Good day, ladies and gentlemen and welcome to the Q3 2015 NGL Energy Partners LP Earnings Conference Call. My name is Sue and I’ll be the operator for today. At this time all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of this conference. [Operator Instructions] I’d like to advice all parties this conference is being recorded for replay purposes. I’d now like to turn the call over to Mr. Mike Krimbill, CEO of NGL Energy Partners. Please proceed, sir.

Thank you and welcome everyone. This conference call will include 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 the prices and market demand for natural gas liquids, and crude oil, level of production of crude oil and natural gas, effect of weather conditions on demand for oil, natural gas, 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 any 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 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 reconciliation of the differences between any non-GAAP measures discussed on this conference call and the most directly comparable GAAP financial measures. All right, let’s get started and we will turn it over to Atanas.

Thank you, Mike. Good morning, everyone. Adjusted EBITDA for this fiscal quarter is $144.8 million, which exclude one-time acquisition costs of approximately $8.2 million. This compares to an EBITDA of $85 million for the same period last year, which represents an increase of 70%. NGL also reported net loss of $5.3 million for the quarter ended 12/31/14, which compares to net income of $24.1 million for the same period last fiscal year. The primary driver of this difference in net income was attributable to approximately $29.7 million of loss on disposal of an asset. In our earnings press release we outlined some of our accomplishments during the past fiscal quarter. Most notably, we began construction of the Grand Mesa Pipeline, which is a 20-inch crude oil pipeline originating in Weld County, Colorado and terminating at our Cushing, Oklahoma terminal. We completed a successful open season in which NGL received the required support in the form of ship-or-pay volume commitments from different suppliers and shippers, to begin construction of the pipeline system. On February 9, 2015, we also announced the signing of an agreement to acquire an entity that owns a natural gas liquids salt dome storage facility in Utah. The purchase price will be approximately $280 million, of which $80 million will be payable in cash and approximately $200 million will be payable in NGL common units. At the beginning of this fiscal year, we indicated our expectation to incur approximately $30 million of maintenance CapEx. Year-to-date NGL has spent $25.7 million, excluding $2.8 million of TLP, TransMontaigne Partners maintenance CapEx and we still feel comfortable with our estimate of $30 million for NGL. Our year-to-date interest expense of $69 million and that excludes $3.4 million of interest expense attributable to TLP, and our forecast for the year -- forecast interest expense for the entire 2015 is approximately $95 million. We also indicated our plans to spend around $500 million of growth CapEx in acquisitions. Year-to-date we have spent approximately $502 million, which excludes $3 million of TLP growth CapEx. We also reaffirm our adjusted EBITDA guidance of $410 million to $425 million for fiscal 2015 and our 2015 distributable cash flow is expected to be between $285 million and $300 million and that is based on maintenance CapEx of $30 million and interest expense of $95 million. We also reaffirm our distribution growth guidance of 6% to 8% for fiscal year -- excuse me, for calendar year 2015. Our EBITDA guidance for fiscal year 2016 is in the range of $485 million to $500 million based on current economic conditions. And with this, I’ll turn it back to Mike.

All right. Thank you, Atanas. Why don’t we open it up for questions?

[Operator Instructions] Your first question comes from the line of Abhi Sinha, Wunderlich Securities. Please proceed.

Yes, hi. Good morning, everybody. So quick one on some of the operations here. So I think last time you were expecting margins from the water segment to be 50% higher in fiscal ’16 than ’15. So how has that change or do you still maintain that to be and of course also the volume, I think you’re expecting two to three -- I mean, double the volume in two to three years, would that still remain the same in terms of guidance?

On the water volume side, we did I think double our volumes as we had more disposal wells and increase what’s coming through our previously drilled wells. Margins were not going to increase. They could have -- they decreased actually as a result of more wells in the Eagle Ford and Permian, which is where most of our activity is. The disposal fee down there is less than it is in the [indiscernible] to DJ. So going forward, we’d expect to see volumes continue to increase, although we’re all looking to determine, what’s the impact from drilling on flow back volumes. So, if we were -- if our volumes were consistent and the margins will be equally consistent then we’d be very happy. So that’s probably a decent projection going forward.

Sure. For the Magnum assets, can you talk about the cash flow ramp up here? I mean, what’s the cash flow for the first year and what’s driving the ramp up? Is this utilization or the more expansion of opportunities baked into it?

Yes. We -- the initial cash flow is DCF is expected to be close to zero. So the growth is coming from the additional caverns, we can drill up to eight caverns and approximately 10 million barrels which we will be doing. And so that ramp up will occur as the different caverns are completed, which will take about -- I think we said through 2017. So neutral on DCF in the first year and then it will increase to a number that gives us seven multiple deals.

Right. Sure. And then the equity issuance, will that impact distributions for fourth quarter fiscal ’15, I suppose?

We have a forbearance agreement in place, so it would impact them somewhat, yes.

Sure. And then last one, if I could, I mean, any update on the butane blending facility that you were talking on last quarter?

I didn’t catch that. The butane …?

The butane blending subsidy I thought that was supposed to go online in November, I’m not sure what’s the update on that?

Yes, that was the refinery in the Northeast and that did come on in November. And so, we’ve got a month of activity from that. In this quarter, we will have obviously a full quarter -- full three months next quarter.

Right. Sure. That’s all I have. Thank you very much.

Thank you. Your next question comes from the line of Darren Horowitz, Raymond James. Please go ahead.

Good morning, guys. Mike, I’ve got a quick question for you on crude oil logistics and I know a lot of this really hedges on the forward curve. But now that we’ve swung from backwardation to contango, as you look at the impact on monthly inventory, do you feel like there is a little bit more opportunity from the Gavilon asset perspective to get more asset optimization and maybe a little bit more profit or how do you think about kind of swinging that storage capacity that you had, that was losing a certain amount of money per month possibly to making a little bit more just based on what the forward curve is looking as we look forward to fiscal ’16?

Well, I’m glad you asked that question, because we’re very excited about the change in our fake from backwardation to contango and we have Don Robinson on the line who have [technical difficulty] logistics. I think Don can start out answering -- answer this. I’d like to put that in perspective with what’s going on the water side with the skim oil. Don?

Yes. We basically we do expect. We entered into a couple of agreements for around 25 months for some of our storage that was at real -- at healthy rates versus what obviously had been in the past at Cushing. That’s about a million three, the barrels we have there and then we have about 3.5 million barrels at basically we are looking at from a contango point of view of doing some shorter and longer term deals to take advantage of that market. And we are actively doing that today.

Don, is it a situation where -- when you look at storage rates, are they getting close to $0.25 or $0.30 per barrel. I mean, are we back up in that range?

Actually they’re little bit higher than that. So they’re more in the $0.40 range.

Okay. And is there much of a variation between that range in terms of if you contract those for a few months or anywhere between six months to a year versus maybe sacrificing a little bit of rate and getting more term or more duration?

Well, actually we were able to achieve of those two year rates, around 25 months at those higher numbers, because obviously where the contango where its been in the last 30 to 45 days, we’re looking at. If someone wants to look at tankage we’re expecting that those terms to be longer and not in short-term deals here.

Okay. Thank you.

Yes, Darren. I just to that, I haven’t seen what the curve looks like this morning. But I think for the next six months, we’re probably $1 a barrel. So to Don’s point we had $3.5 million at Cushing, we have storage other places as well. So that’s a very positive factor going forward. We are also losing due to the crude price drop on our skim oil. So we’re probably going to lose -- I mean, if the prices stay where they’re today, we could be down 40-ish million on the skim oil, value, but we expect to make that up and possibly more on the storage. And I think that’s something that everyone should realize that we have this natural hedge. When you have low prices, you’re going to have excess supply so storage is valuable. When you have high prices, then storage is valuable, but our skim oil is very valuable. So we really emphasize more and more that having this portfolio of companies, five different segments, there is a lot of natural hedges. So whatever gets thrown our way in the marketplace, we’re going to find a way to hit our numbers.

Thank you. And your next question comes from the line of Gabe Moreen from Bank of America. Please go ahead.

Hi. Good morning everyone.

Good morning.

Question for you in terms of where you guys feel the balance sheet is at, particularly post the equity or issuing as part of the Magnum deal? Do you think you need to come to marketing more this year? Do you feel comfortable where you’re sitting particularly after Grand Mesa?

Excluding Grand Mesa, we’re very comfortable and that’s why this -- it was very important to issue equity as part of the transaction and not have to go to market. But we’re going to have to issue some equity sometime later in the year for sure to fund part of the Grand Mesa CapEx. So, we have $600 million or so remaining to spend, and we’d like to do, say, half of that in equity.

Got it. And I guess, Mike, are you looking at other sorts of transaction versus whether you’d be able to issue equity for substantial portion of any deal you do, because it just seems like you kind of killed two birds with one stone potentially?

Yes. An obviously example would be, if we come back and try to merge with TransMontaigne that would be one where we just issue equity, for it will be self funding.

Got it. And then turning to, I guess, speaking about TransMontaigne kind of how things are going in terms of the marketing business. Now can you talk about, I know you talked about sort of getting third party volumes into a lot of those facilities which were proprietary previously. Can you talk about kind of [technical difficulty] basis?

Certainly. As Part of our -- as part of the transaction we stepped to more general issues on the backstop recall they had or take or pay on Florida. The Florida terminals in the Southeast which is [indiscernible] and the guys at TLP did a fabulous job finding a partner that could replace us in Florida, and they -- successfully release [ph] some time ago Metroplex is in. So, we have eliminated in fiscal ’16 about $1.4 million a month of expense on the Florida terminals. We are keeping our take or pay on the Southeast terminals which is about $2.2 million a month, which is -- allows us to sell the products through Colonial and Plantation with the product that we’ve -- with the line space we purchased from Morgan Stanley which I think was a 130,000 barrels a day and we picked up marketing [ph] contracts of something just a little less than that. So, we’re very pleased with that transaction. Margins are actually better than what we had modeled. And of course the lower prices for gasoline and distorts we expected there’ll be some increase in demand.

Yes, just was if you’re done, I’ll ask another one. Last one for me Mike, I think you guys put out slides recently at another conference talking about future distribution growth expectations. It seemed like there was a little bit of iterative process, in other words your unit price maybe as high [technical difficulty] growth was a little bit higher. Can you just talk about that? And is there any specific level you’re looking at, any specific duration of time particularly considering volatility?

Yes, previously we had indicated 10% growth in calendar ’15, ’16, and then of course when the entire space got hit and our unit price fell to that $20, I think we got as low as $23 and now we’re back to $30. It just didn’t make any sense, because we weren’t going to get credit for a 10% growth. So that’s why we pulled it back to 6% or 8%. We still want to be one of the top distribution growers in the MLP space. But we also want to get credit for what we’re doing, and otherwise we’ll just pay down debt and improve the balance sheet. So, at this point around $30, we think 6% to 8% is fair and for [indiscernible] price was higher -- significantly higher than we might increase that rate.

Got it. Thanks guys. Thanks Mike.

Thank you. Your next question comes from the line of Ethan Bellamy from Baird. Please proceed.

Good morning, everybody.

Good morning.

Mike, could you refresh us the current stakes at SemGroup, and if there is any plan to get those back?

I do not know what the current number of common units are that they own, we just see what you would see. But it seems like there was some kind of a filing that indicated that the backend, I’ll say mid January they were around 6 plus million units down from 9. I think they had 9.1 at the high point. So, you know as much I do there. I saw no change in their GP ownership.

Okay. With respect to the TransMontaigne merger, is relative price the only gating factor to bring that back or to try to get that done again?

Yes. We look at it the -- say the purchase price or the value is kind of unchanged as long as their price is where it is today. So it’s really a function of how accretive would the transaction be to NGL. So, obviously there you would want to issue fewer units. So, it’s definitely our price -- an NGL price compared to a TLP price.

Okay. And then last one, with respect to the Grand Mesa customer book, can you give us any insight into who the producers are? What kind of credit quality they have? How confident you are in their CapEx plans, and their actual production et cetera?

I’ll start, and then Don can add to it. We haven’t disclosed that. We still have one competing pipeline out there. I think it’s called Saddlehorn. So, until we know what's happening in the marketplace, we’re not disclosing any of our shippers nor tariffs. Don, do you have anything to add?

No, I guess the only thing Mike is we are -- the length of our term show those, with the producers that we have on the pipeline are a little bit north of seven years.

You mean on average?

On average. Right.

Yes. So, our shippers are 5 to 10 year contracts. And in the queue you can see we did indicate we’re building a 20 inch pipeline.

And that’s an increase, right?

Yes.

And what capacity is spoken for?

We haven’t indicated that either. So, I think we need to wait till we determine what's going to happen in the base and with the competing pipeline. But you’ll be the first to know.

All right. Thanks guys. I appreciate it.

Thank you. [Operator Instructions] Your next question comes from the line of Michael Blum of Wells Fargo. Please proceed.

Hi. Good morning everybody.

Good morning, Michael.

Good morning.

Just one question on, Magnum; you said you’re going to be drilling eight additional caverns, what's going to be the cost or CapEx associated with that? And we think about the seven times multiple in fiscal ’17, is that an all in multiple including whatever capital above the $280 million that you need to spend, or how do we think about that?

Sure. Just a correction, the total caverns that would -- we have room to drill our eight. A number have already been drilled and contracted up. The guys that did the deal for us on our side Todd and Jay are on the line, so we can have them talk some about the additional CapEx per cavern. So you can get a feel for, is it a lot of dollars or not that many?

Yes, this is Jay Furman. The approximate per cavern spend for additional cavern [technical difficulty] between $12 million and $15 million depending on size, related infrastructure as you do different caverns you may need to add additional pipeline or connectivity. So, but somewhere in that $12 million to $15 million per cavern range is a good estimate.

So, Michael, that’s the part of the answer. The other part would be, if we look at the total CapEx we’re anticipating to spend an addition to the purchase price, and my guess Todd, Jay another $50 million, $60 million, $70 million?

Yes, that’s correct Mike. It’s about probably $60 million to $70 million incremental.

So you can divide that by seven Michael and you’ll have your EBITDA.

Okay, great. And then, can you also just talk more broadly obviously where we’ve seen lots of announcements that VMP [ph] is cutting CapEx, laying down rigs, and can you just talk about how you see that impacting the water business broadly?

Yes, I think in the queue we also disclosed that our four backwaters approximately 20% of our total water, we expect to have half the rigs laid down. Some of the rigs we talk to producers were already going to be laid down to say we’re drilling from the super pads here more recently, so they could drill the same number of wells with fewer rigs. So, rather than just a quarter or third going down, we think half will go down. And then that would in theory relate to about half our flow back which is 10% of our water. We are replacing that with a couple of other initiatives, and I think we’ve talked about in the past we are -- we developed some processes to dispose of solids for the producers. They are currently taking much of that to landfills where they’re paying $20 to $30 a barrel. We can dispose of it in our well sites for much less. And we’re trying to be as a solution and not a problem. Meaning, once the drilling and completion costs are hammered by the producers are lowered then they’re going to be looking at their lease operating expenses which would include our disposal fee which is relatively a small number as you now compared to their total. A lot of their expense on water disposal is related to water trucks and trucking. And so, we’ve approached the producers to put in water pipelines from their tank batteries into our disposal sites, and we’re finally getting a lot of traction there because that could be as much as $1 to $2 a barrel, and the producers are now interested in working with us. So, we have quite a few projects. When that happens, you’re getting all the water from that tank battery. You’re not just getting whatever the trucking company decides to bring to you. So, we see an increased market share on the water side that we’re anticipating offsetting the decline on the flow back. And it’s also the waters at the very different business and that you don’t -- from a competitive position you don’t have these large public companies, you have some smaller public companies that are trading at $5 or less and private companies. And so, we’re expecting to see the upstream guys want to deal with a public company with good financing that they can depend upon that will be there. So, between solids and water pipes we’ll increase -- we’ll get some increased EBITDA to offset what's going to -- we’re going to lose on the skim oil, oil price decline, and then we would also expect to increase our market share of the water business.

Got it. Thank you very much.

Thank you. And your next question comes from the line of Matt Niblack from HITE. Please proceed.

Congratulations on another solid quarter here in a challenging environment. We’re just looking for some more color on the contracts at Magnum particularly as you’re looking at the expansion. Is the expansion fully contracted and for what term? And I guess if not, how much risk is there around actually seeing the cash flow associated with the expanded capacity?

Not all the capacity has been contracted. We have contracted up all the capacity we have, and we’ll continue to do so as each cavern is completed. I think the initial contract terms Jay would be what length?

Average initial contract term was three years, Mike.

Okay.

Okay. So, three years for the existing, and what is the -- what's the driver that we can look at of increased demand to support the additional caverns. So, what is -- what's creating that need in the market?

Jay, your thoughts on that.

Yes, its really -- this business is built around the western mountain region, and again being outside of the Salt Lake city area, so the biggest customer base is refiners west to the Rockies, and end marketers and the other support companies west to the Rockies. So if you look at the regional growth in refining and health of that industry that’s definitely our primary customer versus it’s not a big production backed facility. So if you look at production risk and the impact of that, there is not the exposure there versus it’s really refinery based business.

So you’re building these additional caverns, because the refiners in the area are saying we need more storage capacity?

Refiners or other customers, yes.

Okay. Thank you.

And that’s kind of a normal term if you at Belvieu and Conway liquid storage, those contracts are anywhere from one to five years and we obviously lease quite a bit of space in Conway ourselves. End of Q&A

Thank you. Thank you for your questions today ladies and gentlemen. I’d now like to turn the call over to Mike Krimbill for closing remarks.

Yes, well thank you guys for your attention especially early in the morning. And we really hope everyone comes away from this, realizing that focusing on one of our segments is kind of useless and that this portfolio is doing exactly what we had anticipated will do and when you have things that aren’t so great in one segment, we have another one that’s kind of a natural hedge. So thank you very much. We are anxious to talk to you again after this next quarter.

Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Thank you for joining and have a very good day.