Kimbell Royalty Partners LP

Greetings and welcome to the Kimbell Royalty Partners Second Quarter Earnings Conference Call. At this time, all participants are on 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 call is being recorded. 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 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 of future financial performance, are all considered forward-looking statements made pursuant to the Safe Harbor's provision of the Private Securities Litigation Reform Act of 1995. We will be making forward-looking statements In the heart 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 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. Kimball assumes no obligation to publicly update or revise any forward-looking statements. I would now like to turn the call over to Bob Ravenous, Kimball 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 Ravenous, our President and Chief Financial Officer, Matt Daley, our Chief Operating Officer, Blaine Reinsberger, 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 and 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 daily production during the quarter was 14,069 barrels of oil equivalent per day, down 7% from Q1 2020 record production of 15,188 VOE 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, Kimball 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 Kimball 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-declined 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 to 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 Kimball 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 in its 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 US energy sector. As an example, one only has to look at Q2 production for Kimball 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 percent quarter over quarter, which was 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 ducts 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 duct 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 30th, Kimball had 806 gross and 2.98 net drilled but uncompleted wells, as well as 611 gross 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 ceiling test impairment expense recorded during the quarter related to the substantial weakness in commodity prices. This non-cash ceiling test impairment is not expected to impact the cash flow available for distribution generated by Kimball 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 SpringBuy 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 percent of the Q2 cash available for distribution, which is 13 cents 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, Kimball anticipates that substantially all of the Q2 distribution will be a non-taxable reduction to the tax basis of the unit holder's investment and will not constitute a taxable dividend. the reduced tax basis will increase unit holders capital gain or decrease unit holders capital loss when unit holders sell their common units. Furthermore, Kimball 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 unit holders 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, Kimball had approximately $171.7 million in debt outstanding under its revolving credit facility. After a giving effect of $477,051 in acquisitions under Kimball's microinvestment strategy so far in Q3, and the repayment of approximately $2.5 million and outstanding borrowings discussed above, which is anticipated to occur in Q3, Kimball expects to have approximately $169.7 million in outstanding borrowings under a revolving credit facility and approximately $55.3 million in undrawn capacity, or approximately $130 million if aggregate commitments were equal to Kimball'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 1st, 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 ducts 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 ducts, 806 gross, and 2.25 net permits, or 611 gross, on Kimball'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 duck and permit inventory based on our experience. In addition, for the 11 months of check stub 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 advisors 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 Kimball and will strive to continue to generate long-term value in the 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'd like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star 2 if you'd like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset. Before pressing the star keys, please ask one question and one follow-up question, then re-queue for additional questions. One moment, please, while we poll for questions. Our first question comes from John Freeman with Raymond James. Please proceed with your question. Hi, guys.

Hey, John. Hey, John. How are 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 of it you think was just curtailments versus outright shut-ins.

Yeah, Bob, do you want me to start? Sure. Yeah, 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 six out of the seven percent would be a good conservative guess is temporary curtailment. Is that correct? Yeah. And the largest one was EP Energy. Is that correct? So, John, it's not. So the good news is we expect, you know, 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 even more aggressive and say we believe most of those have already reversed themselves. Is that a fair statement, Blaine? Yeah. Yep. In June. Yep. In June, yeah. So that's the good news, John.

No, that's great. And then I want to spend a little bit of time talking more about the payout ratio. Y'all increased it from the 50% to the 75%. I know in the past you sort of talked about if you got leverage back down below one and a half 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 know, you all have, you know, the lowest base decline rate of any base. 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 all the way 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 leverage target might, you know, over time maybe move closer to one time.

yeah yeah no great great question john thank you for asking it you know there's not a perfect answer on the payout ratio and we have agonized over it pretty much every single day over the you know ever since this whole covet fiasco started i think that when we made the decision to go to 40 to 50 we had a long conversation with the board it was the same week that oil went to negative forty dollars so at that time give me kind of a long explanation but at that time We just didn't know what we didn't know. We didn't know how bad this was 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 had improved dramatically. 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's going to reverse itself. We were encouraged by the fact that our market share of rigs in the U.S. has actually continued 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 hit leverage closer to that one to one and a half times. Another factor why we went from 50% to 75% is 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, right? 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 that 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. Their families have been in it for multiple generations. They've borrowed money against their cash flow for generations. And They understand our asset base and the diversity and the shallow decline profile. And so I would say most of the people we talked to, John, and 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, you know, if oil goes to 60 or 70 bucks and our EBITDA screams through the roof, we may consider going above 75%. But I think for the time being, you know, 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 the comments, guys. Thanks a lot.

Thanks, Sean. 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 deals 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. Yeah. Great, great question. So nothing is, so we have very strict underwriting standards on the micro strategy where we're targeting kind of risk PV, you know, let's call it twenties 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, you know, really good deals, right? I mean, it's just hard to transact. So we're talking about PV20s risk at, you know, $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 David Duhalde, Volatility and oil prices kills deals. It just makes it really hard to get things done. That being said, the opportunities where we've been able to transact, David Duhalde, there's been an element of distress associated with those. So sometimes these are mineral owners that, David Duhalde, you know, 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 at $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 it 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 microstrategy, but also on some of these larger private equity-backed portfolio companies, most of whom we have an existing relationship with and just try to stay close with them. I think it's no secret that the IPO window, I think, for mineral companies – is narrowed dramatically. I mean, you just need to be a lot bigger. 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 a billion plus in size. So a lot of these PEVAC 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, $200, $300, $400 million packages. There's just a lot of it out there right now. Bob, anything you'd add to that?

Nope, nope. I agree with everything you said.

Does that all make sense, TJ?

No, that's great. I really appreciate all the insight. I'll just leave it there. Thank you.

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, can you give us a sense of how much you've seen pricing improve since, you know, before the oil price crash?

pricing improved since before the oil price? You're talking about in terms of like the PV, the NAVs that we're able to transact at on the micro strategy? Is that what you're asking about?

Yeah, just maybe on like 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 you have no other metrics, you have to use dollar per acre when there's no existing cash flow. So everything we buy has at least some component of existing cash flow or a duct that's in the process of getting completed and But before, it's the same parameters. So we like to do risk, net, PV20s 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 at that level at $40 oil. But if we were, you know, since you asked about it compared to pre-COVID, I'd say pre-COVID, if you're assuming a price deck of, you know, 50 bucks or wherever oil was before this whole nightmare started, I mean, it'd be like a PV 30 or 40 in today's, you know, in today's terms, if that makes sense on what we're able to transact at.

Yeah, yeah. And 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, you know, people can't go notarize and close deals right now with the pandemic. So we expect that to pick up hopefully in, you know, Q3 and Q4. Yep.

Great. And then just to follow up.

Yeah, go ahead.

Yeah. Yeah, 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 the 2Q is the trough for the year?

Let's give them as much detail as we can where we sit. I think – and, Bob, I 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'd 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 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?

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'd have problems sleeping at night if 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're seeing with gas prices, gas over two bucks now, so that just becomes a lot more attractive for drilling Haynesville wells. So, yeah, so Chris, it's a hard question to answer because there's so much uncertainty. I mean, Matt and I were talking before this. We might be in a position to issue guidance sometime in Q3, Q4, or 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 your statement, everybody? You guys already at that?

Hey, Chris, back to the natural gas point. We are 59% natural gas on a 6-to-1 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 Bilkowski with TD Securities. Please proceed with your question.

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

Great question. That's a good question, Aaron. I don't know the answer to that.

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

Yeah, I agree with that. About flat, Aaron, would be our best guess.

Okay. And maybe a follow-up question on the 29 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 is another excellent question. Do we have the breakdown by rigs?

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

Perfect. Thanks, guys.

Thank you.

Our next question comes from Derek Whitfield with Stiefel. Please proceed with your question.

Hey, Derek. Hey, guys. Good morning. How are you doing? Good. Good morning. So 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 is 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 just think 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 been in better areas in the various spaces.

Yeah, I mean, it's just really good operators. I mean, we've got, you know, 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 some of our gas positions have been remarkably resilient. We still have five rigs running in the handle right now. And that was back in June 30 when gas was, what, $1.60? We still had five rigs running. So, yeah, I mean, it's just... We've underwritten individually every single one of the acquisitions that's in our portfolio, and so just the sum of the parts, I think we just have a better-than-average portfolio. We're kind of proving that. I'm glad that you're noticing that because nobody else is, but that's exactly right.

Just to more color, between March and April 17th, the U.S. rate count dropped 28%, and our rate count only dropped 7%. They hung out a lot longer to finish as well.

Yeah, I mean, what's said differently, Derek, when we were back in April, I mean, I'm just kind of giving you more context than perhaps you want. We were having freakouts that these curtailments were going to drop our production 20% or 30% this quarter versus last quarter. I mean, 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 online. I mean, if you had told me, I wish I could go back in time and calm myself down in April where, 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 and 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.

It does. It's certainly a remarkable statement on the quality of your assets. Yeah, well, thank you.

Well, I appreciate that.

And shifting over to M&A with my follow-up, perhaps for Bob or Davis, With the backdrop on gas improving, would it be fair to assume you're seeing increasing deal flow in the gas basins?

Yeah, yeah, nailed it. That's exactly right. We're seeing increased deal flow in gas assets. A lot of Marcellus stuff is coming to market. We're a little bit less rosy on that than we are in the Haynesville. We tend to prefer the Haynesville for a number of reasons, and we just have more experience there too. But, yeah, we're seeing more activity on the gas assets. And the other nice thing about that, Derek, I mean, kind of back to our diversified strategy, there aren't a whole lot of public buyers for gas assets, right? 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.

It's very helpful. Thanks for your time. Thanks, Derek. Yeah, 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.