Kimbell Royalty Partners LP (KRP) 2017 Q2 法說會逐字稿

Greetings, and welcome to the Kimbell Royalty Partners second quarter earnings conference call. (Operator Instructions) As a reminder, this conference is being recorded.

I would now like to turn the conference over to your host, Mr. Rick Black, Investor Relations. Thank you. You may begin.

Thank you, Audrey, and good morning, everyone. Thanks for joining the Kimbell Royalty Partners Conference Call to Review Financial and Operational Results for the Second Quarter 2017. This call is also being webcast and can be accessed through the audio link on the Events and Presentations page of the Investor Relations section of kimbellrp.com. Information recorded on this call speaks only as of today, August 10, 2017. Therefore, please be advised that any time-sensitive information may no longer be accurate as of the date of any replay.

Before we continue, I would like to remind you that the statements in the discussion that are not historical facts, including statements of expectations or future events or future financial performance are forward-looking statements made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve inherent risks and uncertainties, and we caution investors that a number of factors could cause actual results to differ materially from those contained in any such 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.

We will be making forward-looking statements as part of today's call that, by their nature, are uncertain and outside of the company's control. Actual results may differ materially. Please refer to our earnings press release for our disclosure on forward-looking statements. Management will also refer to non-GAAP measures during today's call, including adjusted EBITDA and cash available for distribution. Reconciliations to the nearest GAAP measures can be found at the end of our earnings press release. Kimbell assumes no obligation to publicly update or revise any forward-looking statements.

At this time, 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. Thanks for joining us. I'm here with several other members of our senior management team, including Davis Ravnaas, our President and Chief Financial Officer; Matt Daly, our Chief Operating Office; Jeff McInnis, our Chief Accounting Officer; and Blayne Rhynsburger, our Controller. I'll begin with a look at our operational performance during the second quarter, our latest distribution and our view of the opportunities ahead of us. Then I'll ask Davis to cover our financial performance in more detail. After that, we'll take your questions.

Our portfolio of minerals performed very well in the second quarter, although lower oil prices slowed the growth in drilling activity resulting in a consistent rig count with our first quarter of 24 rigs. The Maxus Mid-Continent acquisition we closed in late April enabled us to offset natural production declines from our existing portfolio and to exit the quarter with slightly higher production. Our exit rate at June 30 was 3,116 BOE per day versus 3,025 at the end of Q1. Average daily production for the quarter was 3,067 BOE per day. On a revenue basis about 58% was oil, 11% was natural gas liquids and 31% was natural gas.

With a shift in pricing between oil and natural gas during Q2, natural gas was a slightly bigger contributor to overall revenues compared to Q1.

Drilling activity on our properties continues at a brisk level with 24 active rigs, up from 15 around the beginning of the year. Two more rigs went to work on our properties in the Permian Basin, which is the single most active basin in the U.S. right now. We now have 17 rigs working in the Permian. These 2 rigs were offset by 2 rigs in the Terryville complex that moved off our acreage during the quarter.

I would point out that the operators of our leases, about 700 across the country, were faster out of the gate early this year than the overall market to accelerate their drilling activity. Currently 2.5% of all the U.S. land rigs are drilling on our properties. New drilling activity on our acreage -- on our mineral acreage allows us to replace declining production and realize incremental production from the same leases at no cost to us, and it produces additional cash flow available for distribution to our unitholders.

Part of our business model is to conduct our own analysis of the potential of our mineral interests and to work closely with our operators to ensure the greatest return possible from our assets. We want to see development and production of as much of the upside as possible, whether it's from more infill drilling or applying new technologies not previously introduced into those fields.

We have mineral and royalty interests across 20 states in more than 300 counties in every active basin in the Lower 48, which is exactly where we want to be over the long term. We like our position in the Permian, which we were accumulating long before the rush began. But as you know, the hottest play designation tends to move around the country every few years, and we always want to be where the economics are the strongest and the most incremental capital from operators is being deployed.

Turning now to our distribution. Last month we declared a $0.30 per unit distribution for the second quarter, which was a 30% increase over our initial distribution in Q1 of $0.23. This increase was largely due to the shorter quarter in Q1 versus Q2 due to our IPO closing on February 8. The Q2 distribution is payable on August 14 to unitholders of record as of August 7.

Our primary goal is to be able to steadily grow our distribution to unitholders by increasing our revenues both through acquisitions and organic growth. Third-party acquisitions and dropdowns will be the main driver of growth for our partnership and our distributions, and we're delighted with the Maxus acquisition we completed in April. But rule #1 is, we don't over pay. We look at a lot of deals, but we only make bids on about 5% to 10% of those deals we review.

As we mentioned last quarter, we are looking at opportunities at every major basin in the Lower 48. We don't chase bubbles. For example, we are continuing to look at deals in the Delaware Basin, but that acreage is currently priced at levels we have never seen in our 20 years of business. We don't think that at those price levels, based on our internal modeling that the numbers can work. In fact, today's acreage prices would imply a cash yield of less than 1% per year.

As an aside, given our strong footprint in the Permian Basin, we feel that our existing Permian acreage is dramatically undervalued based on the current market prices that we are seeing for similar acreage. We are continuing to look for deals which meet our criteria for investment. That is, number one, they're immediately accretive to unitholders and drive distribution growth; two, they have long life stable production with shallow decline curve that enables us to generate current income; three, they have significant upside potential for organic growth through additional field development or application of new technology; and four, we want reliable, financially strong operators.

Dropdowns from our sponsors and contributing parties will be a significant source of growth over time. We currently expect the first one to be in 2018, which will provide additional time to put on production drilled but not yet completed wells that can contribute immediately to our production volumes. Since we are still in the IPO honeymoon phase and because mineral-based MLPs are a pretty small and relatively new group, I'd like to briefly recap our particular structure and benefits to investors who may be new to this kind of investment.

Unlike an upstream MLP, 100% of our assets are mineral interest rather than working interest in oil, gas and NGLs. Our royalties are calculated as a percentage of revenue. So we take our share right off the top. We don't pay operating costs or CapEx expense. So as a result, given the same revenue per barrel, a royalty barrel realizes a much higher margin than a working interest barrel and we face 0 exploration risk. We generate very significant current income for unitholders. We don't buy royalties ahead of the drillbit.

Two other big advantages to unitholders: one, KRP provides a very significant tax shield on distributions, so you benefit from a compelling tax advantage on your investment; and two, KRP doesn't have a general partner that collects incentive distribution rights or receives subordinated units that can significant reduce the LP unitholder payout. That is a big advantage to common unitholders who may be familiar with large sponsored IDRs that are common among midstream MLPs.

Now I'd like to turn it over to Davis for a look at our financials.

Thanks, Bob, and good morning, everyone. Just a reminder that because we completed our IPO in early February, we do not yet have a meaningful quarter-to-quarter comparison of financial results, we'll have more apples-to-apples comparisons for the third quarter, however.

Second quarter net income was $251,651 on revenues of $7.8 million. On an EPS basis, we earned $0.02 per unit for the latest quarter and operating income was $434,626. Net income and operating income in the second quarter were impacted both by lower commodity prices and a G&A expense that was slightly higher than expected as a result of nonrecurring professional and fees we incurred during the period. Absent additional and currently unanticipated onetime events, we expect over time that G&A expense will level off at a run rate below what it was in Q2.

Adjusted EBITDA was $4.7 million. Our adjusted EBITDA calculation is simply net income plus DD&A and interest expense added back. We define cash available for distribution as adjusted EBITDA less cash needed for debt service and other contractual obligations, and fixed charges and reserves for future operating expenses or capital needs. You will find a reconciliation of this at the end of our news release.

Our average realized price per BOE was $27.78 per barrel, down 2.4% from Q1. That includes $45.10 per barrel for crude oil, down 5.7% from Q1, $2.89 for natural gas, up 12.5% from Q1 and $20.83 per barrel of NGLs, down 11.2% from Q1. We have not hedged any of our production at this point. If our leverage position gets to 1.5 or 2x EBITDA or if current prices start approaching $60 a barrel, we would very likely consider it. But right now we don't see a lot of benefit in hedging.

As we footnoted in Q1, last quarter we received an exemption from the SEC regarding a potential full cost ceiling test impairment. We have not had to take this impairment in the first or second quarters, but we have to reevaluate it every quarter. If we were to take the impairment in future periods, I want to be very clear that it would be a noncash charge. It would not impact cash flow available for distribution in any way in the future, nor does it affect the partnership's liquidity, asset borrowing base or ability to grow through acquisitions or dropdowns.

As of June 30, we had cash on hand of $5.8 million, $18.3 million outstanding on our revolving credit facility, primarily related to the Maxus acquisition. That gives us total liquidity of $82 million if we exercise the accordion feature that doubles our revolver to $100 million.

Earlier this month, our bank group reaffirmed our $100 million revolving credit facility. An accordion is part of a semi-annual redetermination. We plan to use the revolver to provide short-term financing for acquisitions, and our goal is to maintain a conservative capital structure. Following the closing of the Maxus acquisition, our ratio is now about 1.0x debt to EBITDA. So we are very comfortable with our conservative balance sheet and we intend to keep it that way.

As Bob referred to earlier, our coverage ratio from operating revenues for the second quarter distribution was about 0.93x, which means actual DCF from operations was $0.28 per unit. The additional $0.02 per unit that the board approved in total distribution represents excess working capital generated mainly from positive prior period adjustments from our operators that we received.

Operator, we are now ready for questions.

(Operator Instructions) Our first question comes from the line of Matt Schmid with Stephens.

I appreciate the color Davis provided on the G&A and the nonrecurring nature of some of those costs in the second quarter. Just thinking about the rest of the year, should we go towards I think that $1.6 million was provided in the S1? Or is the run rate, do you think it might be a little bit elevated beyond that?

Our hope is that on a normalized basis -- our intent is that on a normalized basis we'd hit that number. We put a lot of thought into that in our guidance. I would say that, that -- it may take a quarter or 2 for us to get down to that. We've been a little bit surprised, as most companies are, when they go public by random nonrecurring costs that come up in the first couple of quarters. So maybe, Matt, I would think about kind of working toward that number over a quarter or 2. Bob, do you have anything to add to that?

No. I'd agree with that, Matt.

Yes.

Okay. That's helpful. And just thinking about the acquisition opportunities out there, obviously, as Bob mentioned, Permian's still very hot. What, just generally, are you all seeing out there in other basins? Are there any more looking a little bit relatively more attractive? Or just generally has there been any recent changes sort of in the competitive environment out there?

Yes, great question, Matt. I think I said last quarter that we have seen more deal flow than in any time in our 20-year history and that's actually even accelerated. So our deal sheet has over 20 deals on it currently. And to your question about where, it's every basin. So we look at all deals. That's just what we do. And we've been very active looking at it. So we've been very busy this quarter. What we found is, is that we have not lost deals because somebody has outbid us on properties that we really like. What we found is that this quarter because of lower prices, there's been a bid-ask spread. And so we hope we'll have another bite at the apple because some of the properties we looked at did not sell because the seller was expecting a higher price. So I would say not any more competitive, tremendous amount of deal flow. And we hope as prices kind of firm up in the next quarter that we'll be able to announce some good news.

Yes. And Matt, I'd just add to that. This is Davis. For -- we obviously like to buy properties that have existing production. We think on a risk-adjusted basis, that's just a better way to invest in the royalty business. We've seen that no matter what happens, frankly, in movements in oil and gas prices, it seems like nonproducing acreage, particularly in the Delaware and Midland basins, the price stays the same, which doesn't really make sense to us. But on the producing mineral side, people saw a dramatic drop in oil prices from kind of early Q1 to Q2, and that's caused people to get a little bit squeamish, in our opinion, and perhaps hope to hold onto the asset and sell at higher prices. Given what we've seen in recent weeks and what appears to be some positive momentum behind hydrocarbon pricing, we would expect that in the next couple quarters A&D activity would pick up. I'd even go so far as to say we'd be surprised if it did not.

I agree with that.

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

Just a couple questions related to our kind of production guidance. I know that last quarter you mentioned, Bob, that even though you've had the huge increase in the rig count to start the year, that you typically have kind of that 3- to 6-month lag before it really kind of shows up on you all's end. I'm just wondering now that we're kind of a little bit further now down the road, the rig count's held in there steady despite the oil price kind of bumping around, if you've got any more kind of visibility into the back half where you might have some confidence to potentially raise that.

Yes, John, great question. And it's always frustrating from a mineral owner standpoint and how long it takes operators to put us into pay status. And frankly, it seems like every year that goes by it takes longer and longer for operators to do that. That being said, we don't want to overstate our expectation on production guidance. But just purely from a logical standpoint, it's impossible to us that our rig activity has gone up 50% from year-end and that, that wouldn't translate to increased production volumes at some point in the second half of this year. So operators, they have legally, in some cases, up to 1 year to put us into pay status. Usually it doesn't take that long. But to answer your question in a general way without providing specifics, yes, we would be surprised if our production volumes did not start to reflect that increase in rig activity in the next couple of quarters.

I appreciate that color. And then just kind of a related question, the original production guidance, was it kind of about a 38% oil mix? And so as I try to think about kind of the tug of war between the biggest increase you saw in terms of activity to start the year was in the Permian. But then we also have to factor in the Maxus Energy acquisition, which was obviously predominantly a lot more gas weighted kind of how to think about that oil mix as we go through the second half of the year.

Good question. I would argue that the Permian -- given that a couple of rigs came off Terryville, which is our largest single contributor to gas revenue and 2 rigs were added to Permian, I would expect to see a higher oil mix going forward, John, if that makes sense. And I guess that's all I'd say.

Yes.

I would expect to see that, yes.

Our next question comes the line of T.J. Schultz with RBC Capital Markets.

Just one question. I know this isn't really the business you're in. But the valuations you're seeing out in the Delaware are so high, is there any thought on selling some of those minerals under those valuations and redeploying into some other opportunities? Or are there restrictions there to do that? Or do you just sit with what you've got in the Delaware, given that's the area where drilling is occurring?

T.J., it's funny you asked that question. We've been talking about that recently. I mean, in particular, we think that we're not getting full credit. And I said we've been making this argument since we went public. We don't feel we're getting full credit for the acreage position that we have. I mean, if you just look at the number of net mineral acres we have in the Permian Basin and apply even a very conservative multiple of what you're seeing in the market today, it implies a market cap for our company that's well in excess of what it is today. We are looking at opportunities like that. I mean, we get calls daily trying to buy our minerals and particularly in the Delaware Basin, but also the Midland Basin and other places, but primarily Delaware today. That's something that we'll probably start to focus on a little bit more in the next kind of 3 to 6 months. I mean, our view is, even if it's a great section that we have an interest in, in the Delaware Basin, the problem is that it could take 5 to 10 years for that asset to be drilled, if ever. And so from a present value of money standpoint, it may make sense for us to start to sell some of those assets into what we believe is a bubble and then, to your point, redeploy that at rates of return in producing assets elsewhere that are massively accretive to our company like Maxus. So that is something we're thinking about. And maybe this question will help catalyze us to focus on it a little bit more.

Yes, we're definitely open to that. I second what Davis said.

Our next question is from Brian Brungardt with Stifel.

Just maybe expand on John's earlier question and appreciate the commentary on the rigs moving around, but just wondering if you can provide some color regarding wells turned in line during the quarter maybe relative to first quarter.

We haven't done that yet. It is very time-consuming task, obviously, just given the scope of our -- the large scope of our portfolio. But that's something that we will probably start providing in the future. Great, great point. And that -- I think that would allow you guys to get a better handle on where activity is really picking up. So we'll get back to you on that point, Brian.

In general, 3 areas kind of stand out and we'll do specifically one obviously in the Terryville field, some new wells, even though we said 2 rigs moved to adjacent sections, we did have new wells come online. I would also say in the Delaware Basin and in the Permian, we had new wells come on, and then in the Bakken. So we did see new wells in all 3, and we'll provide…

And in the Eagle Ford.

And Eagle Ford, too, yes.

So yes. But Brian, that's a good point. It takes a lot of time to kind of compile that data, just given that we've got 45,000 wells. But yes, that's something that we intend to start providing on, hopefully, on a quarterly basis going forward, so…

Well, it's a good problem to have, I guess. Maybe coming at it a little bit differently. Do you guys have any color as far as maybe where permits stand relative to maybe in May? And also, just kind of as we're thinking about it, based on where you're seeing rig activity, do you see a material change as far as what the average mineral interests are where activity is focused?

I'd hesitate to provide color on permits. That’s even -- that takes even more time for us than actual wells coming online. We can certainly take a look at that, Brian. I mean we'd love to have that information even for our own internal purposes and are happy to provide that. In terms of, if I'm understanding your second question correctly, we have not done an analysis yet to kind of see which rigs are on properties where we have a greater net revenue interest, so to speak. But that is also an exercise that we should do, and we're happy to do that and happy to provide some additional color to the market on that.

There are no further questions. That does conclude our question-and-answer session. At this time, I'll turn it back to your Chairman and CEO, Bob Ravnaas, for closing comments.

Thank you. And thank you all for joining us this morning. That completes today's call.

This concludes today's conference. Thank you for your participation. You may disconnect your lines at this time.