Ladies and gentlemen, thank you for standing by, and welcome to the Second Quarter Fiscal Year 2020 NGL Energy Partners LP Earnings Conference Call. [Operator Instructions] As a reminder, today's program is being recorded. I would now like to introduce your host for today's program, Trey Karlovich, Chief Financial Officer. Please go ahead, sir.

Great. Thank you, and welcome, everybody. As a reminder, this conference call includes forward-looking statements and information. Words such as anticipate, project, expect, plan, goal, forecast, intend, could, believe, may and similar expressions and statements are intended to identify forward-looking statements. While NGL Energy Partners believes that its expectations are based on reasonable assumptions, there can be no assurance that such expectations will prove to be correct. A number of factors could cause actual results to differ materially from the projections, anticipated results or other expectations included in the forward-looking statements. These factors include prices and market demand for natural gas; natural gas liquids; refined products and crude oil; level of production of crude oil; natural gas liquids and natural gas; the effect of weather conditions on demand for oil, natural gas and natural gas liquids; and the ability to successfully identify and consummate growth opportunities and strategic acquisitions at costs that are accretive to financial results and to successfully integrate and operate assets and businesses that are built or acquired. Other factors that could impact these forward-looking statements are described in risk factors in the partnership's annual report on Form 10-K, quarterly reports on Form 10-Q and in public filings and press releases. NGL Energy Partners undertakes no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. This conference call also includes certain non-GAAP measures, namely EBITDA, adjusted EBITDA and distributable cash flow, which management believes are useful in evaluating our financial results. Please see the partnership's earnings releases, investor presentations and annual and quarterly reports on Form 10-K and Form 10-Q on our website at www.nglenergypartners.com under the Investor Relations tab for more information on our use of non-GAAP measures as well as reconciliations of differences between any non-GAAP measures discussed on this conference call to the most directly comparable GAAP financial measures. We have on the call with us today our CEO, Mr. Mike Krimbill; as well as our Executive Vice President of Water Solutions, Doug White. I will now turn the call over to Mike for his prepared remarks.

Great. Thank you, Trey. And Doug, jump in whenever you think appropriate. This has been an incredible quarter of significant achievements for NGL. We closed the Mesquite acquisition, the largest water solutions company in the Delaware, with capacity of 1 million barrels per day disposal, 95% piped and long-term contracts with large producers. Then we signed the Hillstone [ TSA ], which has one of the best producer contract profiles, MVCs 10- to 20-year acreage dedications with large credit-worthy producers. And next, we closed on the sale of our Refined Products business, reducing indebtedness by $300 million. For those of you who look in the rearview mirror to make investment decisions, in the last 20, 24 months, we have sold assets for approximately $2.1 billion while retaining Grand Mesa, of course, and purchased assets for approximately $1.5 billion, math that would lead one to believe that EBITDA would have declined. But no, EBITDA has actually increased over 50% from about $380 million to nearly $600 million. So what have we accomplished? The business has become more simplified and focused with 3 segments versus 5. The 3 businesses are much less volatile with the sale of Refined Products and less seasonal with the sale of Retail Propane. Crude and NGL Logistics are repeatable, predictable cash flow streams; Water Solutions, less so currently as a result of significant growth going forward. We have reduced total leverage by nearly 2 turns already and have a couple hundred million dollars of working capital debt to eliminate by 12/31. We have established the largest water system in the U.S. with nearly 3 million barrels a day of disposable capacity and many hundreds of miles of pipelines. More importantly, we invested in the Delaware Basin with the highest rates of return for producers, meaning less commodity…

Okay. Great. Thanks, Mike. After that, there are quite a few things to cover from a financial perspective for the quarter as well as updates on the recent closing of the Hillstone. First, for the transactions included in the quarter. As Mike mentioned, we closed Mesquite on July 2, and we closed the Refined Products TPSL on September 30. So both transactions are reflected in our quarterly results. The sale of TPSL is included in discontinued operations in our September 30 financial statements, and prior periods have been adjusted accordingly. This should allow investors to understand the impact this business has had on our historical results. These results are no longer included in our covenant calculations, which is consistent with the treatment of the Retail Propane segment we sold last year. The proceeds from the TPSL sale were used to repay borrowings on the revolving credit facility and delever the business by approximately half a turn in total. Pro forma for the Mesquite acquisition and the TPSL sale as well as growth CapEx invested year-to-date, our LTM pro forma adjusted EBITDA at 9/30/2019 is approximately $575 million, as calculated for our debt covenant compliance purposes, compared to a total debt balance of approximately $2.8 billion, which resulted in total leverage of approximately 4.8x, which is a reduction of about 0.4 turns from the June 30, 2019 period. With the recent change in our business strategy and the reduction in working capital needs with the TPSL sale and the expected further wind-down of certain remaining Refined Products businesses, we have reallocated our revolving credit facility and adjusted our covenants to be more in line with market. We are now governed by a total leverage covenant which will include working capital borrowings going forward and is currently subject to a 5.75x limit…

[Operator Instructions] Our first question comes from the line of T.J. Schultz from RBC Capital Markets.

Maybe for Doug. What percent of the expected Delaware volumes by the end of next year will be on contract or part of an acreage dedication and what percent supported by MVCs?

T.J., thank you. Right now, I believe we're somewhere close to 70% of all either acreage dedicated or MVCs in the Delaware. That really is pretty in line with the percentage of our piped water also. Really, our truck water is the undedicated portion of our portfolio in the Delaware. As we continue to bring on more facilities and then, also, we see the Poker Lake contract ramp next year, we'll see that 70% pushing more towards the 80%, 85%. On an MVC basis -- I would say on an MVC basis in the Delaware, of that 70% of committed, 30% of that is MVC.

Okay. And then maybe a question on recycling more high level. You've indicated building these ponds. So what recycling now is done via some of these mobile units? And how does that evolve? Or is that evolving to something different more quickly that would utilize these ponds and pipes? Just trying to understand the opportunity that sits there for you all as you look to contract that recycling business.

Sure. The mobile units are more focused on, on-the-fly or lower volume production. With our long history of recycling and treating, we've been down that road and considered them -- we didn't see it as an answer for anything we could scale. That's why we do not focus on those. Because we have such a large pipeline system in place now, we're able to strategically place very low-CapEx pits and recycle equipment that is really centralized but not on a big plant basis, more of a central facility with equipment and pits that store the water. Our interconnect to our produced water system is where we receive the produced water to treat. Our average facility can treat 50,000 barrels per day, scalable for -- to 100,000 barrels per day for not a lot more CapEx. And our goal is to -- and what we've already entered into, we have a 10-year acreage dedication on our first facility on our McCloy Ranch. We're delivering that water to the acre dedication, but then that has opened up opportunities for us into other dedications or other contracts within an 8- to 10-mile radius of that facility, all delivered by pipe as well.

Okay, great. That's helpful. Just lastly, Mike or Trey, the implied valuation on the GP and in some recent transactions that were disclosed imply a plan that, I would think, to grow the distribution over the next few years. But how do you view distribution growth versus buybacks just given where the stock is trading right now?

We think, number one, we'd probably end up in the midstream space where everyone eliminates their IDRs. So when do you do it? How do you make it, say, fair to a GP owner but very attractive to the partnership? So when we look at our next few years' projections and we look at more of what the DCF per unit, it's clear that we're not going to raise the distribution if we're trading at 12% or 13% where we currently are. We think it's very attractive to buy GP interest back today. And it ultimately would become a multiple below, say, the current market, where we're seeing, whatever, 9x to 15x. I don't know if that answers the question. Trey, do you have a...

Just to add, T.J., obviously, we're not making decisions in a box. We're obviously looking at the market, looking at what our expectations are for where the units will trade to determine whether we're buying back units or increasing distributions in the future. Obviously, the way that we look at running our business and generating excess cash flow supports distribution growth. But obviously, that decision is not going to be made if you're trading at a 13%, 14% yield. At that point in time, you would devote those funds to buying back units, which again, may not support a GP -- a higher GP valuation because you don't have the increase in distributions. But that's what is implied in our overall evaluation of how we look at the business on a longer-term basis. So hopefully, that helps. Again, I think that at the current unit price level, raising the distribution, we would most likely be buying back units rather than doing that. We don't expect the units to stay at this level. Again, it's -- as it's proven out that our distribution is predictable, steady, coverage increases and leverage continues to decrease and hits our target levels, we wouldn't expect to trade at this level. But again, the market is -- the market -- we'll have to make that decision at the time.

Our next question comes from the line of Justin Jenkins from Raymond James.

I guess, first, on the exit rate for the year for the water volumes, that's fiscal year and not calendar year. Is that right?

That's correct, Justin.

Okay. And then you mentioned, Trey, that the 5 months of contribution from Hillstone in the updated guidance. Can you give us a better sense of potential financial contribution in the early stage of the year. And I guess, secondarily, has the outlook changed at all for those assets given what we're seeing with operator activity levels heading into calendar 2020.

There has been no change to our expectations on the Hillstone assets. Again, we closed that business a week ago. The largest dedication is the 20-year Poker Lake dedication. That development comes online a year from now. Between now and then, our expectation is that the Hillstone EBITDA contribution essentially offsets the -- is not accretive or dilutive. It offsets the financing costs of the business. That business is financed with $200 million of [ 90% ] preferred. The remainder is financed with debt. Doing the simple math, that's around $50 million of contribution for the first year. That's how -- there's a ramp in those volumes over time, but that's the contribution that we're assuming in our fiscal guidance.

Got it. That's helpful. And last one for me, if I could. Just how we should think about maintenance CapEx now that the water business is a meaningfully larger portion on a go-forward basis.

Sure. So our maintenance CapEx, obviously, has increased as we have grown the water business. There is more infrastructure, more assets. You have regular maintenance on your pumps and your facilities. We'll continue to have a regular maintenance plan. The maintenance capital will be more tied to volumes as well. So as volumes increase, we would expect maintenance capital to also increase. We've moved our maintenance capital numbers up for this year, we're still in line with that expectation. It was a range from $50 million to $60 million. I would expect next year's maintenance capital numbers to be slightly higher. But again, I don't think it's going to be significant.

Our next question comes from the line of Shneur Gershuni from UBS.

Mike, thank you for the title reference in the prepared remarks. Just to start off, you guys have made a lot of progress on leverage over the last couple of years. And then you sort of turned around and did this acquisition this most recent quarter. When I think about the backdrop of where the rig count is, producer expectations and so forth, at what point do you take a pause in sort of -- produce where you were at and sort of focus on letting the earnings catch up to where your leverage actually is at this stage?

I'll start, Shneur, then Mike can chime in. As Mike mentioned, we've reduced leverage by 2 turns over the past 2 years. We've completed these acquisitions with a significant amount of preferred equity. So we've raised $600 million of preferred Class Bs. We also issued another $100 million of preferred Class B. So approximately half of these transactions was financed with preferred. I think what's lost in some of the translation is the amount of debt that's coming off related to the TPSL sale as well as the wind-down of remaining Refined Products. That's going to be $500 million. So from our perspective, we have continued to reduce leverage. Our overall target is lower than where our current leverage is because we do -- we will grow into these 2 acquisitions. The volumes are expected to ramp. But these are 2 significant transactions that we have actually been discussing for about a year now. These are assets that we identified in our evaluation of the basin that we thought were core to the further development of the basin. They're underpinned by long-term contracts with the best producers in the basin as well. So we do feel confident in the assets that have been acquired. The question to what's next, Mike mentioned, our continuing growth capital will be focused on tying these assets together via pipeline, expanding pipeline capacity where necessary. We have 2.8 million barrels a day of disposal capacity in the basin. So over the next 12 to 18 months, we should see higher utilization of that capacity and a reduction in growth capital, and there's not any significant M&A that we're evaluating at this point in time. Mike, if you want to add anything more to that.

Yes. It's wonderful to think you can just say, "I'm going to put a business on pause, and I'm not going to lose any competitive advantage," but that's not the way it works. You have to be -- in this basin, there was a shortage of disposal capacity in New Mexico, so producers were signing contracts to make sure they could get rid of their water. Those producers are larger independents and majors, but there's a limited number. So we have to get as many contracts as we can for the future growth and the health of the business. So in the basin, you had us -- ourselves, Mesquite, Hillstone, OWL and Solaris. That was it, really, the large systems, that we felt the 2 best were Mesquite and [Audio Gap] for their physical assets but also their contract profiles. As you know, OWL went to Instar, and Solaris is doing whatever they're doing today. So we just had to purchase these 2 businesses, and leverage will increase somewhat, but it assures our business really of being the franchise in the Delaware. So now what's left? Well, there's really nothing left. So the -- there may be a few producer systems out there that may come up for sale. But otherwise, there's -- all the systems are divvied up and the producers are pretty much divvied up.

So by getting Hillstone and Mesquite that I think we're at the point now where we're just waiting for the water to flow to us, and there's nothing, any kind of large- or medium-scale acquisition, to be done.

Okay. So to paraphrase, you're mostly done with acquisitions, and we can sort of expect the operating leverage of everything you put into place where you just have the connection to capital going forward, and we should see a faster clip or faster growth rate from an EBITDA perspective on a go-forward basis. Does that encapsulate what you're basically saying?

Yes. And that we've tried to say that as well as with SWDs next year and the year after being in this 10 to 20. As you know, the ones in -- on the Texas side, they're $1.5 million to $2 million each. So there's -- we spent the capital, but it's because we expect the water here. We're seeing it already in November ramp up. But yes. So I think now it's just that we're going to see the growth in the water EBITDA and leverage should decline and will decline over time.

Okay. One of your peers reported this week and had some really strong water results. Should we expect similar performance in terms of what Rattler posted earlier this week? Do you have like some similar metrics to them and so forth? Or are there differences based on where you are and where they are and so forth?

Do you have a response to that...

So actually, Shneur, Rattler's tied specifically to their parent, one primary producer. They are not in the exact same area that we are in the basin. We -- I don't think it should be lost that we have seen growth in our volumes over the past quarter. It may not be as significant as we had originally thought in the first part of the year or as the market had anticipated. But it has continued to grow, and we're seeing that growth through October and November as well. So I think if you look at our system and you understand the producers that are behind that system, you can see that their rig counts are not really falling -- either staying steady or even increasing, and their volume expectations are increasing through the remainder of not just this calendar year but next calendar year as well. So I think that's the read-through and where you should be focused from an NGL perspective.

Our next question comes from the line of James Spicer from TD Securities. James Spicer;TD Securities Inc.: Trey, you mentioned an additional $200 million to $250 million reduction in working capital borrowings. Given that the TPSL sale was closed, can you just clarify exactly what's driving that? And then how much in total is going to be drawn on the credit facility pro forma for all these transactions?

Sure, James. So our total -- when you look at our total borrowings at the end of June, it was about $900 million. That was about $600 million of Refined Products and about $300 million of crude and Liquids. At September 30, we sold TPSL. Working capital came down about $250 million in total. Again, the TPSL sale is $300 million, offset by a slight increase in our Liquids that's seasonal. But the $600 million of Refined Products working capital was only reduced in half. The remaining businesses were utilizing that 300 -- approximately $300 million of working capital and generating a very small amount of EBITDA. So we are in the process of winding those businesses down or looking for other opportunities associated with those business and we expect that to be completed by the end of this quarter, which would be December 31. Our estimate right now, that's another $200 million to $250 million reduction in borrowings under the working capital facility. The way we allocated our credit facilities, we have about $1.2 billion available on the expansion facility, $600 million available on the working capital facility. We would expect that working capital facility to be in the $400 million range from an outstanding perspective. And that would cover Crude Logistics; NGLs, which at December 31 will still have a fairly significant inventory position for propane as we move through the heating season; and then what is remaining in our Refined Products business, which is primarily the rack marketing and a small piece of renewables business. James Spicer;TD Securities Inc.: Okay, great. That's helpful. And then just on CapEx for next year, I understand this is primarily connection, capital and tying things together. But can you just directionally provide a little guidance relative to the $230 million to $330 million his year?

So right now, we are looking at growing capital in total across all of our businesses of probably $200 million to $250 million range. At this point in time, that would include no M&A activity. And I think that's a reasonable number at this point. Now it's primarily the water infrastructure, and then as Mike mentioned, you've got key disposal wells that you would add as needed through the year.

Our next question comes from the line of Pearce Hammond from Simmons Energy.

I know this has already been kind of addressed in the Q&A. But I was just curious, what attracted you to the Hillstone assets? Is there like 1 or 2 attributes that you can maybe point out about those assets that attracted you, especially relative to the other water-related businesses that had been up for sale?

That was an easy one. Their contract profile, the contract they have on Poker Lake, in particular, very attractive. We're not able to tell you who the customers are because of the CAs in these contracts. So it's hard for you to necessarily confirm. But with the contract profile, they had 19 wells drilled. We can drill wells and get permits easily, too. So that's not a big deal. But certainly, the contracts. And it's difficult, I think, for analysts -- and you know this better than most -- you can look at the rig count in the U.S., you can look at the oil rig count in the U.S. That doesn't matter. You can look at the oil rig count in the Permian. Okay, that really doesn't matter. You've got some of the companies going bankrupt, others dropping rigs, [ matters into that account ]. The only way you can really evaluate us is to look at the rig count for our producers, and we're not allowed to tell you all the producers. So we -- it's very frustrating when these analysts come out and say, oh, they have a rig count -- this, this, this. That's nonsense. They don't -- no one knows except us what that rig count is, and we can't say anything. But the contracts are key. Poker Laker is one of the most attractive contracts in the company.

Great. And then as a follow-up to that, because you look at other water companies, not your own but other ones. Do you think that there is the chance that they might be facing some pricing-related issues from a competitive standpoint, maybe an oversupply of systems that are getting built out there? Just any thoughts on that?

I think that, generally, it would be true that contracts that were signed, let's say, 5 years ago, are probably at a higher rate than contracts being signed today. As in any business, as you get more competitors, the fees come down. So I think anyone who has contracts from some period of time in history, as they come up for renewal, there will probably be some pressure on price.

Our next question comes from the line of Sunil Sibal from Seaport Global Securities.

A couple of questions from me. So starting out with the customers, realized that you can't talk about specific customers, et cetera. But I was wondering if you could categorize your customers, especially in the water business as large integrated energy companies versus independent E&Ps or by customer credit quality.

Yes. Sunil, our largest customers are going to be large integrated or very, very large independents, all investment-grade or higher rated. I think that would cover the majority of our customers and the volumes that we're receiving. Obviously, we have a very large system. So we do have customers of all credit qualities, but the contracts that are anchoring the systems, the MVCs that we have, the large acreage dedications, those are all from extremely high credit quality customers.

Yes. I mean, clearly, we want all the producers to be successful. So if we have a line running by a smaller producer, we're very excited to have them connect to our system. I think we all are looking at the smaller guys with -- are they more likely to have financial issues, drop rigs? So you really want to base your business on the larger producers that are going to drill through any downturn. With that said, the smaller guys will eventually, I think, be purchased by the larger guys. So we don't want to ignore the smaller guys. We want to help them as much as we can. And then if they end up becoming part of the larger group that we have to do business with, we'll already have their water, and it will be additive to instead of having a portion of our larger customers' water going somewhere else.

Okay. Just to put a little bit of quantification around that. So when you say a large majority, would it be fair to say it's more than 80%, 85%?

Yes. I'm sorry, you have to go by shale play. So if you're talking about the Permian, if you're looking at the Delaware Basin, yes. When you look at the DJ, the Eagle Ford, the Midland Basin, no, it would be a smaller number, Sunil. But the core basin and particularly the assets that we acquired, I think that's at -- around 80% is probably a reasonable number.

Got it. And then just on the leverage question, I think you had set a 3.25x kind of a leverage metric for the business some time back. And I realized there have been some changes around the working capital, how that working capital is broken down, et cetera. So I was just kind of curious, is 3.25 still the kind of the number that you are targeting? And if so, seems like you indicated you will hit 4x or so sometime in the next year. When do we -- when can we expect to get to that 3.25x?

Right. So the 3.25x, adding -- that metric excluded working capital. And if you look at where our working capital was 3 months ago, it was up $900 million. That's 1.5 turns. So if you took the 3.25 and you add 1.5, you're at 4.75x, would have been the target at that point in time. We have actually -- for a total leverage comparison. We have actually lowered that target. We're right at that target today. We're at 4.8x. But we have reduced our working capital. We're continuing to reduce working capital, continuing to eliminate the business -- the primary use of that working capital. However, we will still have a little bit under a turn of working capital. As I indicated earlier, about $400 million, so call that 0.6, 0.7 turns. So we've really -- the 3.25 hasn't changed. It's just been adjusted for how the business is now structured and how we -- how the working capital will be impacted for the business. So we've really taken the 3.25 from a compliance basis, which excluded working capital of 4x, including the remaining working capital. So we really have not changed that target. And we're expecting to be there in about a year once we see the ramp-up of volumes on Hillstone and Mesquite and, again, the elimination of the remaining working capital-intensive businesses associated with Refined Products.

Our next question comes from the line of Spiro Dounis from Crédit Suisse.

Two quick ones. Just on drilling SWDs next year, it seems like there's actually considerable headroom just with your current injection capacity and relative to where your run rate is. So just curious why you think there's a need to drill that many overall. And then just on that 20-or-so figure that you are drilling, should we expect that's something that probably declines at least in the following year?

I can take that, Mike.

Yes.

This is Doug. We are running a lot of pipe, large diameter, to move the water from New Mexico to our existing capacities into Texas. Our New Mexico capacities, we only have -- we only drilled 7 Devonians, inherited 17 Devonians from Mesquite. Those are in field. Those are staying very full. When we engaged our 3 new customers in the Hillstone acquisition, all 3 of them told us they are outpacing their forecast, and they have come and asked us for additional firm capacity above and beyond what was contracted. That basis is where we're coming up with the additional wells to be drilled. That's particularly in Loving County, where the demand on the Hillstone system is. And to answer your second part of your question, our expectation would then be to only be drilling additional wells in the future based on additional forecast or contract -- new contracts. But we are continuing to see the forecast of the magnitude of water under our contracts continue to increase. That's what would drive, obviously, additional investment in new wells.

Got it. I appreciate that color, Doug. Second one, Mike, this one might fall into the fake news category, but there's been some expanded discussions just around risk to drilling on federal lands depending on the results of the next election. So it sounds like maybe there could be some impact in the New Mex area. Just wondering what your thoughts are around risk there and how you'd expect New Mexico to react just given how vital energy is now?

Yes, that is fake news. Thank you. And we've already been through this once in Colorado with a setback. So we have opinions, but those really don't matter. So we engaged a law firm in the Southwest that was an expert in this area. They have provided us an opinion, which took 10 days or so, so it wasn't -- it was well thought out. What really can -- an executive -- can someone really shut us down and they're going to shut down the producers in the next executive order, assuming it doesn't -- it's not something you can get through the Senate and the House. Their opinion was that the -- a Democratic president cannot shutdown fracking on BLM land. So then we said, okay, what happened in Colorado? There was a rush to the -- by the producers to get as many additional drilling permits approved as possible. So they would have a large inventory, obviously, in case [ the setback passed ]. That is not happening in New Mexico. There's not a rush on the drilling permit folks to grant thousands and thousands of new permits. So that's an indication that I think of what the producers are thinking. So we don't believe a change in administration could shut down fracking on the BLM lands. Currently, we have some production in -- it's predominantly in New Mexico that we're on -- our producers are on BLM. We tried to figure out how much water is coming off of those lands, but there's no way for us to know. The advantage, obviously, of what we do is all the water is on pipe. But when water is on pipe, you don't know what mixes it came from. So there's no way for us to determine how much of our New Mexico water is coming off of BLM land. But we do think that's fake news. Unfortunately, investors who don't know any better may react to their detriment. But we saw the same thing happen in the DJ. At the end of the day, in the DJ, we had our biggest water customer come to us and ask for a 15-year contract. So quite a bit different than the fake news that came out about the setback proposal.

Our next question comes from the line of [ Mike Murray ], private investor.

My questions has been answered.

This does conclude the question-and-answer session then. And I'd now like to hand the program back to Mike Krimbill for any further remarks.

Again, I have many thoughts, but I think I'll keep them to myself. So thank you, and we'll see you next quarter.

Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.