Greetings, and welcome to the Kimb ell Royalty Partners Q4 earnings conference call. At this time, all participants are in a listen-only mode. A brief 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, good morning, everyone. Welcome to the Kimbell Royalty Partners conference call to review financial and operational results for the Q4 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. 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 harbors provision for the Private Securities Litigation Reform Act of nineteen ninety-five. 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 a 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? 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 strengthen our financial flexibility by increasing our borrowing capacity and maintain a conservative balance sheet with net debt to trailing twelve-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 Q4 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'd in 2017, production was 3,116 Boe per day. This massive growth in production represents a five and a half times increase, largely a result of our continued consolidation in the mineral space. Today, we also declared a cash distribution of $0.48 per common unit. 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 Q4, 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 today. 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. We are very pleased to report that the results of the review confirmed an estimated 19 years of drilling inventory, a superior 5-year annual average PDP decline rate of 12%, and only 4.5 net wells needed per year to maintain flat production. We continue to believe that Kimbell has the shallowest 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 receive 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. 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 advisors 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. Thanks, Bob. Good morning, everyone. We are very pleased to report record performance during both the year and the Q4. In addition, today we are providing our full year 2023 guidance. I'll start by reviewing our financial results from the Q4, beginning with oil, natural gas, and NGL revenues of $64.4 million, a decrease of 13% from the Q3, primarily due to a decline in realized commodity prices. Kimbell's Q4 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 per BOE combined was $43.65. Our record Q4 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 Q4 run rate daily production includes only 17 days of production from the company's $270.7 million acquisition of mineral and royalty interests held formerly 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 31st, 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 Q4 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 Q4. This represents a cash distribution payment to common unitholders of 75% of cash available for distribution. The remaining 25% will be used to pay down 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 31st, Kimbell had approximately $233 million in debt outstanding under its secured revolving credit facility. It also had a net debt to Q4 2022 trailing twelve 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 in the last 5 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 Q4 2022 run rate daily production, including a full quarter of the acquired production from Hatch. We believe that most operators will focus their 2023 budgets 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 that 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 begin the year having grown our borrowing base and elected commitment on our revolving credit facility to $350 million with enhanced liquidity at a conservative capital structure. In 2022, we paid out $1.88 in the 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. Thank you. We will now be conducting a question-and-answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary that you pick up your handset before pressing the star keys. We ask that you please limit yourself to one question and one follow-up. Thank you. Our first question comes from the line of John Annis with Stifel. Please proceed with your question. Hi. Good morning, all, and congrats on a strong quarter. Yeah, thank you. For my first question, I wanted to ask about your views on an optimal leverage ratio. As you continue to pay down 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? Yeah, 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. You know, what does the company do with its cash flow? 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. You know, 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. We're at a,, a nice milestone currently, which is less than one times debt to EBITDA. I think we will continue to drive that down lower over time. You know, 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 interest rates have risen so rapidly. You know, the return you get from paying down your revolver is better today than it obviously was really at any point since we've gone public. Locking in a guaranteed,, all-in 8% cost of capital by paying down a revolver is not a bad way to allocate capital and allocate that cash flow. Long way to answer 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. We'll obviously weigh the relative benefits of buying a,, an external asset and relative to buying our own assets or stock, which we know better. That anyone does, of course, and we'll make a judgment call into what we think would generate better returns at that point. For now, continuing to pay down debt, I think is what we as management and the board believe is the best and highest use of our capital at this moment. That makes sense. Then for my follow-up, understanding that ink is still wet on the Hatch deal, I wanted to ask for your thoughts on Kimbell's role in consolidation in the minerals space. You highlighted being one of the few companies that can execute on large multi-basin acquisitions. In your view, which basin screen most attractive, and are you starting to see seller expectations come in with the pullback in the commodity? Yeah. Great, 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 of underwriting expectations, so it's always nice to see when the deal's off to a good start. We're proving to be very conservative in how we're forecasting DUC completions. Looking at the environment today, this could be,, from the folks that we speak to and the relationships we have on the banking side, excuse me, this could be a little bit of a tougher year from an M&A 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. I think we look at this environment and say, we're,, 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. 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. We continue to believe that that strategy of being patient and being conservative has worked out for us for,, 25 years of doing this. I think we'll just continue down that path going forward. What was the second part of your question, John? Forgive me. Related to which basins are screening most attractive. Yeah. 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, continues to be the best mineral footprint in the Haynesville. Again,, we got priced out of the Delaware for, what was it? 3 or 4 years, Bob and Matt, then finally were able to pull off Hatch in the Q4, 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. In this environment, I'd say Permian's still competitive, really tough to buy gas assets. I don't think people really want to sell when the,, the strip is down so much, and especially spot being,, pushing that $2 barrier, I think it's going to be tough. 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 MidCon, maybe even the Bakken,, a little bit tougher to buy there with inventory concerns. I'd say those basins, maybe the MidCon first, frankly, I think in terms of value opportunities there, but certainly also the Eagle Ford. 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? Yeah, 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. You know, 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. 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. If we can get a more accretive acquisition and pass all of our screening criteria in other basins, we'll do that. By screening criteria is that,, obviously, when 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 it 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. Then it has to have a significant room for development. 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. If we can buy something that's extremely more accretive in, 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. Great color. Thanks for taking my questions. Thanks, John. The next question comes from the line of Tim Rezvan with KeyBanc Capital Markets. Please proceed with your question. Morning, everybody, thank you for taking my 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. I'd wonder if you could step back a bit and talk about what you're seeing across the rest of your portfolio. Are you starting to see DUCs getting,, rebuilt a little bit? Are you seeing activity slow down? Just trying to understand how you landed on that guidance for the year. Yeah, no, it's a great question. First and foremost, I'll say that 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. If you look back over time, we've generally been in line, if not above, the midpoint of our guidance range on just about every factor going back since we started providing guidance a few years ago. 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 6 currently, has never been higher. 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, we're in an uncertain environment. Our company is still majority gas by revenue and production on a 6:1 basis. 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. Our hope is that,, 3 months, 6 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. If we happen to be above those numbers because 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. Conservative numbers, we don't think it's overly conservative, but we think it's a conservative number. We feel good about the ability to maintain or grow production volumes on our asset even without making any acquisitions. Matt, Bob, anything? No, I mean, I think that's right. I 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. Everything you say was correct, Davis. I mean, it's a. We do conservative guidance, and in 2022, the midpoint was 14,400 BOE per day, and we exited at 17,176. You know, that's beating by quite a bit. Yeah, it's very conservative, we think. That makes sense. Gas at $2,, should drive one to be conservative. I appreciate that. 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 going to, like, a mid-teens,, as you look out a year? Yeah. 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 reservoir engineering, arguably the best in the country in this field to provide more color. It's interesting. It really doesn't affect the decline rate as much as you might expect. I was a little bit curious at looking at the numbers itself initially. Hatch has an existing PDP base, which has been accretive to our distributable cash flow. Because it's not,, an overwhelming component of our overall production mix, it really doesn't drag down it's not such flush production with such a high decline rate, that it drags down the overall company decline in a really meaningful way. There's that. It doesn't really affect the initial PDP decline rate in a material way. If we were at,, 12.5% before, if we were, like, 11.9% before, now it's 12.4%, it still hasn't moved it more than,, 50, 60 basis points. Not enough to create a rounding difference on that initial decline rate. The next question is, well, what happens when all these wonderful development catalysts materialize on Hatch and all these DUCs? That,, you would assume, because it's flush production coming online at a higher decline rate, you would assume that would have an impact on increasing our decline rate. 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 is flattened out. It's offset that increased decline on the Hatch assets with a lower decline on the more mature, existing legacy KRP assets. The net effect, in our view, is actually not material enough to really make much of a difference. I'll turn it over to Bob for any additional color. I articulated that in a way that makes sense. Go ahead, Bob. No, really nothing of, nothing I can add to that. I agree with everything Davis just said. Okay. That makes a lot of sense. Thanks for your time, everybody. Yeah. Thank you. Yeah. Thank you. The next question comes from the line of Trafford Lamar from Raymond James. Please proceed with your question. Hey, guys. Thank you for taking my question. To 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 total 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? Bob, how would you answer that question? I think. Yeah, I think that's a good analysis. I think I. Yes. In looking at it, we thought that possibly it would go down because of Davis's comment about our production maturing and taking less net wells to maintain production being flat. That didn't go down, I would say, as a primary driver. What you alluded to is the new wells that are coming on, all the DUCs that are coming on Hatch. Yeah. I would say that without Hatch, it would probably be closer to 4.1, 4.2 net wells would stay flat. Hatch probably added 0.3 to that. You know, I don't... Okay, perfect. Okay. You know, last question, circling back M&A, M&A landscape. Obviously, Hatch was in a higher unconventional versus the rest of your asset base. Does that affect your mindset going forward with regards to potential acquisitions? Or is it still... I know y'all mentioned,, if it's accretive,, that's priority number 1. I guess,, are y'all looking more to lower decline assets moving forward or in the near term? Or is it simply agnostic accretive? 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 what you're immediately targeting. I would extend that to hydrocarbon streams. We have folks that come into our office all the time and say, "Oh, you just bought a liquids-focused asset with Hatch. Should you guys go out and buy a gassier asset now to balance it out?" 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, we're not pigeonholed into one basin. We're not pigeonholed to gas versus oil. We look at the entire landscape. We try to look at as many opportunities as we possibly can. We're not in the business of predicting which commodity is going to outperform. We take the view of we're going to look at as much as we can. We're going to underwrite deals in such a way that they're accretive to us. We have a conservative price put into it. 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,, gas assets in the Amesville only. I just think that's a much harder business to run and 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 to be able to go out and buy a,, single-digit decline,, to pick on the one place, but,, like Central Basin Platform asset that just had a long life reserve base. I mean, that's how Kimbell got started. That's how we have made our money historically, is buying these very, 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 recompletions and all that on these assets that people think are melting ice cubes, but ultimately aren't. 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 off overrides. The people that own those minerals have typically, the at least the larger positions, have owned them for generations. They're not,, they're just as astute as we are in terms of how predictable and wonderful that cash flow is. They're harder deals to get. No, nothing would make us happier than to underwrite a,, a $100 million-$300 million,, conventional oil asset on the, on the platform in some,, world-class unit. That, that's how we got started. Right. Awesome. Well, appreciate the color, guys. Thanks again. Thank you. Yeah. Thank you. Thank you. At this time, there are no further questions. I would like to turn the floor back over to the Kimbell Royalty management team for closing remarks. We thank you all for joining us this morning and look forward to speaking with you again when we report Q1 results. This completes today's call. Thank you. Ladies and gentlemen, thank you for your participation. This does conclude today's teleconference. You may disconnect your lines at this time.