Kimbell Royalty Partners, LP (KRP) Q2 2020 Earnings Report, Transcript and Summary

Greetings, and welcome to the Kimbell Royalty Partners Second Quarter 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. [Operator Instructions]. It is now my pleasure to introduce your host for today's call, Mr. Rick Black, Investor Relations. Thank you. 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 second quarter of 2020. 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, August 6, 2020, so please be advised that any time-sensitive information may no longer be accurate as of the date of any replay. 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 of future events or future financial performance, are all considered forward-looking statements made pursuant to the Safe Harbors provision of the Private Securities Litigation Reform Act of 1995. We will be making forward-looking statements [Technical Difficulty] 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 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 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 for this call. I'm joined here on the call with several members of our senior management team, including Davis Ravnaas, our President and Chief Financial Officer; Matt Daly, our Chief Operating Officer; Blayne Rhynsburger, our Controller. I'd like to begin by providing an overview of our performance in the second quarter before handing the call over to Davis to walk you through the financials in more detail. We are encouraged by the gradual recovery in both commodity prices in the U.S. economy, and are cautiously optimistic that the worst is behind us with regard to production curtailments. Despite market challenges during the second quarter, we benefited from the full integration of the Springbok assets, and increased our Q2 2020 payout ratio from 50% to 75% of cash available for distribution. Our run rate and daily production during the quarter was 14,069 barrels of oil equivalent per day, down 7% from Q1 2020 record production of 15,188 Boe per day, including a full quarter of the production attributable to the Springbok assets. Substantially, all of the decrease in production between the first quarter and the second quarter was due to curtailments that occurred during the second quarter. Having said that, many risks remain in the economy, including, but not limited to, significant recent increases in COVID-19 cases across the country, additional potential shutdowns related to COVID-19, and the related effects on U.S. employment. In addition, significant uncertainties remain in the U.S. energy sector, primarily related to the pace of new drilling and completions for the remainder of 2020. However, we believe the Kimbell business model is highly differentiated from most companies in the U.S. energy sector, given our pure royalty model, diverse asset base, mix of commodities, substantial hedges, and low PDP decline rate, which is among the best in the industry. We remain extremely optimistic about the future of our industry, and our business specifically. Lastly, I would like to state that our business builds on a broad, stable, and diverse portfolio of royalty assets across all the major basins in the Lower 48. Our mineral interests span over 13 million gross acres in 28 states and include more than 96,000 gross wells, with over 40,000 wells in the Permian Basin. Over the last 20 years, Kimbell has demonstrated organic production growth and a five-year forecasted PDP decline rate of only 13%, which is one of the lowest among our minerals peers. Our leadership team has successfully managed through a number of economic cycles over the past several decades, and I believe Kimbell is very well positioned to not only weather this storm, but also be opportunistic as the right situations present themselves in the future. These strong characteristics of our business, coupled with a proven consolidation strategy that acquires high-quality and accretive assets, have demonstrated significant growth, scale, and cash flow for our company. Our goal is to continue advancement of our long-term strategy as a preeminent consolidator of diversified and low PDP decline minerals that generate substantial free cash flow for distribution to our unit holders. And since approximately 60% of our producing assets are natural gas and a substantial portion of our production is contractually hedged for the next couple of years, we believe that our business model is well positioned for any tough challenges ahead and will participate in the eventual economic recovery. Last quarter, we closed our Springbok acquisition that was announced in January of this year. We believe Springbok is an exceptional strategic acquisition with highly complementary acreage that we expect will add significant cash flow, as well as the opportunity for continued growth. We believe that Kimbell offers a compelling investment opportunity with growth opportunities and a robust distribution yield, which we expect our distributions to be substantially tax free through 2023, and instead to be considered a return of capital to the extent of a unit holder's basis and it's common units. We remain highly focused on executing our business plan and creating long-term value for our unit holders. And with that, I'll now turn the call over to Davis.

Thanks, Bob, and good morning, everyone. Although oil prices have somewhat recovered recently, primarily due to a rebound in gasoline demand, prices will likely be volatile for the remainder of the year. Even in the face of these challenges, we strongly believe that our business model and asset portfolio will continue to set itself apart from most other companies in the U.S. energy sector. As an example, one only has to look at Q2 production for Kimbell relative to Q1. Unlike many other companies in the U.S. energy sector that are experiencing double-digit production declines due to steep decline curves and a lack of drilling, our production only dropped by about 7% quarter-over-quarter, which is largely due to curtailments. While difficult to predict the exact timing, we do expect these curtailments will largely reverse themselves in the coming quarters. In addition, we continue to maintain a very strong inventory of permits and DUCs across our acreage, as a result of the strong drilling momentum on our acreage just prior to the pandemic. We expect these locations will provide immediate enhancements to our production profile, as eventual DUC conversions occur when frack crews resume operations. Overall, this strong focus on production stability in the face of a severe economic contraction is one of the main hallmarks of our business model. Furthermore, combining this competitive advantage with our robust hedge book and significant natural gas production, which has an increasingly positive macro outlook, provides even more enhanced cash flow stability into the coming quarters, as we emerge from this volatile period. The Company's second quarter average daily run rate production was an impressive 14,069 Boe per day, with a total average daily production of 14,254 Boe per day, which consisted of 185 Boe per day relating to prior period production recognized in the quarter. The 14,069 Boe per day of run rate production for Q2 2020 was comprised of approximately 41% from liquids or 28% from oil and 13% from NGLs, and 59% from natural gas on a six to one basis. The prior period production recognized in Q2 2020 was primarily due to new wells outperforming estimates. As of June 30, Kimbell had 806 and 2.98 net drilled but uncompleted wells, as well as 611 and 2.25 net permits on its acreage. Also, as of the end of June, the Company had 29 rigs actively drilling on our acreage, which represented an 11.6% market share of all drilling rig activity in the Lower 48 at that time. For the second quarter of 2020, the Company's oil, natural gas, and natural gas liquids revenue were $16.8 million, which reflected Q2 average realized prices of $24.89 per barrel of oil, $1.44 per Mcf of natural gas, and $7.87 per barrel of natural gas liquids, for a total combined Boe price of $13.09. In Q2, we realized hedging gains of $2.9 million, and a substantial portion of projected oil and natural gas production is hedged through Q2 2022. Net loss for the second quarter was $76.8 million, and the net loss attributable to common units was $48 million or $1.39 per common unit. The net loss for Q2 reflected a $65.5 million non-cash sealing test impairment expense recorded during the quarter related to the substantial weakness in commodity prices. This non-cash sealing test impairment is not expected to impact the cash flow available for distribution generated by Kimbell or its liquidity or ability to make acquisitions in the future. Despite the severe and unprecedented Q2 pressure on commodity prices, our broad-based, high-quality asset portfolio, coupled with our efficient business model, continued to deliver results, and the Company reported consolidated adjusted EBITDA of $12.1 million. Excluding the Q2 one-time impact of a $300,000 transition services agreement related to the Springbok deal, consolidated adjusted EBITDA would have been $12.4 million. On the expense side, general and administrative expenses were #6.9 million in Q2, $4.3 million of which was cash G&A expense or $3.48 per Boe. Excluding the effect of the transition services agreement relating to the Springbok integration, cash G&A was $3.24 per Boe. Management and the Board were pleased to increase the payout ratio to 75% of the Q2 cash available for distribution, which is $0.13 per common unit. We will use the retained amount to strengthen the balance sheet by paying down debt of $2.5 million in the coming days. We continue to manage the Company in a conservative and prudent manner, especially given the risks and uncertainties in the energy sector and the broader economy so far this year. You will find a reconciliation of both consolidated adjusted EBITDA and cash available for distribution at the end of our news release. As you know, Kimbell anticipates that substantially all of the Q2 distribution will be a non-taxable reduction to the tax basis of the unitholders' investment and will not constitute a taxable dividend. The reduced tax basis will increase unitholders' capital gain or decrease unitholders' capital loss when unitholders sell their common units. Furthermore, Kimbell expects substantially all distributions paid to common unit holders for the remainder of 2020 through 2023 will not be taxable dividend income, and less than 25% of distributions paid to common unitholders for the subsequent two years, 2024 and 2025, are expected to be taxable dividend income. Looking now at the balance sheet and liquidity. At June 30, 2020, Kimbell had approximately $171.7 million in debt outstanding under its revolving credit facility. After giving effect to $477,051 in acquisitions under Kimbell's micro investment strategy so far in Q3, and the repayment of approximately $2.5 million in outstanding borrowings discussed above, which is anticipated to occur in Q3, Kimbell expects to have approximately $169.7 million in outstanding borrowings under its revolving credit facility, and approximately $55.3 million in undrawn capacity, or approximately $130 million if aggregate commitments were equal to Kimbell's current borrowing base, which is $300 million. Increases in commitments pursuant to the accordion feature of this revolving credit facility are subject to the satisfaction of certain conditions, including obtaining additional commitments from new or existing lenders. Pro forma total debt to Q2 trailing 12-month consolidated adjusted EBITDA was approximately 2.3 times. On June 1, we received unanimous reaffirmation from our lender group of our $300 million borrowing base, and the total commitments of $225 million. During the first quarter, we announced that we would begin disclosing our DUCs and permits by basin on our major properties, and we have continued this additional disclosure in our second quarter earnings release. As of June 30, 2020, we reported $2.98 net DUCs, 806 gross, and 2.25 net permits or 611 gross on Kimbell's acreage at the end of this period. This data does not include our minor properties, which we estimate could add an additional 20% to the DUC and permit inventory, based on our experience. In addition, for the 11 months of check step data, for which we have completed analysis, we estimate that, on average, 132 gross wells and 0.52 net wells were brought online each month, on average, during the recent trailing 11 months. We are grateful to our employees and advisers, as they have successfully adjusted to this new working environment. We are confident that we will continue to distinguish ourselves in the coming months, as the U.S. emerges from this pandemic. We are also very grateful to our investors in Kimbell, and we'll strive to continue to generate long-term value in the years to come. With that, operator, we are now ready for questions.

[Operator Instructions]. Our first question comes from John Freeman with Raymond James. Please proceed with your question.

Hi, guys.

Hey, John.

Hey, John.

How you doing?

Doing well, thanks. First question I had, just trying to - a little bit more detail on the curtailments or shut-ins that you all saw during the second quarter. I'm just trying to get a sense of how much of it - and I realize it's difficult to nail down, but just ballpark, if you're thinking about from a curtailment versus outright shut-ins, if you could kind of just maybe ballpark round numbers about how much you think were just curtailments versus outright shut-ins.

Bob, do you want me to start?

Sure, yes.

Blayne, I want to hear what you think about this too. It's a good question, John. I think substantially, all - and I'm going to say 6% out of the 7% would be a good conservative. It's temporary curtailments. Is that correct?

Yes.

And the largest one was EP Energy, is that correct?

Yes.

So, John, it's not - so, the good news is we expect what - we have reduced rig activity on our existing acreage position, and so does everybody. But 6% of the 7% of production drop, we believe, is attributable to temporary curtailments that should reverse themselves. And maybe I'll be ever more aggressive and say we believe most of those have already reversed themselves. Isn't that a fair statement, Blayne?

Yes.

In June, yes.

In June, yes.

So, that's a good news, John.

No, that's great. And then I want to spend a little bit time talking more about the payout ratio. You increased it from a 50% to the 75%. I know, in the past, you sort of talked about if you got leverage back down below 1.5 times, you'd probably start moving back to the 100% payout, and I'm just curious if just when you think about long term, if - and again, I completely acknowledge that you all have the lowest base decline rate of anybody, so you already have kind of a built-in additional safety net, relative to your peers. But if there might be some inclination to maybe not quite go back to the 100% payout, just as a sort of additional kind of dry powder, and also along those same lines, if potentially that 1.5 times leverage target might, over time, maybe move closer to 1 times.

Great, question, John. Thank you for asking it. There is not a perfect answer on the payout ratio, and we have agonized over it pretty much every single day over the - ever since this whole COVID fiasco started. I think that when we made the decision to go to 50%, we had a long conversation with the Board. It was the same week then oil negative $40. So at that time - I'm giving you kind of a long explanation, but at that time, we just didn't know when we didn't know. We didn't know how bad this is going to get, and I think it was just prudent and the right thing to do to reduce the payout ratio to 50% at that time. Our Board abundantly agreed with that. When we made the decision to go up to 75%, the world, it improved dramatically. We went from - we had an $80 swing in crude prices from negative $40 to positive $40. We had more transparency on the Company. You asked about curtailments. We felt confident that most of that is going to reverse itself. We were encouraged by the fact that our market share of rigs in the U.S. is actually - continues to increase, which suggests, all other things being equal, that we have more attractive assets than the average asset in the United States. But on top of that, we're not happy with where our leverage is. So, I don't see us going above 75%. Bob, weigh in here if you disagree with that. I don't think the Board is going to want us to go above 75% until we get leverage closer to that 1 times to 1.5 times. Another factor why we went from 50% to 75%, so we spent a lot of time in the last three months, as you can imagine - I think most of our peers have too - just talking to our investors. I mean we work for them. What do you guys want us to do? And we got a lot of feedback from people that they felt confident that we could increase the payout ratio and then our leverage levels would be fine. And we have a lot of very sophisticated investors that have been in royalty business for 30, 40 years, or families have been in it for multiple generations. They borrowed money against their cash flow for generations, and they understand our asset base, and the diversity, and the shallow decline profile. I would say most of the people we talk to, John, - it surprised me a little bit, but most of them felt comfortable and encouraged us to increase the payout ratio. And 75% feels like the right number. I mean, unless we have a massive - oil goes to $60 or $70 and our EBITDA screams through the roof, we may consider going above 75%. But I think for the time being, where things stand, 75% feels like the right number, and just chipping away at our debt, in a small way, every quarter over time. And in the aggregate, it ends up actually being a lot of debt, particularly if you believe in strip prices on gas, if we stay at that 75% ratio over the next year or two. So, anyway -

That's great. I appreciate all of the comments, guys. Thanks a lot.

Thanks, John.

Thank, John. I hope you and your family are doing well.

Our next question comes from TJ Schultz with RBC Capital Markets. Please proceed with your question.

Hey, guys. Good morning. On the micro investment deal in July, is that just normal course? And I know it's small dollars, but is there anything more to read into that on how sellers may be more willing recently? And then just more broadly on M&A, what's your view on the potential to do more deals this year? And how would potentially financing some of those larger deals look, just given where the stock is right now? Thanks.

Great question. So, nothing is - so, we have very strict underwriting standards on the micro strategy. We're targeting kind of risked PV, let's call it 20 plus. So, it's really hard to get those deals done. But it's a really big market. So, in July, we had a small amount of activity, but really good deals. I mean, it's just hard to transact. So, we're talking about PV 20s risked at $40 oil environment. So, we feel pretty good about those. I think what we've seen is a little bit - I think this is fair. Everybody else jump in here, if you have anything to add. I think it's fair to say that it's always more difficult to get deals done when the bid ask spread is just so severe. I mean, the volatility in oil prices kills deals. I mean, it just makes it really hard to get things done. That being said, the opportunities where we've been able to transact, there has been an element of distress associated with those. So sometimes, these are mineral owners that - it's a working interest company that has a small mineral position. They want to sell to pay down debt or they want to fund a drilling program, or whatever. And minerals tend to be the easiest assets to sell. It's just an easier cash flow stream to monetize than an operated position. So, all things being equal, more difficult to get deals done in an environment like this. Although with stabilization of $40, I would expect things to pick up a little bit on that front. But there is an element of distress. I mean, this is a really tough environment for a lot of people, and a lot of people need money right now, I mean, for all the obvious reasons. So, they are looking for liquidity, and we're there and able to provide at a national level, which I think gives us a lot of scale. On future M&A, we're focusing our efforts not only on the micro strategy, but also on some of these larger private equity-backed portfolio companies, most of whom we have an existing relationship with, and just trying to stay close to them. I think it's no secret that the IPO window, I think for mineral companies has narrowed dramatically. I mean, you just need to be a lot bigger than you - when we went public at $300 million back in 2017, that's just not possible in today's environment. I think you have to be $1 billion plus in size. So a lot of these fee-back groups that kind of hope to get enough scale to go public, I think are now considering doing a deal with someone like us for equity, so they can ride the commodity price boom back up. And so, I think this is going to be a really interesting environment for public aggregators because we have a currency. We have a liquid equity currency that we can use when the capital markets for cash are completely shut down and the private markets - I mean it's really hard for private equity guys right now to raise money too. So, I think it puts us in a pretty interesting position, and frankly, that market opportunity is huge. And for us, it's particularly appealing, because a lot of these guys aren't just Permian only. And as you know, we're able to buy everywhere. And so, I think we have a pretty unique opportunity here potentially before year-end or next year to aggregate some of these, $100 million, $200 million, $300 million, $400 million packages. There's just a lot of it out there right now. Bob, anything you'd add to -

No, no. I agree with everything you said.

Do that all make sense, TJ?

That's great. I really appreciate all the insight. I'll just leave it there. Thank you.

Thanks.

Our next question comes from Chris Baker with Credit Suisse. Please proceed with your question.

Hey, guys. Just on the micro strategy, I was wondering, could you give us a sense of how much you've seen pricing improve since before the oil price crash?

Pricing improved since before the - I think you're talking about in terms of the PV, the NAVs that we're able to transact at on the micro strategy. Is that you're asking about?

Yes, just maybe on a dollar per acre basis or something like that.

So, we never look at dollar per acre because we don't buy - that's when - when you have no other metrics, you have to use dollar per acre where there is no existing cash flows. Everything we buy has at least some component of existing cash flow or a DUC that's in the process of getting completed. But before - it's the same parameters. So, we like to do risked net PV 20s on the micro strategies, and that's because the deals are so small that you're able to find some good opportunities. So, what I'm saying is we're still underwriting to that harder to deploy capital, that level at $40 oil, but if we were pre - if you asked about it compared to pre-COVID, I'd say pre-COVID, if you're assuming a price deck of $50 or wherever oil was before this whole nightmare started, it may be a PV 30 or 40 in today's terms, if that makes sense, of what we're able to transact at.

We've done about 24 micro deals, and they're relatively small. And one thing that slowed it down obviously a lot was the fact that people can't go notarize and close deals right now with the pandemic. So, we expect that to pick up hopefully in Q3 and Q4.

Great. And then just a follow-up on -

Did I answer your question, Chris? Go ahead.

Yes. Yes, no, that's helpful. And just as a follow-up, any color on the second half outlook? I know you guys talked about a majority, if not all of the curtailments coming back online. Do you think it's likely that second quarter is the trough for the year?

Let's give him as much detail as we can, where we sit. I think - and Bob, I'd turn it over to you. I think I'd be happy if our volumes stabilized around where they are right now. I mean all things being equal, I expect Q3 to be higher than Q2 because of the reversal of the curtailments. But, Chris, offsetting that, we do have some element of natural decline and fewer rigs running on our properties. So, I'd be happy if our production stayed at it its current level for Q2 for the rest of the year. But I do think that it could go up in Q3. And we still have a fair amount of - I mean it depends on what happens in our high-interest wells, but we still have a fair amount of activity that's meaningful. What would you add to that, Bob?

I'm very proud. We've always said how we've always gone into best areas to buy our properties all through the country, and I'm extremely, extremely proud of only a 7% decline in the second quarter, and I think it's a self-fulfilling strategy. If you buy properties in the better areas, that's going to be the last properties that operators shut in. And that's what we're seeing. I would have problems sleeping at night of our PDP decline was 35% to 40%, and it isn't. It's a five-year average of 13%. So, I think we're in a very strong position, and I think the second half of the year shouldn't be any lower than the second quarter, and I'm cautiously optimistic that it should be higher.

Well, in particular, what we are seeing is gas prices. Gas over $2 now. So, that can pick up a lot more attractive for drilling Haynesville wells. Chris, it's a hard question to answer because there's so much uncertainty. Matt and I were talking before this. We might be in a position to issue guidance sometime in Q3, Q4 for next year. As soon as we feel comfortable enough issuing guidance, Chris, we're going to do it. So, we can give you a better answer. But I would expect our production to be somewhere between where it is today and Q1 for the second half of the year. Is that a fair enough statement, everybody? Do you guys all agree with that?

And Chris, back to the natural gas point, we are 59% natural gas on a six to one basis, and natural gas is up over 20% so far in Q3. So, that's certainly going to help going forward here.

Great. Thanks, guys.

Our next question comes from Aaron Bilkoski with TD Securities. Please proceed with your question.

Thanks. Morning, guys. Maybe just as a follow-up to Chris's questions, you talked about 29 active rigs as of June 30. Would you have any idea where that rig count on your acreage would stand today?

Great question. I don't know the answer to that.

I mean the Baker Hughes rig count has stayed relatively flat, maybe pretty much flat since June 30. So, I'd say probably about the same.

So, about flat. Yes, I agree with that. About flat, Aaron, would be our guess.

Okay. And maybe a follow-up question on the 2019 rigs at the end of June, relative to - I think you had 75-ish at the end of Q1. Which plays were the most resilient which plays saw the largest drop off in rig counts?

That's another question. Do we have the breakdown by rigs?

We do. I can do it. So, Aaron, it's Matt. So we had - this is - going let's compare April to June. So, April 17, we had 70 rigs, and June 30, we had 29 rigs. In April, we had 33 in the Permian and that dropped - so, 22 rigs down to 11 at June 30. So, that was the biggest in terms of drops. And the [indiscernible] operators like Concho, Diamondback, Apache, Parsley, dropping rigs between that period. We still have rigs from Pioneer, Devon in the Permian, but that will be the biggest area in terms of the drop.

Perfect. Thanks, guys.

Our next question comes from Derrick Whitfield with Stifel. Please proceed with your question.

Hey, Derrick.

Hey, guys. Good morning. How are you doing?

Good. Good morning.

Staying on the rig count market share topic, you guys have seen some remarkable gains, as noted on Page 12 in the bottom chart. My question is really twofold. First, how sustainable is that trend? And second, what, in your view, is the primary driver for your success?

That's a great question. Bob, why is our rig count doing so much better in terms of market share gain than kind of the average company?

I mean, I'd just say it's because we've selectively, through the years, bought in the areas where the operators would leave that as the last area to stop drilling. So, we've just bet in better areas in the various basins.

Yes. I mean, it's just really good operators. We've got Pioneer right now drilling a bunch on our acreage. We've got - Laredo and Devon are still very active in the Permian, which is surprising to me. And I think I think some of our gas positions have been remarkably resilient. We still have - we have five rigs running in the [indiscernible] right now. I mean, that was back in June 30 when gas was what? $1.60? We still had five rigs running. I mean, it's just - we've underwritten, individually, every single one of the acquisitions that's in our portfolio, and so just to sum of the parts, I think.

Exactly.

I think we just have a better than average portfolio. We've kind of proven that. I'm glad that you're noticing that because nobody else is.

Yes, thank you.

But I mean that's exactly right.

Just some more color between March and April 17, the U.S. rig count dropped 28%, and our rig count only dropped 7%. They hung out a little longer to finish those wells.

Yeah, I mean what's said differently, Derrick, was - when we were back in April, I mean that's kind of giving you more context than perhaps you want we were having freaks out that these curtailments were going to drop our production 20% or 30% this quarter versus last quarter. I would kind of have trouble sleeping at night, just worried about curtailments. The fact that we're only down 7% and we believe 6% of that 7% is temporarily curtailed and probably has already come back one, I mean if you told - I wish I could go back in time and calm myself down in April there. I mean we're really only down 1% quarter-over-quarter, which is exactly what we've tried to do. That's exactly the purpose of how we built this asset base, was to have that type of performance in adverse environments like this. I mean, this is - we're purpose built exactly for this, and it's just so nice to see it play out the way that we thought it would, if that makes sense. It's very rewarding.

That's certainly a remarkable statement on the quality of your assets.

Well, thank you.

Well, appreciate that.

And shifting over to M&A with my follow-up, perhaps for Rob or Davis, with the backdrop on gas improving, would it be fair to assume your stand increasing deal flow in the gas basins?

Yes, yes, nailed it. And we are happy, right? We're seeing increased deal flow in gas. A lot of Marcellus stuff is coming to market. We're a little bit less rosy on that than we are the Haynesville. We tend to prefer the Haynesville for a number of reasons, and we have more experience there too. But yes, we're seeing more activity on the gas assets. And the other nice thing about that, Derrick, if you kind of backed our diversified strategy, there aren't a whole lot of public buyers for gas assets. I mean it's one or two groups, us and one of our peers maybe that are even interested in buying gas assets. So, I think that puts us in a pretty unique position to consolidate that segment of the market, which is obviously enormous.

Very helpful. Thanks for your time.

Thanks, Derrick.

Yes, thank you.

There are no further questions at this time. At this point, I'd like to turn the call back over to management for closing comments.

We thank you all for joining us this morning, and look forward to speaking with you again when we report third quarter results. This completes today's call.

Ladies and gentlemen, we thank you for your participation. This does conclude today's teleconference. You may disconnect your lines, and have a wonderful day.