Good day, ladies and gentlemen, and welcome to the NGL Energy Partners Q3 2017 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions] As a reminder, today's conference call is being recorded. I would now like to turn the conference over to Chief Executive Officer, Mike Krimbill, and Chief Financial Officer, Trey Karlovich. Please go ahead.

Thank you, Candice. This is Trey. Good morning and welcome. This conference call includes forward-looking statements and information. 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 and crude oil; level of production of crude oil 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 strategic acquisitions at purchase prices that are accretive to financial results and to successfully integrate acquired assets and businesses. 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 other 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. Please also see the Partnership's Web-site at www.nglenergypartners.com under Investor Relations for reconciliations of differences between any non-GAAP measures discussed on this conference call to the most directly comparable GAAP financial measures. At this time, I will turn the call over to Mike Krimbill for opening remarks.

Thank you, Trey. Good morning and thanks for joining us today. First, I would like to say, the theme at NGL is, nothing has changed. The sector has emerged from the recent challenges and there are significant upside to our business. Obsessing over a quarter's numbers rather than the next three to four years' projected EBITDA just doesn't make any sense. With respect to distribution guidance, we continue to expect the 20% increase in our distribution over the next four quarters and 10% annually thereafter for the next three years. On Grand Mesa, we began shipping in November as you know. We had one committed producer that was having some difficulties. The situation with that producer has been clarified. We began receiving 100% of that producer's production volumes January 1 and we have agreed upon a term sheet for the next 7 to 12 years. We are also picking up additional volumes from non-committed producers in the northern portion of the DJ. The DJ rig count is up significantly, which will bring us increased volumes and wider spreads as fiscal 2018 progresses. We purchased the Murphy Energy assets in January for approximately $50 million, at a 5x multiple. We are integrating those currently, bringing back former customers that have left because of Murphy's financial situation, and then evaluating an expansion of the Kingfisher assets. The STACK extension was announced and will be completed this calendar year. This provides NGL the presence in two of the three highest-rated return basins, the DJ and the STACK. We are currently looking at the Permian like many others to find an opportunity that doesn't come at a 12 to 20 multiple. In short, the future is very bright. We're at the bottom of this current cycle. There is significant upside to our water disposal business and crude logistics with the increased rig count in the DJ and Permian which we're all seeing, and to a lesser extent in other basins such as the Eagle Ford. We have transitioned NGL into a higher fee-based repeatable business model with our recent organic projects. Our balance sheet is much stronger and common unit coverage high. And with that, I would like to turn it back to Trey for his comments.

All right, thanks Mike. I appreciate everybody who joined us this morning. I'll be going over our financial results for the third quarter, which we released this morning, as well as some of our thoughts about the rest of this fiscal year and beyond. On our last call, we discussed the notes offering which we closed in October and is now reflected in the financial statements. This offering was significant in that it allowed us to balance out our secured and unsecured borrowings and increase our liquidity. It also extended the debt maturities to November of 2023. Since then, we have seen a new President elected, an agreement by OPEC to limit production, an increase in the stock market and interest rates, as well as dare I say some stability in oil price although the past couple of days may not reflect that. We have also announced the Murphy and STACK projects, as Mike discussed, and have some resolution on the Grand Mesa producers, and gave our distribution guidance in the middle of January. As a result, the notes that we issued in October are trading well above par, which is great to see, and we continue to be pleased with the transaction and the continued transformation of our balance sheet. As we have discussed over the past several months, our financing strategy has been to reduce our committed capital requirements, decrease our leverage, increase liquidity, and improve access to capital markets, all of which we have achieved. This continues to be our focus as well as extending debt maturities and balancing the financing of our capital expenditures going forward. Happy to announce that we have launched an amendment and extension to our credit facility and we hope to have that completed in the short term. We expect to continue…

[Operator Instructions] Our first question comes from Robert Balsamo of FBR. Your line is now open.

A quick clarification, I think you just mentioned next year your expectations for coverage for fiscal 2018, did you say 1.6x? I know the 1.3x to 1.5x I guess over the longer term.

Our target range is 1.3x to 1.5x. We expect next year's coverage to be closer to 1.6x.

Great. And could you talk a little bit about the range? I mean the guidance last quarter I know was unofficial was 2018. Could you just talk a little bit about that? You were saying over $600 million. It sounds like that would roughly still be in line given that coverage number, but could you maybe just speak to that again?

Sure. We have no change to that at this point in time. We are working on our, finalizing our budgets for next fiscal year and updating our forecasts thereafter. We do not expect it to be any significantly different and we will give robust EBITDA guidance by business in our next quarterly call.

And just to clarify, some of the acquisitions were announced after last quarter's guidance. So that now be including kind of these acquisitions, maybe offsetting some of the weakness or is that actually incremental?

The acquisitions should be incremental to what we spoke about last quarter.

Great. Thank you very much.

Our next question comes from Darren Horowitz of Raymond James. Your line is now open.

If I could, I wanted to go back first to the discussion around the purchase of the terminal in Kingfisher County and the opportunities to expand those assets like you referenced. Do you think it's more of a Y-grade opportunity to Conway via Chisholm or maybe some splitter opportunities? If you could just talk also about what you see as incremental CapEx associated with those expansions and where you think expected returns could be, that would be great.

It's more on the Kingfisher, the condensate project perhaps to remove sulfur from the off-spec condensate. In our model, we only assume 1,400 barrels a day of condensate and the splitter will handle 5,000, which probably means we can do 4,000 efficiently. And then on the other side, we assume 4,000 barrels a day of Y-grade, and I believe the capacity is at the moment 7,000. So, I don't have a number on CapEx, but it's not going to be much.

Okay. And then also, Mike, regarding the purchase of the Port Hudson terminal, you outlined the expected EBITDA run rate there. Where do you see more opportunities to drive value? Is there more of a butane blending opportunity or maybe additional downstream opportunities to leverage the purity products?

At the moment, we are supplying butane and naphtha to a single customer who has built storage, or it may be a lease-up storage, on the Colonial pipeline property there. So, I think we're not seeing that we're going to have a big increase in supply, but there may be an opportunity to expand the facility, meaning more storage and then perhaps more blending.

Okay. And then my last question, just more of a clarification, can you guys provide how much storage at this point you've leased to third parties on a fee-based perspective relative to how much you're using for contango storage, just so we have a sense?

On the crude side, we have just under 1 million barrels that we're utilizing for our own usage. The remainder of the capacity is being leased to third parties.

Okay, that's helpful. Thanks, guys.

Our next question comes from Michael Blum of Wells Fargo. Your line is now open.

Can you just talk about I guess a couple of segments I want to talk about? One, in the Water segment, so you kind of referenced the pick-up in drilling activity, but can you just talk about effectively when does that translate into stronger results in that segment? And you also referenced that effectively skim oil was a drag on the business year-over-year. At this point, prices are higher. So at what point, does that kind of become a benefit and not a drag?

I'll start with the volume. So what we're seeing, there is a lag still in the rig count increases in an area such as the Eagle Ford where we have excess capacity, we see that benefit immediately. But the majority of the increase is happening in the DJ and more so in the Permian and the Delaware side. So, we are out buying properties and filing for permits currently. So we would expect to see our Water volumes increase in say late summer, just to be safe. And we're going to have a higher percentage of flow back. So we should see our skim oil percentage increase also and then get the benefit. Currently, we're getting the benefit in this January/February/March quarter of higher prices because we don't have the hedges we did in the low $40 range. We are also seeing a big uptick in solids, as we have solids processing facilities, DJ and the Eagle Ford in particular. So, we're very excited about what's going to happen by say late summer and then the third fiscal quarter with October/November/December 2018 from the increased rig count. In the DJ, we have capacity there. So, we are not drilling any additional wells. We may drill one for one of our committed producers. So, all of the increases is just falling right to the bottom line. And we think we're going to be full in the southern half of the basin by the end of the summer, and then northern half will probably take a little longer to fill up. Our capacity there is about 220,000 barrels a day and we're approaching 100,000, and it will just keep increasing from there. We also just opened our two facilities there, at C6 and C9, that process solids. So we're seeing an increase in the solids as well because of the increased drilling.

And Michael, on the skim oil, just to put some frame of reference around it, we expected a little bit less than 2,500 barrels a day of skim oil in our forecast. We came in just under 2,000 barrels a day. We had hedged close to that 2,500 barrels a day at $40. So, our hedges were in excess of the actual production at a lower value in a rising price environment. So overall, that was about a $1 million to $2 million impact to the quarter. So, taking that impact away of just the hedges being – of the over-hedges and then removing hedges and assuming the mid-$50 price, that alone bridges the gap between the $17 million for the quarter and the expected run rate next quarter of $20 million at least.

Okay, thanks. That's helpful. In the Liquids segment, the wholesale based liquids business, is it just weather that's driving the change in that, in the margins in particular? Just trying to understand the change in margins, and I think volumes I'm assuming is weather, but just want to make sure I understood the dynamics there.

Most of that margin change is on the butane side of the business, and that was expected coming into the year. Part of that's – with increased rail cost, increased competition in basins because of excess railcar capacity, all of that has driven to the impact that we are seeing on the butane side of the business. The wholesale propane business margins were not significantly different than what we've seen in the past.

Okay. And then a final question, I apologize if you said this and I missed it, so I got over the segments but I couldn't add them up quickly enough, is the – your prior guidance for this fiscal year was [$450 million] [ph] to $500 million, where does that stand now?

We are going to be at the lower end of that range.

Okay, great. Thank you.

Our next question comes from Matt Niblack of HITE. Your line is now open.

So, in terms of the overall trajectory of the Water business, it's definitely running obviously a bit below where you had originally hoped. When you look forward to kind of 9 to 12 months from now, by the time you have these new wells online and you've laid some more of the pipe you need to lay in places like the Delaware, do you have a sense of volume and/or EBITDA that you expect to be at if current trends continue in that kind of 6 to 12 months from now range?

Yes. What we did is looked, we modelled it and we said, what does it take to get to an EBITDA say of $125 million? And at that level, we only need about 700,000 barrels a day of water. So, we're in the low 500s. I don't know what it's coming out of this year kind of on a run rate, but it should be more than that. So, then you say, can we get 100,000 barrels a day each year for the next two year? And clearly, the answer is, yes. In the Permian alone, if you're doing 30,000 barrels a day per well, that's only seven wells, and that's only with water [indiscernible] to 4-to-1 ratio that's having 3 million or 4 million barrels a day of water that needs to be disposed. So, we are just being very conservative because we've gotten beat up on this water thing until here recently, but it looks fairly simple to get up well over $100 million of EBITDA.

Got it. As a run rate by kind of end of this calendar year roughly?

Yes, if you – the permits have to get approved, that takes some number of months. So if we had 10 drilled by the end of the year, then maybe we only get half a year's volume. So, just I think conservatively we'd say, at the end of two years, so end of calendar 2018.

Got it. And in terms of the competition in this business, how is that evolving? Is it getting more competitive, less competitive, and sort of how do you build the kind of moat around this business?

That's a great question. In fact, we've had a discussion yesterday because we all kind of look around and say, who are the competitors? And we know who they were in the past, [indiscernible] and select and key and basic, and they've all had some issues. So, we've seen a few new entrants. But I actually talked to the Water guys yesterday and we went through who the competitors were in each basin, and we have competitors that have anywhere from one to five, six, seven, eight wells SWD. So we don't really have a large competitor up there. We've heard Western wants to get in, do Anadarko, and Anadarko does some of their own. So, there is plenty of room for both of us. But we don't have a large competitor and it's really basin-specific and you have these smaller guys. We have normally 80-plus disposal wells. So we are 10 times larger than most of our competitors, if not all. I don't see prices falling any further. I think they've gotten as skinny as they're going to. We hear that some of the oilfield service companies are beginning to raise their prices and perhaps producers are raising the lock-in rig cost as soon as they can so they don't have that increase. So we don't see any further decline. We have a menu of services to bring, not just water disposal, and I think public companies should be more interested in dealing with us because we're going to be very safe, take the risk that they don't want to take, and I just kind of – I'll say, I sit here sometimes wondering why we are not getting all the business, because our model is really I think significantly ahead of the competition.

And your buildout there continues to be mostly pipelines for the incremental volumes?

No, I think we are seeing pipelines, I'm not sure how much, 100,000 or 200,000 barrels a day of new pipeline water. I think if you go into the Permian and you're able – there's a new area they are drilling, it's easier perhaps to just start with a pipeline instead of trying to convert an area that's already producing to a pipeline. So I think we are having good success in the Permian. But I don't know if it's 50-50 between new pipe versus truck.

Got it. And then last question. You seem to have some success doing some acquisitions here that fit nicely with your system. Do you see that continuing? Is there still a nice backlog of opportunities there that should feed that activity?

On the Water side?

Not just the Water side, but I guess you could comment by business, but you made some nice terminaling acquisitions, you made some tuck-in acquisitions in propane, so I guess when you look at the different businesses, what's the outlook for continuing to do those kinds of tuck-in acquisitions?

On the Retail Propane side, it's all tuck-in because we're not doing any start-ups there. They tend to lose money for two to three years. So, they are just buying them at a 4x to 6x multiple based on projected, not trailing. And the other segments, we are really completely focused on organic projects. We think there is growth to be had at Port Comfort, Houma, certainly I think at the DJ, STACK. Our Refined Products, we're looking to see if we can build storage with partners. So, I don't see M&A as a – it's not the focus and I don't see it outside the Retail Propane having a high probability. Now, like you said, the Murphy assets, we were familiar with those and we engaged Murphy Energy for a number of months, and then they unfortunately had to file for bankruptcy. But that's probably a one-off type situation.

Great. Thank you.

[Operator Instructions] Our next question comes from T.J. Schultz of RBC Capital Markets. Your line is now open.

Really just one question, it's kind of a follow-up to Matt's last question on CapEx. So I think you said you have $100 million of growth CapEx for fiscal 2018 in your model, and then I guess on your last point there, Mike, really the focus is organic growth. So maybe if you could just characterize where there are the most options to kind of increase that spend in 2018, what's the timing for the Point Comfort spend in particular, and just where the most opportunities are on the growth side?

I'll start and we can – on the Water side, we assumed about $50 million of CapEx, that's about 10 wells, in this fiscal year, $50 million of that $100 million, right. And then we had the STACK, which is $25 million to $30 million. And then we had I think $5 million left on Point Comfort. So, on the Water side, we don't really see any acquisitions. So, where they are? Let's see, in Crude, we'd love to find something that makes sense in the Permian. We would like to see some extensions or gathering systems both in the DJ and the STACK. Those are possibilities. Point Comfort would be by bringing additional volumes through that, whether it's by a pipe. I think that's probably the biggest opportunity there. And then on Houma, it would just be expanding storage. So we are running a facility. It's in service, it's going well. And so we are expecting or hoping, I'm expecting, everyone else is probably hoping, for increased storage that we can build there. I think Liquids, we are focused more on [indiscernible]. We've recently signed a contract with a customer for five years and we have other discussions going. The great thing there is you don't have any CapEx and we get to use, more fully utilize our railcar fleet. There's always some small propane deals. And then Refined Products, we are looking to build storage with others and utilize that storage like we do at Collins.

T.J., on Point Comfort, some of that spend will be in this current quarter and then a little bit rolls over into next year. [Indiscernible] only $5 million.

That rolls into next year?

Yes.

Okay. Thank you.

Our next question comes from Sunil Sibal of Seaport Global. Your line is now open.

So most of my questions have been hit, I was just looking for a housekeeping item. What was your covenant leverage at the end of the quarter?

Covenant leverage at the end of the quarter is close to 4.5x with the pro formas.

Okay, got it. And then you expect to end fiscal year 2018 at 4x, correct?

Yes, that's the target. And that leverage comes down pretty quickly with – this is the quarter that we generate significant excess cash flow which will reduce the amount of debt outstanding, we have very little CapEx to spend during this quarter, and we'll get the full benefit of a quarter of Grand Mesa.

Got it. So basically, when we're looking at fiscal year 2018 end, your reported leverage and covenant leverage should be pretty much aligning, correct?

Other than the exclusion of the working capital facility.

Right. Okay.

The pro forma EBITDA comes down significantly over the next two to three quarters.

Okay. That's all I had. Thanks guys.

Our next question comes from Ray Fu of Bank of America. Your line is now open.

Just a really quick clarifying question on the [indiscernible] from the DJ on Grand Mesa, is that [indiscernible] to the guidance which seems to be unchanged? And also on Grand Mesa, how does the agreement with Bonanza Creek sort of stack up to prior expectations?

So, the guidance on Grand Mesa does not change. If you go back when we provided that guidance in April of last year, we took the volumes from Bonanza and reduced those in half in our guidance. So we reduced that from a 15,000 barrel commitment, which they have disclosed, to a 7,500 barrel a day commitment. They are currently producing more than that and we receive 100% of their volumes and they are expected to complete some wells as well as bring a drilling rig back in after they complete their bankruptcy. At that point in time, we would expect to see volume grow through the remainder of this year. Our expectation is that with that growth we would still end up at the same overall impact as what we had guided to by reducing their volumes in half and they would exit at a higher run rate than what we had forecasted for the next year. Their rate is disclosed in their filing. The tariff is in line. There are some ancillary transportation that they would be provided, but that rate does have an escalator based on crude price. Our assumption for crude price is something very much in line with what we are seeing today, in the mid-$50 range.

Got it.

They are the only producer that has a rate that's dictated by crude price. It does have a floor and the floor escalates after a couple of years.

Understood. And then on the Crude Logistics, on the comment that you expected to make up I guess 25% of next year's EBITDA, next fiscal year's EBITDA, does that make any assumptions regarding sort of the forward curve and contango, or is it more or less just assuming that today's conditions persist?

Today's conditions, again a rough math, our numbers from last quarter, if we assume $600 million-ish, $150 million from crude, $130 million of that Grand Mesa. So again, at least 25%.

Got it. And then a follow-up question, can you just clarify, you guys are sticking with the fiscal 2018 EBITDA guidance for now?

For fiscal 2018, yes, I mean we used again some round numbers last quarter. We'll give more robust fiscal 2018 guidance on the next quarterly call.

Got it. Thank you very much.

And we'll break that down by segment as well.

All right, thanks.

Our next question comes from Matt Niblack of HITE. Your line is now open.

Thanks for taking the follow-up. So, on the Crude Logistics business, it looks like this is the biggest guide down versus your prior guidance, and I'm trying to understand that that delta, how much of that if any is Bonanza Creek? Is it $5 million or is it zero? And then, is the rest mostly the evaporation of contango?

So Bonanza Creek was the $5 million, which we referenced in the call. The rest of that…

Do you think you will make that up?

We will make that up through the rest of the contract year, yes, that's our expectation. The rest is in our marketing business, which includes supporting our trucking, our marine, our wellhead business, as well as our storage business at Cushing and in various other terminals.

Got it. Thank you.

Thank you. There are no further questions at this time. I'd like to turn the conference back over to Mr. Krimbill for any closing remarks.

Thank you very much and we'll talk to you soon.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Have a great day everyone.