Good day, ladies and gentlemen and welcome to the Second Quarter 2015 NGL Energy Partners LP Earnings Conference Call. My name is Lisa and I will be your operator for today. At this time all participants are in listen-only mode. Later we will conduct a question-and-answer session. (Operator Instruction) As a reminder this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Mike Krimbill, Chief Executive Officer of NGL Energy Partners. Please proceed, sir.

Thank you. This conference call will include forward-looking statements and information. While NGL Energy Partners LP 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 Energy Partners LP undertakes no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. 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 to the most directly comparable GAAP financial measures. All right. Thank you and welcome to our second quarter call. I think we will turn it over to Atanas to begin and we will go through some of the things in the press release. And then we will I think give a more thorough overview of our businesses and how they are doing. All right, Atanas?

Thank you Mike. Good afternoon, everyone. Adjusted EBITDA for the quarter is $70.4 million, excluding onetime acquisition cost of approximately $0.3 million, which is in line with the guidance provided during last quarter's earnings call. This compares to an EBITDA of $42.1 million for the same period last fiscal year and represents an increase of approximately 70%. NGL reported net loss of $15.9 million for the quarter ended 9/30/2014, which compares to net loss of $900,000 for the same period last fiscal year. The primary driver of the difference in net income was attributable to additional depreciation and amortization related to the acquisitions we completed. In our earnings press release we outlined some of the accomplishments during the past fiscal quarter. Most notably, the Grand Mesa Pipeline project to build a pipeline from Weld County, Colorado to NGL's storage terminal in Cushing, Oklahoma. And we expect the project to significantly increase fee-based cash flow upon completion in 2016. We also announced our plans to build a crude oil transloading facility backed by executed producer commitments, capable of handling unit trains from west of Albuquerque, New Mexico in the San Juan Basin. The project is expected to further enhance NGL's fee-based cash flows. We have already acquired the lands and are beginning to start the work. We also completed the acquisition of TransMontaigne Inc. in July 2014. As part of the transaction, NGL acquired valuable line space (indiscernible) on Plantation and Colonial Pipelines, refined products purchase and sale contracts and 100% interest in the general partner along with approximately 20% common unit interest in TransMontaigne Partners LP. At the beginning of this fiscal year, we indicated our expectation to incur approximately $30 million of maintenance CapEx. Year to date we have spent $17 million and we still feel comfortable with our estimate of $30 million. We also indicated our plans to spend around $500 million of growth CapEx in acquisitions. Year to date we have spent approximately $350 million and we anticipate the balance of $150 million to be spent through the end of fiscal year 2015, primarily on water and crude logistics. We also reaffirm NGL's adjusted EBITDA guidance of $425 million for fiscal year 2015 and approximately 18% distribution growth for calendar year 2014 with a 10% distribution growth thereafter. And with this I will turn it back to Mike?

Thanks, Atanas. I would like to go over the segments briefly and give you feel for what's going on. Starting out with the NGL logistics and retail. We have tried to be conservative and we will speak with respect to our $425 million projection for the year, our guidance. So we have tried to be conservative here with respect to these two segments as compared to the prior year. We originally pulled back within our guidance number the EBITDA between $5 million and $10 million for these because of the cooler weather last winter. But based on November weather and December-January forecast which we are getting more, having a higher probability, it's going to be a colder than normal winter and we could see these two segments equal or exceed last year's results. So there is some upside here of 10+ percent but we will see how it goes. If you have a business that where you like cold weather, your favorite colors become blue and purple. And if you look at the weather map they are just covered with blue and purple. So we were off to a great start. With respect to our presold gallons, last year we performed very well for all of our customers and we didn’t have to short fill any one on retail. We fully supplied all of our wholesale accounts according to the contracts. We didn’t cut anybody off. So we think that’s why this year, our presold gallons at this point in time are 220 million versus 100 million the same time last year. And increase of over 100%. And these have good margins and will be pulled by March 31. So another reason in addition to weather that we are feeling very good about our liquids and retail business. We also…

(Operator Instructions) And your first question comes from the line of T.J. Schultz with RBC Capital.

I guess just first on that TransMontaigne EBITDA guidance that you gave. I understand that some of the acceleration coming from the customer coming in on Florida. So as we get to kind of that year three run rate on those assets, I think it was about $70 million, could you just discuss any opportunity there to maybe optimize some of the other assets you acquired other than Florida that could provide some upside there? Just some color on what else is going on beyond just the opportunity you saw in Florida?

Sure. David Kehoe is on the line and he has responsibility for all of the refined products. So David, you might go into what we are doing in Florida with Butane, or Brownsville, other places.

Sure. So we have some opportunities in Florida outside of what we have leased out. So we are looking at expansion projects there around butane blending, as Mike mentioned, as well as some conversion of tankage from current live products. Well, still live products but into some jet fuel and some repurposing of additional tanks. And then within the Southeast system, we are evaluating a project to expand some of the facilities on the Southeast. And then with Brownsville we have got the expansion opportunities from both crude oil and refined products. So we are looking at each of the segments, if you will, on various locations, whether they be on the [river] (ph) Florida, in Midwest. And we have identified what we feel like are some very strong organic growth potentials behind the existing facilities there. We would say a period of time under the previous ownership that expansion and growth opportunities were considered on a, kind of on an ongoing basis, and so we backed up and started looking at that. So the business model would be the same, to continue to -- NGL will continue to look to diversify our customer based and expand out the tankage and/or change the product mix in the terminals and we think that has significant growth.

Okay. Thanks. And just on the guidance for this year. Mike, I understand that the backwardation issues on the crude business. I think last quarter we discussed that some of the ramp on volumes in the back half of this year would come from some of those pipe capacities coming back in the December and March quarters and now some of those delays sound like it may extend until the end of the year. So I'm just trying to understand the thought on the guidance remaining the same. Is that just a function where maybe you thought you were too conservative on the liquids business and now getting a little less conservative there so that offset some of those delays on the crude side? Is that the right way to think about it?

The performance on TLP, on the refined fuels with TLP, has been better than what we anticipated. And that’s offset some of the decline in crude. So the increase in the liquids segments will be a plus to the 425 and we feel pretty good about the water and the crude based on the 425.

Okay. Just to clarify, so that 425 includes that accelerated cash flow that you are expecting from the TransMontaigne asset at this point?

It includes part of it for this year, yes. The total numbers were for full 12 months.

Okay. Understood. And then just lastly, on the distribution growth guidance, that 10% annual growth that you're targeting. What's your expectation going forward? You mentioned Grand Mesa coming on increasing your fee business. Just as you look at distribution coverage on your asset base, what are you targeting as you also target that 10% annual growth?

Yes. We would decrease from a [1.5] (ph) to -- we would have to look at it, but maybe [1.2, 1.25] (ph) with more -- our goal is to get 60%. We can see 60% fee-based once Grand Mesa is complete. So we are probably two years or so away from that kind of a coverage ratio.

And your next question comes from the line of Darren Horowitz with Raymond James. Please proceed.

Mike, I had a couple of quick questions. The first, just with regard to your comments around the water business and doubling capacity there over the next two to three years. What do you think the associated CapEx is going to be in order to get you to where you want to be in the DJ Basin? And as we think about aggregate CapEx guidance shifting to fiscal 2016, how do we think about the split between what's going to be allocated on the crude side, like what you mentioned around Grand Mesa. And also what's going to be allocated towards the water side in order to accomplish those targets you laid out?

On the Grand Mesa, we haven't given out any value or any cost estimates yet, but it's probably still 50:50 water and crude. Let me think for a second. To do a million barrels of capacity -- let me think how many wells. That’s going to be 50 wells, 50-60 wells. And let's say if average facility has 6 million-7 million, so you are 300-350 on water and we are probably doing to double that on crude. So it's probably two-thirds crude, one-third water.

Okay. And in terms of the aggregate cap spend. Is it still fair to assume, like what Atanas outlined for this fiscal year, call it $500 million would be the expectation for fiscal '16 too or is there going to be a little bit of upside to that?

There will be upside to that.

Okay. All right. That makes sense. And then in terms of the crude business, like you talked about maybe some other downstream logistical enhancements that you could do, and I know in the press release there was some pretty good discussion around that oil transloading facility. How much more opportunity is there, provided that you guys can get the producer commitments and the economics clear your cost of capital and give you a justifiable return? How much more opportunity is there for you guys either to scale up in the San Juan or other areas and just try and get that margin capture opportunity further downstream of the wellhead?

David, you have thoughts?

You bet. So we have other opportunities. We are working diligently on them. There are probably fear in the San Juan although there is one other asset opportunity we're looking at there. The remainder of them, we are really focusing around the Gulf Coast and Canadian [market] (ph). And so we have both rail and pipe opportunities in both of those two lookouts and we are working with an [opportunity] (ph) at the Permian as well. So we have three strategic areas that our group is working diligently all the time to get producer commitments to. We feel comfortable over the next couple of years that we will have additional of pipe and rail facility to (indiscernible) customers in those three geographic regions.

When you look out over the next couple of years, and I recognize it's a difficult exercise to entertain, but do you have a rough sense of what you think the capital commitment could be to get where you want to be in each one of those three areas, just ballpark numbers?

If I take that over two to three year timeframe, I would say you are looking at 750, maybe just a little north of that.

Okay. All right. Thank you very much. I appreciate it.

And, David, I would have said the same thing, 750 to 1 billion a year for three years.

And your next question comes from the line of Abhi Sinha with Wunderlich Securities. Please proceed.

I apologize if you already answered this, just trying to understand if you can provide any update on I think the replacement of the lost transportation customer that you have mentioned in the last quarter that was costing you around [$500 million] (ph) or so in EBITDA every month. Just trying to get an update on that, if you have any.

Sure. It was 500,000 a month we did lose from that customer. So we are just slowly repositioning our vehicles in other basins as we get the additional volumes. And we are getting those volumes, as we said we are up to 300,000 plus a day. But it just takes time because you got to relocate and find drivers. David?

Yes. I was just going to mention that the biggest challenge is around finding the drivers. The tracks themselves are easily portable and movable. Where there is existing work for them, it's just finding the source of qualified drivers is difficult. There is a significant shortage of those and that's our biggest challenge, it's finding the drivers.

And, David, I would throw in there that this decline in crude prices could benefit us if it means there is certainly not necessarily an increase in production but there may be more truckers available as a result. And we think it may benefit, we could build our pipeline, with Rimrock perhaps, at a lower cost than otherwise if crude prices were still $100 a barrel.

Sure. And in the water services segment, we noticed that the OpEx has increased significantly. Can you comment on prime drivers for that, like...?

You said, operating expenses have increased in the water business? Is that...?

Yes, sir.

Yes. As you grow, obviously your operating expenses will grow because your volumes are growing. And so this is a function primarily of the acquisitions as well as the organic growth that we have experienced.

We should be lowering our per unit cost. It's a little -- depends somewhat on the mix. As our costs in parts of the Eagle Ford are higher than let's say the DJ, but we have been working hard on our chemical cost to get the benefit of larger suppliers from our water business. We have been looking at putting in some new systems so we can reduce the labor cost. So that will continue to actually decline over the next couple of years on a per unit basis.

And your next question comes from the line of Michael Blum with Wells Fargo. Please proceed. Michael Blum – Wells Fargo: I had a couple of questions on the water business. Can you tell us right now where you stand, what percent of that business is contracted versus kind of spot business? And you made an interesting comment about the change where you're hooking up pipelines directly. I would assume that that sort of keeps that customer captive to your system, but I just wanted if you could just talk about that whole concept?

Yes, I will start out and then I have Jim Burke on the line, I will ask him to jump in. Obviously, we have, the Pinedale is contracted, the DJ is contracted. So that's it a fourth of our -- that will be a fourth of the million barrels that we are talking about capacity wise. And then we had the customer, in the Eagle Ford we have that volume commitment of a minimum of 50 a day. We are actually getting almost double that from that customer. So we are seeing that -- and you are right, the pipes are great because it takes trucks off the road and we can make perhaps a little higher margin because we are sharing a bit of that truck cost with the producer who is no longer paying. So, all in all Jim, what do you think where this contract is?

Mike, I think about 50% is contracted and as you know we have signed up five customers within the last two months, large customers.

Yes, we are seeing that trend is that the -- we think the producers are seeing value in a public company that has financial strength building these pipelines. We are now -- in Texas the model was, you were dealing more with the trucking companies and billing them. We have now gotten quite a few of our relationships where we are billing the producer directly and then they are paying the transportation. So it's moving in the right direction, which is what we thought. It was just going to take some time. Michael Blum – Wells Fargo: Okay. That's very helpful. Thanks. And then just one other question on that. Just trying to understand the thought process or how you are planning to grow that business, basically double it and then double it again within the next couple of years, sort of in the context of falling commodity prices? Are you thinking you're going to take market share from others or is there something else that's going on there?

I will say it's both. We are making an acquisition in the Bakken. It's not a big one, it's two wells. So that's the acquisition side. We are not buying much. We much prefer to drill our own but that's the first presence we will have in the Bakken. So found a really nice couple of wells to start from. But we are moving into, with our customers into new areas. So it's not a stealing someone else's water but the Eaglebine, the Delaware, we moved over into the Granite Wash. And so it's really new areas of production and following our customers which is great. And then there is, I think we are getting water perhaps from the two competitors because of our reliability and being a public company. And any other thoughts, Jim?

Yes, Mike. I think that because of our size, being a dominant player, it's so much easier for somebody large, independents to make one call. For example in Eagle Ford where we have 14 or 15 facilities throughout the entire basin. Then call up some of the smaller players area by area, location by location. So a lot of the large independents do like the fact we are a strong public company but also because of simplicity for the basins. The operators can call up -- make one call and we can service almost all their needs in a lot of the basins. Michael Blum – Wells Fargo: Okay, great. And then on the Grand Mesa project, I think you said you are not going to tell us what the capital cost is, but just looking for any other details you can tell us. I know the press release says 2016, but I wasn't sure if that was first quarter or fourth quarter, and then what types of returns are you looking to generate? And of the 130,000 a day, how much of that has been committed and does that sort of get your minimum return and then there is upside? Just trying to get a little more flavor around that.

Sure. I am trying to think through all your questions. This is completion -- the completion of course would be, I think we have indicated the middle of '16. We have already stared acquisition right of way. So we are on target to hit that. Cost, sounds silly to me, but it's downhill. So we don’t necessarily have a lot of pump stations which cuts down on the cost and the power needed. So if we could end up return wise in the 6 to 8 multiple range, I would be very -- I think that would be a great project. Michael Blum – Wells Fargo: Okay. And then last question is just, as you mentioned you were unsuccessful in your bid for the remainder of TLP. Should we just assume that the way things are structured now is how things will proceed, or could you contemplate potentially making another offer here at some point?

I think we would contemplate an offer in the future but at the moment it wouldn’t -- we wouldn’t have any interest due to just really where the unit price is.

And your next question comes from the line of Ted Durbin with Goldman Sachs. Please proceed.

I guess if I could go back to the backwardation issue. Can you just give us a sense in storage rates, what are storage rates looking like right now as you're out contracting?

David, do you have a flavor for that?

We are starting to get some interest in storage rates and leasing of the tankage now. The Gulf Coast is somewhat filling up back up the Cushing and so if we can get into a little bit stronger contango market then we think the storage rates will be back. Previous to now we have had little to no interest in storage at Cushing.

Are there any sort of numbers, range of numbers, you can put on the rates?

I think the rates will come back in $0.25 to $0.35 range.

Got it. And then just coming back to the water business. I guess can you just give us a feel for what is actually your direct commodity price exposure? Realizing you're hedged through '15, but how many actual barrels of oil or liquids should we think about your exposure now and as you double and go to, say, two million barrels, what would your exposure look like? Would you just double it or would it be sort of a smaller or bigger oil cut, or maybe you keep less of it? Just give us a feel for where that commodity exposure is?

We haven't -- Ted, we really have never talked about the oil cut. It moves around on and it tends to move down and not up. So I think we will probably -- we will go back and look to see what that is and maybe we will talk about it on the next call. But for the rest of this year and part of next year, we are not going to see a decline.

Right. The hedges, okay.

Right.

Fair enough. And then last one for me. As we now have the refined product segments in here, should we think about, just for modeling purposes, significant seasonality there? Or should it be at least pretty ratable across the year?

I will think, Mike, it should be ratable. We are not, kind of have a lot of seasonality around the business.

(Operator Instructions) Your next question comes from the line of Matt Niblack with HITE. Please proceed. Matt Niblack – HITE Hedge Asset Management: Just a follow-up on a couple of those questions in the water business. First question is, the revenue per barrel came down quarter over quarter, just commentary on that, and if that has to do with the oil cut and if that's a pre-hedging revenue? And then secondly, if you could just give us a sense of, based on overall rig count, how much does the water business volume go up or down just in your base business, putting aside the growth projects you have in mind?

Well, Jim, I will start. I would say revenue down per unit is probably more a function of mix and most of our expansion is weighted into the Permian and the Eagle Ford.

And if you look at the margin itself, the margin itself is not really -- is materially the same as it was last quarter. And so really ought to be looking at the [margin] (ph) per barrel.

Yes. So we get to the same returns in margin. But you will have perhaps a lower revenue in Texas because your costs are lower. Matt Niblack – HITE Hedge Asset Management: Okay. Makes sense.

Okay. And then rig count, I guess what we are anticipating because we don’t really look at our business as a -- not real scientifically, I guess trying to calculate anything per rig. But we are anticipating that the upstream guys will be somewhat limited by their cash flows and we will see them cut back their expansion plans perhaps for next year to a level of duplicating what they did this year. So we would not expect to see an impact on our business unless the rig count is declining over what it was last year. Matt Niblack – HITE Hedge Asset Management: In terms of the base business though, if we were to see a rig count decline, isn't the water business sort of one to one with the rig count? Because it really has to do with the drilling and completion of the well rather than the production? Is that the right way to think about it?

Jim, I will let you answer. There is a certain produced water and flowback water and your rig counts can impact your flowback and not your produced. So certainly if they cut there -- if the producers cut the rig count in half, we are going to have in theory half as much flowback water. Matt Niblack – HITE Hedge Asset Management: And what's the mix between produced and flowback in the business?

Jim, do you have a feel for that?

Mike, under 50, as far as flowback.

Yes. I mean flowback is going to be probably -- what is flowback? I mean we ask ourselves that and it's kind of like everybody, you trust everyone to say, well, this is flowback water. But oftentimes we have a two tier pricing for flowback and produced. So is flowback water the first three months, coming out of the well first six, first two, after that there isn't any. So it's going to be, as we get bigger, the flowback percentage drops because the number of wells being drilled, let's say it stays the same, it's going to be a smaller percentage of our total volume, right. Matt Niblack – HITE Hedge Asset Management: Right. So the portion of the base revenues that are really impacted by rig count directly is somewhere south of 50% and declining over time.

Right. Matt Niblack – HITE Hedge Asset Management: Is that a fair statement?

Hey, Mike, this is Jim. I think I would add a couple of things. First of all, in some of the basins we are at capacity right now. For example the DJ, we are at capacity so we are trying to keep up right now by building several facilities all at once. And as far as utilization, we are very high throughout the entire business unit. The other thing I like is, we are doing a lot more than just the oil cut, the fee and recycling in some cases. Now we are into fresh water and we are way downstream as far as taking care of the solids, the bottoms and the drilling mud and things like that which are high margin. So we have got more of a full slate. We are diversifying our approach, if you will, of that producer with some very high margins items.

There are no additional questions. I would now like to turn the presentation back over to Mr. Mike Krimbill for closing remarks.

Great. Thank you, and thanks for your time guys and your good questions and we will talk to you next quarter.