Kimbell Royalty Partners, LP Q1 FY2023 Earnings Call

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. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Rick Black, Investor Relations. Thank you. You may begin.

Thank you, operator, and good morning, everyone. Welcome to Kimbell Royalty Partners conference call to review financial and operational results for the first quarter ended March 31, 2023. 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 on this call speaks only as of today, May 3rd, 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 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 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 press release. Kimbell assumes no obligation to publicly update or revise any forward-looking statements. 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 our first-quarter results that included record run rate daily production, a new record high rig count on our acreage, and a declared cash distribution of $0.35 per common unit. We're also very excited about our Midland Basin mineral and royalty acquisition that we announced last month. We expect to close this acquisition later this month. With the addition of MB Minerals to our portfolio, we continue to build on last year's momentum, and our production mix is now expected to materially shift towards oil. After giving effect to our recent M&A activity, the Permian now leads all categories in terms of production, inventory, rig count, and line of sight wells. Looking at our natural gas royalty assets, even in the face of low natural gas prices in the first quarter, the rig count on our core Haynesville acreage increased quarter-over-quarter, led by private operators. This increase in the rig count is a testament to the quality of our acreage in this area. In addition, we realized natural gas prices that were substantially higher than Henry Hub across several basins during Q1, led by the DJ Basin and Bakken, which highlights the strength of our diversified royalty model. In fact, we realized natural gas prices during Q1 that were 19% above Henry Hub. Before turning the call over to Davis to provide a more detailed review of our financials, I'd like to comment further on our Midland Basin acquisition. These assets include targeted oil and gas mineral and royalty interest on approximately 60,000 gross acres concentrated in the Northern Midland Basin, located primarily in Northern Howard County. There is a high interest contiguous footprint and three active rigs on the acreage as of March 31st. The mineral and overriding royalty ownership is on over 100 horizontal development spacing units and is 100% held by production, with over 300 total producing wells. We expect to add approximately 1,900 BOE per day with a mix of 77% oil, 12% natural gas, and 11% NGL based on our estimated run rate average daily production over the next 12 months. We believe this is an excellent and highly accretive transaction for our company and our unitholders at a very favorable multiple. This acquisition again reinforces our Permian Basin position as our leading basin in terms of production, active rig count, drilled uncompleted wells, permits, and undrilled inventory. We expect to increase our run rate average daily production to over 19,000 BOE per day, and the acquisition is expected to add 2.06 net drilled uncompleted wells and net permitted locations to Kimbell's inventory. Following the transaction, we expect our oil weighting daily production mix to increase from 29% to 34%. We also expect to maintain a peer-leading five-year PDP decline rate of approximately 13%. If we zoom out to take a broad view of the industry, we continue to expect oil production growth from US operators to remain relatively flat. We arrive at this view not only from the commentary we're hearing from US operators but also due to the fact that the number of drilled uncompleted wells in the US, which is one of the best indicators for near-term production growth, has dropped precipitously since 2020 and has not recovered. Many operators will continue to focus on replenishing their drilled uncompleted well inventories in the short term, and 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 we've seen in prior cycles. Moving forward, we will continue to drive growth through organic development and our disciplined acquisition strategy that is both consistent and proven at Kimbell. We also expect to continue benefiting from our diverse portfolio with quality production, low PDP decline rates and upside drilling locations. As a major consolidator in the highly fragmented US oil and gas royalty sector, we remain bullish about long-term consolidation in this space and our role in it. We believe that future opportunities for Kimbell are very bright and extend for many years. 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, and good morning, everyone. We are pleased to report strong performance during the first quarter. We are also affirming our full year 2023 guidance that was previously disclosed in our fourth quarter 2022 press release, and we will update our full year 2023 guidance after the closing of the MB Minerals acquisition. I'll start by reviewing our financial results from the first quarter, beginning with oil, natural gas, and NGL revenues of $57.4 million, a decrease of 10.9% from the fourth quarter, primarily due to a decline in realized commodity prices. Kimbell's first quarter 2023 average realized price per barrel of oil was $74.99, per Mcf of natural gas was $3.16, per barrel of NGLs was $25.82, and per BOE combined was $36.19. Despite coming in lower than Q4, our average realized natural gas prices for Q1 were 19% above Henry Hub due to premium prices received across several basins led by the DJ Basin and the Bakken. First quarter 2023 average daily production was 17,215 BOE per day on a 6:1 basis, which consisted of 201 BOE per day related to prior period production recognized during the quarter and 17,014 BOE per day of run-rate production. The prior period production recognized this quarter was attributable to past production that came into pay status during Q1 2023. Our record first quarter run-rate daily production of 17,014 BOE per day, an increase of 10.5% from Q4 2022, was composed of approximately 58% from natural gas and approximately 42% from liquids, or 29% from oil and 13% from NGLs. The first quarter run-rate daily production does not include any production from the MB Minerals acquisition that we announced last month. As of March 31st, 2023, not including the MB Minerals acquisition, Kimbell's major properties had 749 gross and 3.55 net drilled but uncompleted wells as well as 750 gross and 3.19 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. In addition, we exited the quarter with a record 94 rigs actively drilling on our acreage, up from 92 rigs at the end of 2022. Currently, our market share of all land rigs drilling in the continental United States represents approximately 12.8%. On the expense side, general and administrative expenses for Kimbell were $8.3 million in the quarter, $5.1 million of which was cash G&A expense or $3.34 per BOE. Unit-based compensation in the first quarter, which is a non-cash G&A expense, was $3.2 million, or $2.07 per BOE. We saw an uptick in cash G&A expenses compared to last quarter due to the payment timing of certain third-party professional fee expenses. However, those costs are expected to come down through the remainder of the year. First quarter net income was approximately $28.9 million. For the first quarter, consolidated adjusted EBITDA was $42.3 million. You will find a reconciliation of both consolidated adjusted EBITDA and cash available for distribution at the end of our news release. Today, we announced a cash distribution of $0.35 per common unit for the first quarter. This represents a cash distribution payment to common unitholders of 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. Since May 2020, excluding this upcoming Q1 payment, Kimbell has paid down approximately $99.2 million of outstanding borrowings under its secured revolving credit facility by allocating a portion of its cash available for distribution for debt paydown. And since our IPO in 2017 through today, the total cash distributed to common unitholders since we became a public company is $8.80 per common unit, approximately 49% of Kimbell's $18 per unit IPO price. Commenting further on our balance sheet and liquidity, as of March 31st, we had approximately $223.9 million in debt outstanding under our secured revolving credit facility. We continue to maintain a conservative approach with net debt to trailing 12-month consolidated adjusted EBITDA of one times. With approximately $126.1 million in undrawn capacity under our secured revolving credit facility, we are very comfortable with our strong financial position and the flexibility this provides for our continued consolidation. Before we open up the call to your questions, I would like to briefly reiterate Bob's comments about our acquisition of MB Minerals. We think this is a home-run acquisition for Kimbell at a great multiple that is highly accretive beginning in Q2 of this year. The purchase price is comprised of $48.8 million in cash, which is approximately 34% of the total consideration, approximately 5.4 million newly issued common units of Kimbell Royalty operating valued at $85.4 million at approximately 0.6 million newly issued common units of Kimbell Royalty Partners valued at $8.9 million. We appreciate the vote of confidence and support of Kimbell by the sellers that see the value of holding units in our company. With that, operator, we are now ready for questions.

Thank you. Ladies and gentlemen, at this time, we will be conducting a question-and-answer session. Our first question comes from the line of John Annis with Stifel. Please proceed with your question.

Good morning, everyone, and thanks for taking my questions. For my first one, looking at active rigs across your position, there was a six-rig increase in the Haynesville that you noted was largely driven by the privates. And as you mentioned, the rig increase during the first quarter when operators were generally decreasing activity is certainly a testament to your acreage quality. So my question is, how do you see that trend holding up against the backdrop of lower commodity and commentary from the industry regarding deferring completions and further activity reductions? Thanks.

Yes, thanks for the question, John. I think that was one of the more surprising data points that we observed from this quarter-over-quarter comparison. Frankly, we were expecting rig activity to be more muted in the Haynesville just given the obvious drop in the commodity price. Impossible for us to predict what's going to happen in terms of operator activity. We do think it's an indication that our acreage is in an area that's better than average, obviously, and perhaps even extremely above average just given the fact that the rig activity increased meaningfully. But at the same time, we wouldn't be totally opposed to our operators keeping the gas in the ground and pulling it out when commodity prices are higher. So we don't want to make any sort of estimate about what's going to happen on our acreage going forward, but it is a good sign that we appear to get more activity than the general basin overall, notwithstanding the decline in the commodity price. Bob or Matt, anything you guys want to add to that?

I would just like to point out that the current ability of operators to hedge into a contango-shaped natural gas curve is likely contributing to the increase in drilling in the Haynesville. Essentially, they can hedge natural gas at prices of $3.50 and $4.15 for 2024 and 2025, which represent a significant return in that drilling area. It's difficult to predict future trends, as Davis mentioned, but given the current contango, we don't anticipate a major slowdown in the Haynesville unless that flattens. Currently, we have 21 rigs actively drilling there, which makes up one-third of all Haynesville rigs on our acreage. It's encouraging to see this level of activity, and I believe this contango is primarily driving the drilling in the Haynesville.

Terrific. I appreciate all the color. And for my follow-up, I wanted to touch on how you see production trending over the next few quarters on a legacy company basis, that is, excluding the pending MB transaction. If we look at your line of sight inventory being well above your maintenance requirements, is it fair to say that there is potential upside to production growth above what the full-year guide implies, which is relatively flat based on the midpoint?

Yes, John. We mentioned this last quarter, and I want to emphasize it again. The number of net drilled uncompleted wells and permits on our land compared to what we need to maintain production is, in my view, at the highest level in the company's history. Therefore, we could see an increase in production that exceeds maintenance levels. However, commodity prices are certainly a challenge right now. It wouldn't be surprising if we experienced delayed completions on our properties, which would impact production in the future. Currently, we don't see any evidence of that. As a mineral company, we don't have control over the timing of these completions. Overall, we feel optimistic. It's only a matter of time before those drilled uncompleted wells are finished, and the vast majority of those permits will be developed eventually; we just can't dictate when that happens. We remain confident, but there is uncertainty regarding when that timing will occur. Bob or Matt, do you have anything to add?

No. I agree that.

No. I agree.

Makes sense. That's it from me. Thanks again for taking my questions.

Thank you, John.

Our next question comes from the line of John Freeman with Raymond James. Please proceed with your question.

Hi, guys.

Hey, John.

Hey, John. How's it going?

Good, thanks. I noticed that in the last six months, you have completed over $400 million in acquisitions, including two very appealing Permian deals. In contrast, looking back at the previous four-year average, prior to Hatch, your annual acquisitions were just over $100 million. I'm trying to understand what has changed that has led to this significantly improved environment for you to secure both the quality and size of the recent deals compared to what occurred in the past three to four years.

John, that's a great question, and I appreciate your observation. The most significant acquisition we made, which greatly transformed our company, was the Haymaker acquisition in 2018 for over $400 million. If you had asked us back then what our expectations were regarding acquisitions, we would have hoped to maintain a cadence of several hundred million dollars annually. However, a major influx of private equity capital occurred around 2017-2018, primarily focused on the Permian. This environment made sellers more inclined to accept cash instead of equity. Consequently, it became difficult for us to offer equity and stay competitive against buyers with substantial cash reserves seeking similar opportunities. Additionally, five to six years ago, most mineral positions in the Permian Basin, especially in the Delaware Basin, were quite mature, resulting in limited production. Many transactions involved significant amounts but had minimal existing production, with buyers anticipating increased output and development. This was a strategy we've never embraced, as we've been cautious about acquiring non-producing assets that could dilute our cash flow, relying on development that is beyond our control as a mineral company. We needed to be patient during a period of maturation in the basin, while many cash buyers were also on the sidelines. Fast forward to Hatch, which was an ideal asset for us. It is not only immediately accretive to our cash flow but also has room for growth opportunities. Moreover, we don't see new portfolio companies from major private equity firms emerging with large commitments to acquiring minerals. Even if they did, they wouldn't likely target more mature assets like ours. Therefore, a mix of factors has contributed to our successful M&A activity over the past six months. Our internal underwriting process has remained largely unchanged for 25 years, with only some improvements made over time. This situation is the result of various events aligning favorably for us, which we hope will continue, though we didn't anticipate the timing. We never expected to complete $400 million in deals over the last six months; it was simply a matter of being in the right place at the right time, ready to act. Bob or Matt, do you have anything to add?

I would like to mention that we feel fortunate about both acquisitions. As Davis pointed out, we are very selective, so there were no changes in our underwriting criteria. I remember our experience with Hatch; Jimmy Murchison and his team assembled an impressive collection of assets that exceeded our expectations. It met all our criteria, as our offer was immediately beneficial both for cash flow and net asset value. They also had a significant inventory in the Delaware. Upon reviewing that and the engineering runs, I believed we would be competitive. Unfortunately, many royalty companies still focus too much on dollars per acre as a backup metric. For us, as long as everything aligns with our criteria in a high-quality development area, we don't prioritize dollars per acre—though we do consider it. Additionally, Hatch had a large number of near-term drilled uncompleted wells and permits, which helped de-risk our cash flows for the first year and a half to two years. We appreciate this aspect, and we feel similarly about our most recent acquisition. We feel fortunate that both acquisitions met our criteria.

And John, I'll add on to that just one more side. We're very lucky to have different owners of mineral baskets, private equity sponsors in particular, and then also just management teams—Bob mentioned the Hatch team—and then also obviously EnCap is a sponsor with MB, these are groups that we've done business with in the past and groups that we trust and that we've had good experiences with. And so I think that just speaks to the importance of relationships in this sector, which is still in the early stages of consolidating.

All that color is great. Actually, I was going to go in a different direction, but I will stick with the M&A topic because Bob and Davis mentioned a few interesting points. On the exploration and production side, we have seen several portfolio companies sold by private equity this year. They generally had good inventory and acreage, but their base decline rates were really high compared to the acquirers. In contrast, you have completed two sizable deals with your base decline rate barely changing from 12% prior to these deals to 13% post-deal. This is impressive, but it raises a question about potential deals in the coming year or two. If there is a theoretically accretive deal that meets all the metrics you focus on, such as high inventory and being in a good area with competent operators, but it also comes with a significantly higher base decline rate that would substantially impact your overall rate, would you still consider that deal under the right circumstances, or would you pass on it?

John, that's a great question. We have been fortunate not to pursue deals that have the higher decline rates you mentioned, at least not at a significant scale so far. We are open to those opportunities. Over time, our base decline rate has been flattening, which is one reason why Hatch and MB didn't significantly affect our base decline rate. As our base decline rate continues to mature, it enables us to explore opportunities like you described without altering the underlying depletion and amortization of our PDP production profile, which is very important to us. However, it likely makes acquisitions more challenging for us to get excited about. If the base decline rate were significantly higher and increased Kimbell's base decline rate, we would need to see substantial benefits, including enhancing shareholder value through accretion, and we would require a noticeable immediate impact on cash flow per unit along with the potential for increasing those cash flows over time. Therefore, such a deal would be less desirable, but it wouldn't rule it out for us. We're actually optimistic that as the Delaware continues to mature, the production profile of those packages will improve, although many are still privately held. We believe we will become increasingly competitive in acquiring those deals we previously missed for the reasons I mentioned, and I hope that clarifies our position.

That makes sense. I appreciate it. Thanks again, guys, for the detailed answers.

Thanks, John.

Yes. Thanks, John.

Our next question comes from the line of Tim Rezvan with KeyBanc. Please proceed with your question.

Good morning, everybody. Thanks for taking my question. I had a couple of quick questions just based on prepared comments to help us from a modeling standpoint. Did you say that you expect oil to be 34% of production after the close? And should we assume that as kind of a run rate going forward, maybe starting in the third quarter?

Yes, this is Matt. Yes, that's correct. 34% oil weighting in Q2, and of course, we are going to issue guidance here shortly that will have this deal integrated that will have the revised production numbers, mix of various commodities, cash G&A, and so forth. But, yes, 34% would be something to use and that would be something going forward plus or minus a couple of percent.

And then, Tim, this is Bob. We struck the deal, so that would be a full second quarter after we close. So it won't be just after the closing date, that's the effective date. So we'll get full production beginning in the beginning of the second quarter. So that 34% would apply for the whole second quarter on.

Okay. All right. I appreciate that. And then one thing I was sort of surprised on is this impending acquisition, the pricing seems so attractive that it looks like a little more of a kind of a PDP acquisition. I know there's some near-term growth. If I heard you correctly, you said three active rigs at the end of the first quarter. Do you expect or did you underwrite kind of longer-term growth? Beyond you talked about the number of producing wells. How do you think about that asset over the next two, three years or what was embedded in your expectations?

Yes, Bob, do you want me to start out and then you can jump in here and then Matt?

Sure.

So, Tim, great question. Great question. So not as much running room on the drilling front as something like Hatch, right, which has a much longer runway from an inventory standpoint. So love that because Hatch was immediately accretive, but then we also have a lot of inventory in growth to drive future accretion. Contrast that with the MB acquisition, which has, at a much lower cash flow multiple to your point, which is correct, a lot more near-term accretion but then less growth going forward. That being said, this isn't a PDP asset that's declining. We do see a multi-year inventory on this package, but it's just not as much running room as Hatch has. And so candidly, we kind of look at it and say they are a really nice complement to one another. We didn't proactively seek out to buy MB, because it was a good complement to add. It just kind of turned out that way because it is a nice circumstance. But it adds—it kind of drives more near-term accretion to cash flow, which everybody is going to see in the second quarter, and then that will be well balanced by the longer-term inventory nature of what Hatch has. But, no, I don't want to leave you with the conclusion that we bought an asset that's peaked out on production rates—has been declining over time, and I think you pointed that out too. I mean, that's why there's a meaningful amount of drilled uncompleted well and permit inventory on the rigs that are running on the acreage. I mean, there is running room there, and you can go look at the calls, investor presentation and kind of make your own informed opinion as well. But there is growth there, just not quite as much as Hatch. But that's also why we bought it at the multiple of cash flow that we did and didn't pay as much forward on a cash flow basis as Hatch, and that makes sense.

Yes, totally. Okay. I just wanted to confirm that, and that was as expected. And then if I could sneak in a quick final one.

Sure.

You touched on the $126 million undrawn capacity, $224 million drawn. My understanding that it's kind of before the factoring in this acquisition. So could you talk about kind of when the timing-wise, when we might see a redetermination or how that liquidity could change?

Yes. As Davis said, this is a relatively heavy PDP asset, which the banks gave a lot of credit on the borrowing base increase. So we're looking at the bank meeting. It will be mid-May. Just throwing out some potential numbers here. You're probably looking at least a $50 million increase in borrowing base on this transaction, probably could be more than that. And of course, with that increase, you're looking at about $130 million of liquidity. So a lot of liquidity post this acquisition, and a pro forma leverage ratio around one times.

Okay, that's great. Thank you, everybody.

You bet.

Thank you.

Yes, thanks, Tim.

There are no further questions in the queue. I'd like to hand the call back to management for closing remarks.

Thanks, everyone. We appreciate your time today and look forward to talking to you again when we report our second quarter earnings. This completes today's call.

Ladies and gentlemen, this does conclude today's teleconference. Thank you for your participation. You may disconnect your lines at this time and have a wonderful day.