bonuses during the third quarter. This reflects increased operator interest in developing Kimbell’s acreage. Line of sight wells continue to be well above the number of wells needed to maintain flat production, giving us confidence in the resilience of our production as we wrap up 2024. More specifically, the number of net DUCs increased by 34% quarter-over-quarter to 5.1 net DUCs, the second highest level in Kimbell’s history, led by the Permian Basin. Finally, we are very optimistic about the future for Kimbell and its ability to drive unitholder value for years to come.

And now I’ll turn the call over to Davis.

Davis Ravnaas: Thanks, Bob, and good morning, everyone. In the third quarter, we once again generated strong results, maintained a substantial market share of the U.S. rig count and achieved the lease bonuses during the quarter that were the highest in our history. I’ll start by reviewing our financial results from the quarter beginning with oil, natural gas and NGL revenues which totaled $71.1 million. We had run rate production of 23,846 BOE per day and 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. On the expense side, third quarter general and administrative expenses were $9.5 million, $5.6 million of which was cash G&A expense or $2.57 per BOE.

This continues to demonstrate operational discipline and positive operating leverage. Net income in the third quarter was approximately $25.8 million and net income attributable to common units was approximately $17.4 million or $0.22 per common unit. Total third quarter consolidated adjusted EBITDA was $63.1 million. You will find a reconciliation of both 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 $0.41 per common unit for the third quarter. We estimate that approximately 100% of this distribution is expected to be considered return of capital and therefore 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 September 30, 2024, we had approximately $252.2 million in debt outstanding under our secured revolving credit facility. We continue to maintain a conservative balance sheet with net debt to trailing 12 month consolidated adjusted EBITDA of approximately 0.8x. We had approximately $297.8 million in undrawn capacity under the secured revolving credit facility as of September 30, 2024. We remain very comfortable with our strong financial position, the support of our expanding bank syndicate and our financial flexibility.

With this substantial liquidity, we are planning to redeem at least half of the Apollo Preferred Stock in May 2025. We believe this timing will optimize cost savings for the company as well as maintain conservative leverage and liquidity. Today, we are also affirming our 2024 guidance, which includes daily production at its midpoint of 24,000 BOE per day. As a reminder, our full guidance outlook was provided in the Q4 2023 earnings press release. We remain confident about the prospects for continued robust development as we progress through 2024 given the number of rigs actively drilling on our acreage, especially in the Permian. We continue to believe that our diversified portfolio of high-quality royalty assets across the leading U.S. basins will continue to drive value for our unitholders for years to come.

With that, operator, we are now ready for questions.

Q&A Session

Operator: Thank you. [Operator Instructions]. The first question comes from the line of Tim Rezvan with KeyBanc Capital Markets Inc. Please go ahead.

Tim Rezvan: Good morning, folks, and thank you for taking my question. I was expecting we hear comments on the preferred being partially redeemed this quarter. I believe you said May 2025, Davis. So I was curious if you could kind of walk through, what it seems to be a little bit of a change from what you commented on before, kind of what’s driving that. Is that an interest rate, outlook or something else mechanical?

Davis Ravnaas: Yeah. Great question. As always, good job picking up on the detail. We ran the math with greater specificity following the last conference call and we realized that it’s actually more cost efficient to redeem it in May than it is today. Just saves us a couple of million bucks when we kind of work through the mechanics of the math. So nothing’s changed. The goal is still to take it out as soon as possible. We just realized that, waiting 4 or 5 months would actually save the, the partnership a little bit of money.

Tim Rezvan: Okay. Okay. That that’s fair. So from — should we from a modeling perspective, is roughly half a good assumption to run with?

Davis Ravnaas: Yes. And what I would say, Tim, just to just to hedge that a little bit, obviously, if something crazy happens in oil and gas markets, we might want to readdress, taking it out at that time. But right now, barring some unforeseen events, that’s absolutely the game plan we talked about on the board call yesterday.

Tim Rezvan: Okay. That’s good to know. Appreciate that. And then, as my follow-up, I noticed you did have the increase in net DUCs. It seemed to come at the expense of net permits, which went down about 1.4. So, but with that said, it’s kind of been at that 8-ish level, the net DUCs and permits going forward. So, you know, just trying to understand, is that the right way to kind of think about those two together going forward as a visibility on activity? We’re just trying to trying to understand this increase a little better in the in the net DUCs.

Davis Ravnaas: Yeah. I think that’s a fair way to think about it. Obviously, a DUC is more valuable than a permit. It’s always nice to see the conversion from permits to DUCs. Things go up and down. I will say that the increase in DUCs recently has been encouraging, particularly as it pertains to Delaware Basin activity. So the big driver of that DUC increase is in Loving County. Those well results just start to pay off in Q4, so we’ll start to see the impact of those. And good point of the permitting activity. Wouldn’t be surprised to see that tick back up. It’s just hard to predict. But, very happy. I mean, we’re at a near record, if not record on the DUC activity. So continue to feel good about the production outlook over the near to medium term at this time. Okay. Thanks for the details.

Tim Rezvan: Okay. Thanks for the details.

Davis Ravnaas: Absolutely, Tim.

Operator: Thank you. Next question comes from the line of Bertrand Donnes with Truist Securities. Please go ahead.

Bertrand Donnes: Hey, good morning. Thanks for taking my questions. What basins are you guys seeing the most opportunities for M&A? And are you still looking for maybe blocky acreage? Or is there may be more value in picking up small interest across your position and doing all the consolidating yourself? And then just part of that would be with the election behind us, does that maybe mark a pickup in M&A as some of the uncertainty has been removed?

Davis Ravnaas: Yes, great question. I would say that, well, a lot of thoughts there. I’ll try to keep it brief. Obviously, our sand box is the lower 48, so we’re looking at every basin. We’re always asking ourselves what’s the most efficient way to deploy capital to maximize the risk adjusted return to our investors. So sometimes that’s the Permian Basin, sometimes it’s not. The Permian’s wonderful. Everybody knows it’s wonderful, so it can sometimes be too expensive. But I would continue to see just because of the pipeline of opportunities. I would say the Permian continues to be the most attractive, and we’re just going to continue to make conservative bids. And as you know from following us for a while now, every once in a while, we win.

Every once in a while, a competitor won’t show up, or maybe they’re full because they did a deal recently. I would say we started to see an uptick in, in a basin that we’re not we’re not particularly exposed to in a meaningful way, which is Appalachia. And just on your point about the election, one thing we talked about yesterday was the view toward increased infrastructure and LNG exports becoming a more bullish story. Maybe that Appalachian story makes a little bit more sense for us now than it did historically. It’s also a basin that’s not traditionally played by a lot of our competitors. So that could be a place where, you could see some activity from us going forward. That being said, continue to look at opportunities all across the board.

On the smaller deals, we really want to use our balance sheet to make larger, more impactful acquisitions. We’re reluctant to draw $10 million, $20 million, $30 million, $40 million, a quarter on smaller acquisitions on your revolver. It’s just really easy to see leverage creep up and then you’re not there with cash available to transact on bigger deals. And it takes us the same amount of time to analyze the larger transaction as it does a smaller one. And I would also add to that, I think the competition for some of the smaller acquisitions, let’s call it less than $5 million is significantly greater than acquisitions over $50 million. So at this time, we don’t really see the benefit of increased consolidation efforts on the micro level, both from a balance sheet perspective, but also from competitive dynamics.

Bertrand Donnes: That’s really great detail. And then just the follow-up is your quarterly lease bonus is obviously impressive, but you guys noted in there that maybe there’s increased operator interest. Is that what you’re attributing to? Is it maybe those operators have run through some of their Tier one acreage already? And should we go back down to normalized levels? Or is this maybe a trend that goes forward?

Davis Ravnaas: The big driver of this quarter’s leasing activity was in the Mid Continent. Part of that, the new Cherokee shale play, which we hope is successful because we have such a robust footprint up there. So hopefully that continues to pay off. A good thought on the Tier two acreage. Yes, I think that will continue to be more meaningful if I had to give you an answer over time. I think that you’ll start to see folks expanding their exploratory efforts beyond what has already lineated and known. So I think that’s a good thought. It will be interesting to see if that continues to pick up in subsequent quarters. We’ll obviously keep you guys posted.

Bertrand Donnes: That makes sense. Thanks.

Operator: Thank you. Next question comes from the line of Noah Hungness with Bank of America. Please go ahead.

Noah Hungness: Morning, guys. Just one question for me. I wanted to ask just a clarification question on the high NRI wells in Loving County. So should we expect that to come online in 4Q and then really start to see the impact at the start of 2025?

Davis Ravnaas: Sure. Matt, correct me if I’m wrong here. Those wells are actually already producing. We just expect to start receiving production and cash flow in Q4. And I’ll just add that so far the results are very encouraging. Unsurprisingly, it’s one of, if not the best, most productive counties in the United States, very encouraging initial results from that, and we’re very happy to see the production.

Noah Hungness: Awesome. Thanks.

Operator: Thank you. Thank you. Ladies and gentlemen, we have reached the end of question-and-answer session. I would now like to turn the floor over to the management for closing comments.

Rick Black: We thank you all for joining us this morning, and we look forward to speaking with you again next quarter. This completes today’s call.

Operator: This concludes today’s teleconference. [Operator Closing Remarks]