Good morning ladies and gentlemen, and welcome to the Q1 2018 NGL Energy Partners LP Earnings Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to turn the conference over to your host, Mr. Trey Karlovich, CFO.

Thank you, Kenzie and welcome. 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 management 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, 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 and 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 the Risk Factors and 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. This conference call also include 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 partnerships earnings release, investor presentations, and annual and quarterly reports on Form 10-K and Form 10-Q on our website at www.nglenergypartners.com under Investor Relations 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 and the most directly comparable GAAP financial measures. At this time, we will now turn the call over to Mike Krimbill, our CEO.

Thanks, Trey. I think what I'd like to cover and then we'll get into detail. However Trey is in overall state of the numbers and the company -- have we changed any strategies based on the market conditions; and then my thoughts on the individual business units in the full year. So I think first we need to put the quarter into perspective. Our NGL logistics segment was about $10 million of the shortfall due to falling liquids prices during the quarter. Our inventory values include our pre-sold gallons that are at a higher price than the quarterly average, so prices were declining from April through the end of June such that when the ratable barrels we received each day are sold and they are sold at or above cost, they are hit temporarily with a higher weigh [ph] resulting in a loss. So this shifts the EBITDA into future quarters when the presold gallons are extra delivered, so this is a timing issue. We've had this happen to us in the past and in the summer when the liquids prices were falling. Secondly, our refined products group also experienced some timing issues. Our hedges of the future months product prices did not match the decline in the twelve [ph] month; the twelve months fell more than the out-months and that resulted in a loss of approximately $15 million that will be recovered prior to year end as the prompt and future months prices converge. Adding these two items back to EBITDA which resulted in a number of the low $60 million area which is about $10 million below the equity analyst average guidance. This $10 million in trial get into I think some more -- it will not come back as it resulted from the same market conditions we…

Alright, thanks Mike. So I'm going to go through our quarterly results as well as our current expectations for the rest of this year with my additional thoughts on each business segment. So walk through each segment expectations for the remainder of the year and then we'll go through the balance sheet. I'll start with the easy ones, so with crude oil. The crude segment generated approximately $26 million of adjusted EBITDA this quarter with Grand Mesa contributing $30 million and the remainder of the segment operating at a slight loss as the marketing business continues to support our various assets. Volumes on Grand Mesa averaged about 75,000 barrels per day for the quarter and exceed the quarter over 80,000 barrels per day. We expect volumes to continue to ramp through the upcoming quarter and we expect over 90,000 barrels per day in August based on current nominations compared to our original guidance just for this quarter of 75,000 barrels per day and an average of 80,000 barrels per day for the entire year as Mike mentioned. As a reminder, the minimum volume commitments on the pipeline increased on November 1. The differential in the basin continues to improve, that is currently trending ahead of our original forecast. Our Houma and Point Comfort assets are just beginning to ramp up and we expect those assets to generate incremental revenues throughout this year. We continue to focus on rig counts in the basins we operate, crude prices and opportunities for increased utilization of our transportation and storage assets. And the crude group is working closely with our water team to provide multiple services to producers. The Glass Mountain extension into the stack remains on budget and on-schedule and we continue to expect it to begin operations in early 2018. At this…

[Operator Instructions] Your first question comes from the line of T.J. Schultz. Your line is open.

Hi, Mike. This is Rahul, in for T.J. Just had a few questions here in regards to your restructured contracts. I was wondering, do you guys have any leverage - under these contracts, do you still have any leverage to the upside, should line space values increase? And is there a more stable quarterly or annual run rate for the segment with these contracts in place now?

Answer to the first one is yes, do we share in the upside or the positive, but we do not go negative. And what that will do is make our margins more consistent, but we're still subject to this volatility due to our hedging program and the relationship of the prompt [ph] month price change to the out-month price.

Okay. For your 2018 guidance, I know you guys have previously mentioned that assume the sub-normal winter for retail propane. What kind of an impact relative to guidance would there be, should there be in normal winter?

Normal winter would be about 10% higher. Colder than normal winter would be 15% to 20%.

Okay.

And a warmer-than-normal winter would maybe be 10% lower if that. I think last year is a comparable number for the downside.

We did take an average over the last three years. That was 5% or 6% warmer on average. It would have to be warmer than that to ever lower number than what the guidance were providing.

Okay. And then last question, are there any restrictions from the banks after the recent amendments on paying your distribution on lower coverage level? I just want to get your comfort level with the current payout.

The only restriction on distribution is that we cannot increase the distribution if our leverage is over 4.25x where our interest coverage is under 3x, but there are no restrictions or limitations on the current distribution level.

All right. Sounds good. Thank you, guys.

Thank you.

Your next question comes from the line of Shneur Gershuni. Your line is open.

Hi. Good morning, guys.

Hey, Shneur.

Starting I guess with the guidance, right now the guidance is now 475 versus to 500 and it was 500 to 525, which is kind of basically a $25 million down draft. But I think in your prepared remarks, Mike, you have said that you thought that you were tracking this quarter about $10 million below expectations. Obviously that would sound like it's a bigger delta in terms of tracking error. Where do you think the difference is, where do you think you're going to be able to make up the difference versus where you're tracking versus original plan?

I'll start. Shneur, one of the things and in my comments, I mentioned because of the recontracting on Colonial, we estimate that that's about $10 million impact to the rest of this year, so that's not an impact that was realized earning this quarter, but it is the impact that we're forecasting based on current line space values. That number could change if line space were to move positive. As Mike mentioned, we do get some of the uptick in mind space values, we're capped to zero on the down side. That's $10 million of the difference - $13 million is what we believe has been. We've essentially not be made up based on the impact from the first quarter.

Great. But I guess my point is that you're tracking $10 million for the year below on your first quarter. Right? So it's $40 million annualized, but the guidance only moved down $25 million?

Got you. The $10 million, it was lost from the first quarter, does not annualize. We kind of debated what do we do for guidance? Do we just drop it to 500? What do we do? So we decided to just be a little more conservative and go to the 475 to 500.

Got it. Okay. And with respect to propane expectations, you're assuming that the average heating degree days for the last two winters is now normal for your guidance?

No. We took the last three and averaged it. I think most in these three does some kind of normalization. The last two winters have been much warmer than normal, so they keep going back to normal seems like you're banging your head against the wall. So we just took an average of the last three years. I think three years ago, it may have been 4% or 5% colder than normal. The last couple have been 10% to 15% warmer. If you had them together divided by three, that's why I came up with 5% or 6%. Our guidance is based on 5% or 6% warmer than normal.

Okay, got it. Last fiscal year, you had some propane inventory liquidation issues. What's being done a, to mitigate that and; b, if prices zoom up, does that potentially present that risk again if price has moved up, but then all of a sudden you don't get the weather that you're thinking in February? What's being done basically to avoid being long inventory at the wrong times?

That was a function of the weather and supply situation in the New England area, which a lot of the contracts are based on a Bellevue [ph] Index. So you are correct, we have a requirement in our contracts that the counter party has to take 90% of the contract, so we are only committing ourselves to 90% of the contract volumes. We are also doing some things with exchanges, so that we can short ourselves in that February-March time frame. So if it does turn out to be warmer than normal, we will not be stuck with the length that we had last year. The other unknown, which is going to be interesting to all of us is the MEE2 [ph] pipeline, if that's on stream in service and moving liquids out of the New England area - will that really get rid of the excess supply? Or be effectively a hub just like Conway or Belleview that the excess supply can go into that pipeline and be exported. That was a bit major, I guess, an impact as what was going on the blind space, but we have changed our strategy up there in New England area, so it does not happen again.

Okay. Just sort of shifting to line space. You've talked at length about colonial. Can you talk about the plantation? Are we going to have any similar issues there? Do you see that coming and do you have space on any other systems that we should be watching as well, too?

We do not have space on any other systems. Some of the other core systems might be Mid-Con, NuStar, Explorer, Magellan, but those are not on allocation and there's not a line space issue. It's limited to the southeast. We also have some line space on plantation and we've not experienced...

It's been essentially flat.

Flat.

Yes. It's been the Colonial line space.

Okay. Final question on water segment that's doing all right. There has been some talk about completion crew shortages in the Permian and some of the higher areas and so forth. Would that have an impact on your water expectations at all?

That at the bottleneck at the moment is getting permits approved. We have at least 14 or 15 permits out there. It's taking six to nine months to get approval. That's why I say we're fortunate because we have getting this year a million and-a-half barrels of capacity through all the basins and we're running maybe 500,000 barrels a day. So we've got plenty of space. Where it's getting tight is in the Delaware. That's where the majority of our permits are. We haven't seen oil-filled service or completion rig, completion crew issues yet. So the answer is we don't think so.

All right. Perfect. Much appreciate. Thank you for the color.

Your next question comes from the line of Gabriel Moreen. Your line is open.

Hi. Good morning.

Hi, Gabe.

Hi. Just a couple of questions on Colonial fundamentals. I know there's a refinery down at Mexico, exports has still been pretty healthy up the Gulf Coast and that there's a refinery down in the East Coast, too, which also means that exports from Europe to New York harbor, less than a bit as well. Can you talk about the dynamics a little bit and whether they're having any impact at least in the near term on line space before the market [indiscernible]?

Yes, we have news, tell me when you've had enough. Things were very zeroed in on the what I call more of the macro stuff. I think it was a Rotterdam refinery that went down earlier in the week or the weekend, so that means less gasoline produced. That should mean less exports from Europe. We were seeing a decline in the exports from Europe into the harbor. They were heading down to the South Central America. So don't know that that's going to have an impact. The greater impact on the harbor is just continuing to see the inventory draws there. With line 1, Colonial have no longer an allocation. That means there's less making it into the harbor. As all the customers along the line are still taking what they did last year or more; so we're seeing less coming from the gulf -- we believe going from the gulf up to the harbor, and with the draws we're saying that we should get tighter. I think our bob [ph] got pretty tightly heard, earlier this week or last week. The refinery in Mexico that went down was on the West Coast. Those refineries in total have been running about 60%. I think Pemex [ph] publishes numbers once a month. So last report was 60%. Last winter, they were only running at 50% and that's when we saw the exports to Mexico jump from maybe 0.5 million barrels a day to 1 million barrels. They're back down now we think in the 500,000 to 600,000 barrel a day range. The refinery on the West Coast impacted our West Coast refiners, so much of the short fall they had in that refinery came out of the West Coast, not the Gulf. And I believe a bit of that, because I think it was something of a refiner, it was at 400,000 barrels a day. We think a lot of that was exported. So that is not been a factor in the Gulf Coast. The trend seems to be drawing down in the harbor, we're not seeing any more imports up there and steady to slight build in the gulf coast and we're not seeing any excess exports out of the Gulf.

Thanks, Mike. That was helpful. Then just turning to asset sales and the potential there. Can you maybe talk about which segment you're looking for? Are these sizable things or core things like Grand Mesa? If you can speak to that?

Sure. The Grand Mesa, I cannot imagine ever being on the table. So not in Grand Mesa. There are still an awful lot of upside on that pipe. We're actually looking at multiple segments. I think it takes something in the $200 million range to make the difference we want to make. So obviously you need a double-digit multiple to bring the leverage down significantly. We're looking at the moment and I think four of our segments, we have identified some assets and we are pursuing those opportunities. Yes. It's not gambling something on one asset. No. We're trying to be thoughtful about it, we don't want to unbalance our five segments, we don't want to eliminate one segment entirely, so we've identified those assets that have I think a lot of interest from other companies that we would not be giving up future growth.

Okay. Thanks, Mike. And then just in terms of hedging [indiscernible] oil at water solutions, I assume you want to be more than 25-30. It depends? Is it just a matter of washing the curve?

Yes. This is one, Trey could probably talk about a long time like I could about refined products. But it doesn't make sense. We think just hedge 100% all at one time. So we're going to layer into this. I think our budget was of around for the year -- it was 2,600 barrels a day.

Barrels, yes.

Yes. We're going to be higher than that because of the increased water that we're receiving. So let's say it's 3,000 a day, we hedged 25% of that. I know we had some orders in for between $50 and $51, but did not get transacted, but that would be a level for the next 25% and that we'd be at least 50% hedged. Trey?

And the idea, Gabe, is to step into the hedges over time. We don't see that there's any benefit really to hedging at $40. At $50 we are stepping into some hedges. Again, that's in-line with our budget. We can hedge up to 90% of our expected volumes for one year, 50% for two years and 25% for three years out. So we've started that program here recently and we're layering in positions at this time.

We're probably competing every other upstream company to the United States for hedges.

Which is probably why there's a bit of a cap at $50.

Yes.

At least you only have a couple of thousand barrels to do [indiscernible].

Exactly.

Right.

All right. Thanks, guys.

Your next question comes from the line of Lim Shen [ph]. Your line is open.

Hi. This is Matt Niblack. Thanks for the walk-through on what happened in the quarter. I just wanted to understand on the refined products guidance for the year. Are you assuming anything above your sort of minimum contracted rates for value of line space in that spread?

We are assuming that line space is essentially zero at this point in time. As Mike mentioned, we are doing things contractually and physically to make line space zero, so we put a floor on our contracts. Any contracts that are exposed to line space, we are buying the line space and getting paid with that differential. So that essentially negates the negative. We do have some potential to the upside. Our upside forecast for the rest of this year is between a penny and two pennies - all of that really in the third and fourth quarters. So zero in the second quarter and a penny each quarter thereafter.

And if that penny or two doesn't materialize, how much downside is there to the guidance?

The penny is only under discretionary.

I'm just getting my calculator out here, which is my head. We have bought that 100,000, so 20,000 a day x 42 x a penny x 180 days, 1.5 million.

1.5 million? The downside to your refined products, guidance for the balance of the year is only 1.5 million if line space never recovers?

Based on line space. Yes.

Based on line space. Right.

Are there risks or downsides to that guidance or is it pretty solid now to your contract structure?

There are still some variability in that business. We do some blending, we've got storage, inventory values can move a little bit. We try to be very conservative with guidance and continue to be and we're updating it real time. I think we've eliminated the vast majority, the volatility, the amount tied to line space has been essentially eliminated. Volume will also be a driver. We've seen robust volume and we expect that as demand continues to increase throughout the year. But those are the variable components, I think. Margins that we ultimately realize at the racks and the volume on those margins is what the driver is going to be. The guidance they gave was $3.25 per gallon, which is down from just over $0.05 last year and force them so it was in our original guidance.

So I put it another way is; we think we whacked the heck out of refined products, we've taken our line space to zero in the discretionary and $0.01 for the second and third quarter, we've reduced margins from plus $0.05 to $0.0325; so it's hard to imagine how it gets any worse. We do have some upsides on the renewable side that would be significant, so we think we've been pretty damn conservative and we have some upside.

Great, thank you.

[Operator Instructions] Your next question comes from the line of Jason Menda [ph].

Thanks for taking the questions. Just -- can you give us the size -- I don't think you have on the propane businesses acquired and how much of that is included in the 105 estimate for the year now?

Yes, too small -- small acquisitions. The cumulative was $25 million and $5 million of EBITDA is what we added to our guidance. And we're going to have those -- yes, we'll have those businesses through the heating season since we did not have them during the first quarter which is typically a breakeven or zero period.

Got it, great. So only five of the 105 is related to the acquired businesses?

Correct.

And then separately on the covenants [ph], obviously we had the revolver amendments; anything that can't be done and -- so how can you layout what kind of headroom you have on the covenants in the private placement note? And if there is any ability to get any release there?

Those are consistent with -- those have been in a minute and are consistent with the credit facility.

Great, thanks for your help.

Your next question comes from the line of Simon Curman [ph], your line is open.

Hi, good morning. You had mentioned potentially monetizing assets to help deliver; couple of questions, are they going to be size-wise similar to propane acquisitions or would they be more needle movers with regards to delivering? And also do you have any limitations or restrictions on potash use of proceeds as to whether we need to pay down any of your specifics that off borrowings versus you can just do it for any -- you can use it for any purpose. Thanks.

I'll handle the first one. There is no reason to do anything unless it is a needle mover. So yes, it's a needle mover we wouldn't mess, really mess around with anything in that $25 million range.

And on the second question, there is really not any requirements; again, our acquisition facility has paid zero. We would target our -- probably our most expensive debt to repay but there is no real requirements on what we have to do with those proceeds.

Thank you.

I am showing no further questions at this time. I would now like to turn the call back to the Company.

All right, well, so guys thank you very much. We will expect to have better news in the second quarter. Thanks.

Thank you.

Ladies and gentlemen, this concludes today's conference. Thank you for your participation and have a wonderful day. You may all disconnect.