Kimbell Royalty Partners LP

Greetings and welcome to the Kimball Royalty Partners First 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. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Rick Black of Investor Relations. Thank you, Mr. Black. You may begin.

Thank you, operator, and good morning, everyone. Welcome to the Kimbell Royalty Partners conference call to review financial and operational results for the first quarter of 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, May 7th, 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 or expectations for future events or future financial performance, are 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 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 press release for our disclosure on forward-looking statements. These factors, as well as other risks and uncertainties, are described in detail in the company's filings with the Securities and Exchange Commission. Management will also refer to non-GAAP measures, including 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. Kimball assumes no obligation to publicly update or revise any forward-looking statements. And with that, I would now like to turn the call over to Mr. 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 extending our thoughts and prayers to those affected by the COVID-19 crisis. These are certainly unprecedented times, and we are doing all that we can to support the health and safety of our employees and to assist with the recovery of our community from this crisis. We are especially grateful for all of the hard work being performed by first responders and healthcare workers. They have truly been an inspiration to us all. We also applaud the legions of hardworking Americans all over the country that have remained dedicated to keeping the nation's food supply and other vital components of the economy up and running during this difficult time. As you know, COVID-19 has contributed to deeper challenges in the energy sector than most other industries, as the price of crude oil recently reached record lows. The market volatility and pricing pressures that existed before the pandemic began have now created the perfect storm with an unparalleled supply glut and continuing demand disruption. Notwithstanding the challenging effects of this health and economic crisis, we believe that Kimball's fundamental business model will provide far more stable and resilient than others. As of the first quarter, approximately 60% of our production was from natural gas, which continues to have an improving macro outlook. and we have strengthened our balance sheet and improved liquidity. In addition, we believe that we have one of the strongest hedge books in all of energy in terms of both in price and duration. We currently have a substantial portion of our oil and natural gas production hedged in the form of swaps going out two years with prices for oil averaging in the low 40s and natural gas averaging around $2.49 per MMBTU. Our leadership team has been successfully managed through a number of economic cycles over the past three to four decades, and I believe Kimball is very well positioned to weather this storm. In light of the potential for curtailments of production in the coming months, we made the decision to pay down a portion of our debt during the second quarter. We will fund the debt repayment by allocating 50% of our cash available for distribution from Q1 2020 together with certain cash received at the closing of the Springbok acquisition and other cash reserves for the repayment of $15 million in outstanding borrowings under our revolving credit facility. We believe that, in light of the uncertainties in the economy right now, particularly in the oil and gas sector, paying down a portion of our revolver is prudent. We also believe that strengthening our balance sheet and maintaining dry powder in this challenging environment provides additional financial flexibility. Touching now on the first quarter results, we achieved new record high performance for daily production and consolidated adjusted EBITDA. In each case, after giving effect to a full quarter of Springbok as the effective date of this acquisition was October 1st, 2019. Our first quarter production daily run rate was 12,602 barrels of oil equivalent per day, up 5% compared to the same quarter last year. Including a full quarter of the Springbok assets, the first quarter run rate daily production was 15,188 BOE per day, up 27% compared to Q1 last year. We had 70 active rigs operating on our properties as of April 17th, 2020, which represents an increased market share of all land drilling rigs in the continental United States compared to year-end 2019. Davis will walk you through more of the Q1 2020 metrics during his remarks. Given the unprecedented circumstances of the current economy and challenges in the energy industry, I'd like to spend a few moments recapping the fundamental characteristics of our model that provide us with continued confidence today about the royalty in mineral space. It is important to understand our business model and our diverse, high-quality asset portfolio. As an oil and gas minerals and royalty company, we benefit from the fact that we do not make any direct capital expenditures, and our expense structure is extremely efficient and more akin to an asset management company rather than a traditional oil and gas company. Our business builds on a broad, stable, and diverse portfolio of royalty assets across all the major basins in the lower 48. Our mineral arches 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 its minerals peers. In addition, our pre-developed reserves at year-end 2019 increased by approximately 22% year-over-year, including 8% organic growth. Perhaps most importantly, Kimball has one of the highest PDP reserve-to-production ratios, or R over P ratio, in the entire energy industry of approximately nine years. These strong characteristics of our business, coupled with a proven bolt-on acquisition strategy that consolidates highly accreted assets have demonstrated significant growth and cash flow for our company. Our goal is to continue advancement of our long-term strategy as a preeminent consolidator of diversified, high-quality, 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, our business model is well positioned for the tough challenges ahead. Last month, 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. Please remember that we issued equity directly to the seller as a fixed number of units for nearly half of the total purchase price, which helped us to continue to maintain our financial flexibility. From an M&A perspective, we plan to continue to fund our micro acquisition strategy at current depressed commodity prices and continue to be well positioned as a consolidator in the highly fragmented minerals industry. As we navigate through the challenging landscape of today's current volatility relative to M&A, we plan to maintain a strict discipline and selection process focused on diversified high-quality targets. We also want new prospects to be immediately cash flow accretive, enhance production stability and diversity, as well as provide years of future growth. We believe that Kimball offers a compelling investment opportunity with growth opportunities and a robust distribution yield, which we expect 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 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. I want to take a moment to echo Bob's opening comments about COVID-19 and this pandemic. We will remain vigilant regarding this health crisis and will continue to follow all federal, state, and local guidance regarding safety measures for ourselves, our employees, and our communities. Regarding the economic effects of this crisis, we strongly believe that our business and our asset portfolio are well positioned to manage and even grow in 2020 and beyond. Even if WTI oil traded at zero for the entire second quarter of 2020, we estimate that we would still generate positive distributable cash flow due to our significant natural gas exposure and strong hedge book. First, I want to cover our record-breaking production in the quarter, followed by a recap of our first quarter financial results. Since the springback transaction effective date was October 1, 2019, with a closing date of April 17, 2020. We are entitled to the Springbok cash flow since October 2019, but our GAAP Q1 2020 financials will exclude Springbok. I plan to provide Q1 2020 consolidated adjusted EBITDA and production numbers with and without Springbok in my remarks today. Our first quarter average daily run rate production was 12,602 BOE per day, with a total average daily production of 13,358 BOE per day, which consisted of 756 BOE per day relating to fire period production recognized in the quarter. The 12,602 BOE per day of run rate production for Q1 2020 was comprised of approximately 40% from liquids, which was 27% from oil and 13% from NGLs, and 60% from natural gas on a six-to-one basis. The prior period production recognized in Q1 2020 was primarily due to Newell's outperforming estimates. Including a full quarter of Springbok, run rate production for Q1 2020 was 15,188 BOE per day, a new record high for the company. Oil, natural gas, and natural gas liquids revenues for the first quarter increased 12% compared to the first quarter last year to $25.6 million. This increase reflects solid performance from acquisitions made in the past 12 months, despite the decrease in realized commodity prices. Consistent with prior quarters, while downward pressure persisted for many E&P companies, Our broad-based, high-quality asset portfolio continued to outperform expectations in Q1. Consolidated adjusted EBITDA was $18.8 million, up 17% compared to the first quarter of 2019. Including a full quarter of Springbok cash flows, consolidated adjusted EBITDA for Q1 2020 was $23.3 million, also a new record. On the expense side, general administrative expenses were $6.5 million in Q1 2020, $4.4 million of which was cash G&A expense, or $3.85 per BOE. Including a full quarter of production attributable to the Springbok assets, Q1 2020 cash G&A was $3.20 per BOE. The company will distribute cash of 17 cents per common unit on May 11th to holders of record as in the close of business on May 4th for the Q1 2020 distribution and also made the decision to pay down 15 million of debt in order to strengthen the balance sheet and increase liquidity. Had we not allocated 50% of Q1 2020 cash available for distribution to pay down debt, the cash distribution per unit would have been 34 cents. However, we believe this is a conservative and prudent measure given the high level of uncertainty and recent economic disruptions in the broader markets and the energy industry. 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 Q1 distribution will be a non-taxable reduction to increase unit holders' capital gains or decrease unit holders' capital loss when the unit holders sell their common units. Furthermore, Kimball expects substantially all distributions paid to common unit holders from 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 to 2025, are expected to be taxable dividend income. Turning now to realized pricing in the first quarter, average realized price per BBL of oil was $44.48, per MCF of natural gas was $1.75, and per barrel of NGLs was $12.22, and per BOE combined was $19.83. Looking now at the balance sheet and liquidity, at March 31st, 2020, Kimball had approximately $101.2 million in debt outstanding under its revolving credit facility and approximately $123.8 million in undrawn capacity, or approximately $198.8 million if aggregate commitments were equal to Kimball's current borrowing base, which is $300 million. Kimball was in compliance with all financial covenants under its revolving credit facility at March 31, 2020. At April 24, 2020, after taking into account the previously disclosed drawdown to fund the cash portion of the purchase price in the Springbok acquisition, Kimball had approximately $186.7 million in debt outstanding under its revolving credit facility. After getting effect to the previously announced repayment of $15 million in outstanding borrowings, which is anticipated to occur in the second quarter of 2020, Kembo expects to have approximately $171.7 million in outstanding borrowings under its revolving credit facility and a pro forma total debt to Q1 2020 annualized consolidated adjusted EBITDA, including a full quarter of the Springbok assets of approximately 1.8 times. We think it is important to note the power of the free cash flow that our business generates. Traditional oil and gas companies tend to focus on debt to EBITDA as the primary leverage metric, which is generally meaningless since it doesn't factor in required maintenance capital or other drilling requirements. The more appropriate metric to truly measure leverage is debt to free cash flow. As we have proven in Q1, our substantial free cash flow is a tool that we can use to either pay out at its entirety each quarter in the form of a cash distribution, pay down a portion of our debt, or a combination of both, depending on market conditions. Most other EMPs may have positive EBITDA, but zero or negative free cash flow. Thus, they have no real ability to pay down a meaningful amount of their debt balance. We are simply a far more efficient business model that is heavily focused on consistent free cash flow generation. Turning now to our reserves that Bob mentioned earlier, as of December 31, 2019, approved reserves increased by approximately 22% year-over-year to almost 41 million barrels of oil equivalent, reflecting the acquisitions made during the year along with continued organic reserve growth on Kimball's acreage. Finally, we are very pleased to be able to disclose for the first time in our earnings release our ducts and permits by basin on our major properties, including the Springbok assets. We had 2.96 net ducts, 882 gross ducts, and 2.35 net permits, or 476 gross permits, on Kimball's acreage as of March 31st, 2020. This data does not include our minor properties, which we estimate could add an additional 20% to the duct permanent inventory based on our experience. In addition, for the eight months of check step data for which we have completed analysis, we estimate that on average 129 gross wells and 0.5 net wells were brought online each month on average during 2019. We are providing this increased level of transparency in an effort to show that the company not only has robust development on its acreage, but also near-term future development catalysts across both oil and natural gas and nearly every major producing basin. Our business model has not changed due to recent events, and Kimball continues to build on its track record as a leading consolidator of the oil and gas mineral space. We expect our success to continue into 2020. We do think the migration of private ownership to public ownership of mineral assets across the US will continue to accelerate. With that, operator, we are now ready for questions.

Thank you. We will now be conducting a question and answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, It may be necessary 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 the line of John Freeman with Raymond James. Please proceed with your question.

Thank you. Hi, guys.

Morning, John.

Hey, John.

I just wanted you all to talk a little bit more about sort of the strategy and at least in the foreseeable future, about how you think about balancing the lower payout ratio with sort of the two-pronged of, you know, looking at, you know, lowering the leverage more, but also what is likely to have a lot of really attractive kind of acquisition opportunities in this market, I would expect, in the dry powder you get with having that lower payout ratio.

Yeah, great question, John. I think our plan is to pertain to the payout ratio. Just given the enormous uncertainty in the market, it's really, from our board discussion, it's taken on a quarter-by-quarter basis. So we'll reevaluate at each quarter what amount of the cash flow we want to pay out. We continue to fund our microaggregation strategy. So to your point, we expect to see some pretty compelling acquisition opportunities here in the near future. Based on our experience, it takes a couple of months of royalty owners receiving checks at reduced cash flow amounts for them to accept the new reality of where hydrocarbon pricing is. So the A&D market, as you might imagine, is pretty slow currently, but we expect it to pick up in the next, you know, let's call it three to six months. Beyond that, we continue to see a tremendous opportunity to use our equity very selectively on highly accretive transactions, particularly with private equity-backed groups that have diversified assets. Doing all equity deals allows us to accomplish two things at once. One, improve accretion on a dollar-per-DCF basis, and then also to delever to the extent that it's funded entirely with stock issued directly to the sellers. So I think that's how we're thinking about it for now is just being very careful in this environment. And I know things feel a lot better with oil at $25 today, but it was $12 eight days ago. So I think it's only prudent that we as management and our board make those decisions in real time on a quarter-by-quarter basis as things develop.

That's great. And then does – Does the fact that at the moment with the payout ratio where it's at, you sort of have the side benefit of it, it lowers your cost of capital. Does that in any way change sort of when you're looking at a creative acquisition, especially given at least recent track record of using equity on a lot of the bigger deals? Does that at all change the set of assets you can look at?

No, I think the game plan is still the same. I mean, we don't expect to do any major deals, you know, imminently in this environment, to state the obvious. And we'd like to see a recovery in the sector before we start to use our stock. We're obviously not happy with where it's trading today, and we think it's unduly low, just kind of a reflection of overall market conditions. But no, I don't think it changes our strategy, other than to say, John, that Obviously, you know, we've always been selective, but even in this market, you have to be hyper-selective. I think there's only a small, you know, we might be one of the only groups that's capable of buying assets both in the Permian Basin and outside of it. So I think competition for assets nationally is going to continue to dwindle. We're seeing a lot of the private equity back quote competition really dry up. It's become more difficult, I think, for folks to raise money and deploy it in an attractive way. And so I think that plays into our hand as well over time. We think coming out of this, it's going to present some pretty compelling acquisition opportunities. What do you think you'd add, Matt?

Yeah, John, just in terms of your question about cost of capital and, you know, WAC. You know, right now the credit facility with LIBOR dropping so much and interest rates being so low, we're looking at, you know, a credit facility interest rate cost of between 3.1% and 3.2%. So it's extremely low interest. cost of capital in the credit facility. To the extent that we do acquisitions using cash, especially on the micro strategy where some of those transactions have extremely high yields, it generates a lot of immediate accretion to us. Okay, good point.

That's great. I appreciate all the information. All the best to you guys.

Yeah, you too, John. Thanks, Sean. To you and your family.

Thank you. Our next question comes from the line of Derek Whitfield with Stiefel. Please proceed with your question.

Good morning, all. Perhaps for Bob or Davis, I wanted to stay on cash distributions to build on John's first question. As we look out towards a recovery scenario, what will be your guiding principles or conditions for increasing the percentage of distributable cash flow?

That is a great question. For now, we're going to address that on a quarter-by-quarter basis, and I can't speak for our board at large, but directionally, I'll point to If we get back to our, you know, when and if we get back to our target leverage ratio below one and a half times, I think it's, I'll say likely, if not probable, that we resume paying out 100%. I think we just want to be, and maybe, you know, history might show that we've been too conservative by directing some cash to debt pay down in this environment. But the reality is it's just an environment with incredible uncertainty, and we'd rather be too conservative than the other way. So I think once we get back to a position where we feel more confident and we feel like the leverage is under control at less than one and a half times, that's probably the point at which we start resuming, you know, 100% payout. So it's something to that effect.

Understood. And as my follow-up, regarding your Hainesville royalty position more broadly, are you sensing any change in activity with the steadily improving forward curve?

We have not seen anything imminently. We had a really big year last year in the Haynesville. You might recall, Ben, I believe it was the second quarter of last year, we had some huge wells come online, which led to 8% quarter-over-quarter growth in the entire company, so very meaningful wells. We still have more PUDs on that acreage and nearby acreage of similar interest. We have yet to see – to your point, we think that our natural gas position is amongst the best in the industry, particularly in the Amesville shale. We haven't seen an immediate impact to increased drilling activity, but we would expect that with the drop in associated gas and the improved outlook for natural gas holistically, we would expect to see an increase in the Amesville. Funny enough, this quarter we did see – We went from one rig in Appalachia to three and had some big Appalachia rigs come online. So we are seeing some improvement in the gas basins, and we would expect that to continue. And, again, I'll just say this again for the benefit of anybody on the call. You know, 60% of our production is natural gas. You know, we were widely – I will even use the word ridiculed for that in the past for being, quote, gassy – We've always done that by design. Our company has always had a healthy balance of oil and natural gas, and it's to protect our investors in moments exactly like this where one commodity has gotten a hit disproportionate relative to the other. And so I think this is an environment where a diversified model with a low PDP decline rate and a healthy mix of oil and natural gas should outperform. So it's a challenging environment, but we think we're up for that challenge.

Just one follow-up comment. Just on the overall rig count, I mean, we had 81 rigs as of year 19, and as of 4-17, we ran this pretty recently. We had 70 rigs across our acreage, including Springbok. So our market share of the entire lower 48 land drilling fleets, based on Baker Hughes, went from 11.9% to 13.7% as of 4-17. We actually had a rig count increase in the Permian region, from 24 rigs a year end to 33 rigs on 4-17. And some of the operators, we had six rigs with Pioneer. We had six with Parsley, four with Concho, two with Diamondback. We had 11 rigs in Midland County. This is all as of 4-17. Now, we had some rigs drop in the MidCon expected. We had a few rigs drop out of the Haynesville and with the Wilson Basin. But Appalachia, as Davis mentioned earlier, we went from one rig to three rigs, and those are two Cabot rigs that were added. as well. So a lot of activity, frankly, in the market pretty good.

Yeah. The reason we focus on market share of all rigs, Derek, is that we think that that's the best way of kind of showing people that our assets tend to be on average in better locations than the average acreage if our market share continues to improve despite a drop in the overall rig count. We just think that's the best litmus test for that. Anything else you'd add, Bob? No, I agree.

It's very helpful, guys. Diversification clearly matters. Thanks for your commentary.

Thanks, Gary.

Yeah, thank you. Thank you. Our next question comes from the line of Jason Wangler with Imperial Capital. Please proceed with your question.

Hey, good morning, guys. Morning, Jason. This may be a real-time question that's hard to answer now, but, I mean, as we're hearing a lot of the operators talk about, you know, shutting in production, whether it's, you know, late April or even into May, Are you guys seeing any impact on that? Or maybe it's even more what you guys are hearing on that aspect is how that might affect you guys in the next couple of months?

Glad you asked that. So I think our company is going to be a helpful data point in the second quarter for the industry at large, just given the fact that I think we probably have more exposure to more acreage and more wells than maybe any other company in the United States. And so I think that seeing activity and the way that operators are changing their behavior, you know, we're going to see that, and we're going to be able to provide you guys, I hope, you know, at the end of Q2 with information on how things are changing. You might be surprised to hear this. We've only received one force majeure notice, and that's from an operator that I didn't even know still existed in the Eagleford. Other than that, have we gotten anything, looking around the table, any other material force majeure notices? I mean, we know it's happening. We know that operators are choking back and curtailing. I'm not sure their legal requirement to provide us with notification of their plans. I think they're probably reluctant to notify thousands of mineral owners of what they intend to do. But we'll be tracking that. And it's going to be interesting to see how we get affected relative to some more concentrated companies. because a lot of our production lags three to six months or even more. We sometimes get paid on wells that are 18 months in suspense. So we'll see how this plays out, but it would be my expectation that we outperform relative to a lot of other groups just given the diversification, the small interest in tens of thousands of wells, and just that combined effect. This quarter, we got a million-dollar check on an asset that we didn't even know we owned. So, I mean, we just find good news with these diversified portfolios that kind of comes out of nowhere somehow.

The other thing, as we've said in the past, over the last 20 years, we've really taken care to buy high-quality properties. And so when you hear, and I think it's probably going to happen, that the operators are going to shut in the marginal wells and the stripper wells, and that's a very, very small percentage of our overall production. So I think we have insurance against that, too.

That's really helpful. And maybe kind of alongside that, you kind of mentioned it there, Davis, about whether it's lease extensions or changing the contract a bit on your acreage. Is that something that you guys are maybe starting to hear about as far as with this activity slowdown, folks either looking to make sure to extend the leases to make sure that they're not coming due or things like that, which may actually, like you said, kind of bump up on your lease bonuses and things of that nature?

Yeah, good question, Jason. So I'll say this to you. Everything that we own that we know of is held by production. So we're not necessarily worried about leases going away. I think what we expect to see, given the fact that we've received only one force majeure notice, which would allow them to kind of get around the shutting in production temporarily and not allowing us to have any legal recourse, the fact that we haven't seen more of that, frankly, has surprised me. which suggests to me – I mean, tell me what you think, too. It suggests to me that operators aren't necessarily shutting in entirely on all these leases. They're just choking back, you know, in some cases probably pretty dramatically. So we don't expect to lose a lot of leases, again, because everything we own is HPP. We only buy properties that have existing production. That's a unique aspect of our business model that's not necessarily shared by many others. So we haven't seen any of that yet, but to the extent we start to see operators playing games or trying to get out of their obligations to us, we certainly have a duty to all of our investors to be as aggressive as we can to maximize value for folks. And worst case scenario, if some of these operators lose leases, if they're in good areas, We'll release them to somebody else, collect a new lease bonus, to your point, and, you know, hopefully a higher loyalty and proceed that way. So we're going to be doing everything we can to protect our assets, protect our investors, and maximize value through this difficult time.

Great. I appreciate it. Thanks very much.

I appreciate the questions.

Thank you. There are no further questions at this time. I'd like to turn the floor 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 the second quarter results. This completes today's call. Thank you.

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