Greetings and welcome to the Kimbell Royalty Partners first quarter earnings conference call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. 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 March 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, which is May 8, 2025. 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 are not historical facts, including statements of expectations or future events or future financial performance. Those 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 the 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. 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 January 17, 2025, increasing the company's borrowing base and elected commitments on our credit facility from $550 million to $625 million on May 1, 2025, and redeeming 50% of the Series A cumulative convertible preferred units on May 7, 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 remains strong. In fact, one notable example this quarter was from one of our oldest properties that we acquired in 2006 from an East Coast College endowment. This royalty asset, which we have owned for nearly 20 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 5-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 $0.47 per common unit, an increase of 17.5% from the fourth quarter of 2024, and reflecting an approximate 16% annualized tax-advantaged 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 unit holders. 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 U.S. oil and natural gas royalty 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 unit holder value. I'll now turn the call over to Davis. Thanks, Bob, and good morning, everyone. As Bob mentioned, this was 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 and 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 74 days of contribution from the acquired production, and is a new record for Kimbell. Including a full Q1 2025 impact of the 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 74 days of contribution from the acquired production and is also a new record for Kimbell. 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 $0.47 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 unit holders. This represents a cash distribution payment to common unit holders 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 March 31, 2025, we had approximately $299 million in debt outstanding under our secured revolving credit facility, which represented a net debt to trailing 12-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 March 31, 2025. Subsequent to quarter-end on May 1, 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 May 7, 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 paydown from the remaining 25% of Q1 2025 projected cash available for distribution, Kimbell expects to have approximately $462.1 million in debt outstanding under its secured credit facility and have net debt to first quarter 2025 trailing 12-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 operational 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 as our 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 U.S. oil and natural gas royalty sector, which we estimate to be over $700 billion in size. 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 multibasin 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 unit holders 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 Star 1 on your telephone keypad. A confirmation tone will indicate that your line is in the queue. You may press Star 2 to remove yourself from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the Star keys. One moment, please, while we poll for any questions. 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 wanted to start your last comments about continuing as a major consolidator. No surprise there. 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 that things are kind of on a pause right now. The mineral space, there's been a lot of new capital being deployed, especially on the gas side. Can you talk about kind of your interest today and maybe how your equity currency is not really what it was a few months ago as shares have pulled back across the industry? Kind of your interest and 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 say 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. It just 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. If you look back historically, we've done that quite well and have been fortunate to have a lot of success in doing that in the past. I would expect us to—I would be surprised if we were not able to execute on some sort of M&A on that front, let's call it over the next 6-18 months, which I think would be to everybody's benefit. Okay. Okay. I guess we'll stay tuned on that front. I appreciate the comments on leverage. It seems pretty clear that the residual free cash flow will work that debt balance down. Do you have a target number you're looking to, or is the plan just steady state pay that down to give you more dry powder for the next deal? How do you think about that target and leverage? Yeah. Absolutely. One advantage of the prep that we have that I think is lost on a lot of people is that for covenant purposes, it does not apply, right? The reason that we have the prep, which is more expensive than bank debt, is because we have seen this—we have 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. What we are doing is just carefully managing leverage so that we can stay at that 1.5 times target for the foreseeable future. Again, if we are 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. Keeping leverage at one and a half times or less, we've gone considerably lower than that in the past. 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 Longpoint or something else. The goal is absolutely to continue to deliver. 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 has obviously benefited quarter over quarter. We also have diversity across every basin in the United States. Last and certainly not least, we have the lowest PDP decline rate of pretty much any company that I'm aware of. 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 because I thought this was interesting, we're in a unique position just given how diverse our exposure is throughout the United States. We have acreage in pretty much every county, if not every county that produces hydrocarbons in the United States. 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, and I don't want to get ahead too much, but we might have the second highest lease bonus payments we've ever had in company history in Q2. I do not want to 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. Most of that has been in the Permian Basin. It just runs a little bit counter to the narrative that things are slowing down. That is not to say that things will not in the future, but from our perspective, not only have we not seen a slowdown, we have actually seen kind of a dramatic improvement in leasing activities, which I think is surprising, and I hope you find interesting. Yeah. I'd like to add to what Davis said. This is Bob. Been doing this since 1998. Love this business model, obviously. 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. What we're doing is really taking a bet on how smart the engineers and geologists and landmen are and finance 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. 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 U.S. They are trying to figure out a way to maintain production because they maybe want to buy a new F-150. They maybe want to get a nice Christmas gift for their kids and wives with a nice bonus. That is dependent upon them figuring out ways to maintain and increase production. I will bet on that all day long. Okay. That is excellent, Caller. 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% hedge going forward. Just kind of curious on your thoughts on hedging with higher debt. Thank you. Yeah. 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—we stress oil and gas down to very low levels, and we look at our ability to protect the ability to pay distributions to common unit holders. We feel that that 20% hedge level is a good place to be. That is something that we actively think about, though. 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 do not try to time oil and gas prices when we layer on hedging. We have a very methodical, formulaic approach to layering on hedges. That thought is not lost on us. It's an intelligent thought. 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. The next question comes from the line of John Annis with Texas Capital. Please proceed with your question. Hey. Good morning, guys. Congrats on the strong quarter. Morning, 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? 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. 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 going to happen with drilling schedules and CapEx. Again, based on everything I said on the preceding 10 minutes, we're not seeing any evidence of a slowdown, which I think might be surprising to people. Maybe it comes in the future. Just based on near-term activity we've got from DUCs 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. That's why we're reaffirming them. That's a 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. That is why we have that wonderful preponderance of our dividend, which is 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. It is considerable, I'll put it that way. We see no near-term end to that runway, so to speak, in the foreseeable future. Thanks, guys. Thank you. 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. Good morning, Paul. Just a quick one for you on I know you can pay down or redeem 50% of the converts. I want to get an understanding of how you all think about what's left long-term and how that fits into the cap structure over time. Yeah. So the game plan is to continue to pay down debt every quarter. I think we paid down $17 million in debt this quarter. 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 in 20% increments. You'll see us continue to allocate 25% of cash flow available for distribution to debt pay down. We will periodically, every couple of quarters or so, chip away at that pref, all the while maintaining that kind of ceiling of, let's call it plus or minus, depending on oil and gas prices, but plus or minus 1.5 times EBITDA. The goal is to just chip away at that over time. 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. We did that quite successfully that way. 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, our covenant levels. Understood. Makes perfect sense. Just drilling down a bit more on something you had said prior, where you've gotten blown out of the water on the M&A side for net gas. I guess, is there any bifurcation in that narrative between Haynesville or Appalachia? Has it kind of shifted over time, or is it all pretty much like 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 Appalachia. There's a lot of interest in the Haynesville these days. And 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. 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. As that place started to mature, things became more accretive to us, and we've been able to rattle off a series of acquisitions in the Permian. That was not because we were deliberately targeting the Permian. It is just because that is where we saw the opportunity set. I would not be surprised to see, for example, the western Haynesville, East Texas, those prices are really high right now, and it is still a relatively undeveloped play. There is still a lot of running room there. It is 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, I would expect for that to become a more competitive place for us to allocate capital. Good question. I think one other thing I would 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 have seen a lot of really great natural gas revenue in NGLs coming out of Oklahoma too. That is an area where there is less competition and, frankly, just some really good repeatable well results. I think that is one other play I would kind of put on your radar of interest on the M&A front. Understood. Appreciate the clarity. I'll leave it there. Of course. Thank you. The next question comes from the line of Noah Hungness with Bank of America. Please proceed with your question. Good morning, everyone. For my first question here. Hey, Noah. Morning. I just wanted to ask on. 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 at similar times in prior years. Could you maybe talk about what drove that beat and then also kind of how to think about where NGLs as a percent of WTI and natural gas as a percent of Henry Hub would kind of trend through the balance of 2025? Yeah. I would use this quarter's numbers as a goalpost for the rest of the year. Fourth quarter differentials, they're traditionally worse for royalty companies for everybody. For royalty companies in particular, I think one key number is going to be more representative going forward. I actually asked that same question, Noah, to our technical team about where are we seeing the biggest uplift in differentials. It's really been across the board. We've seen that pretty much in every basin across our portfolio and improvements in both NGL and natural gas differentials. There really isn't one area that I could attribute that improvement to. It's really been across the entire portfolio. Great. For my second question here, you guys gave us some great color on kind of where net DUCs were at the end of the quarter. I'm sure, as you guys are well aware, a lot has happened since March 31. Could you kind of give us an update on where the net DUCs kind of stand today? Yeah. I think that's in our materials. Let me pull that up. Give me a second. Yeah. I mean, we noticed, Matt Daly, we disclosed we had 4.67 net DUCs at 331, 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 2 into the quarter. No. I mean, 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 half, are spread throughout the other 6 major basins that we're in. Good trends there. Again, just haven't seen any indication of a slowdown. Not to say that it isn't going to happen nationwide, but continue to feel very good about our production profile. Yeah. I would just add this to Matt again. I mean, the Conoco commentary this morning indicated that production is going to remain flat in their Permian assets and overall. The Diamondback down 1%. We are not looking at this sort of a dramatic drop-off here in terms of Permian production. Again, half our production is natural gas. In some ways, we are a lot more insulated from what 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. Ladies and gentlemen, that does conclude today's conference call.