NGL Energy Partners LP (NGL) 2015 Q2 法說會逐字稿

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'll be your operator for today.

(Operator Instructions)

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 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 and 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 form 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 or future events or otherwise. Also see the Partnership's website at www.NGLEnergyPartners.com, under Investor Relations for reconciliations of the differences between any non-GAAP measures discussed on this conference call and the most directly comparable GAAP financial measures.

All right. Thank you, and welcome to our second quarter call. I think we'll turn it over to Atanas to begin, and we'll go through some of the things in the press release, and then we'll give a more thorough overview of our businesses and how they're doing. All right, Atanas?

Thank you, Mike. Good afternoon, everyone. Adjusted EBITDA for the quarter is $70.4 million, excluding one-time acquisition costs of approximately $8.3 million, which is in line with the guidance provided during last quarter's earnings call. This compares to an EBITDA of $42.1 million from the same period last fiscal year, and represents an increase of approximately 70%.

NGL reported a net loss of $15.9 million for the quarter ended September 30, 2014, which compares to a 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 built a pipeline from Weld County, Colorado, to NGL storage terminal in Cushing, Oklahoma. We expect the project to significantly increase fee-based cash flow upon completion in 2016. We also announced plans to build a crude oil transloading facility, backed by executed producer commitments, capable of handling unit trains of 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 also acquired the lands and are beginning (inaudible) work.

We also completed the acquisition of TransMontaigne Inc. in July of 2014. As part of the transaction, NGL acquired valuable line space on the 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 expectations 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 reaffirmed NGL's adjusted EBITDA guidance of $425 million for fiscal year 2015, an approximately 18% distribution growth for calendar year 2014, with a 10% distribution growth thereafter.

With this, I will turn it back to Mike.

Thanks, Atanas. I would like to go over the segments briefly and give you a feel for what's going on. Starting out with the NGL logistics and retail, we've tried to be conservative. We will speak with respect to our $425 million projection for the year, or guidance, so we tried to be conservative here with respect to these two segments as compared to the prior year. We originally pulled back and within our guidance number, the EBITDA between $5 million and $10 million for these because of the cooler weather last winter.

Based on November weather, and the December, January forecast, which are 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. There is some upside here of 10% plus, but we'll see how it goes. If you have a business that (inaudible) like cold weather, your favorite colors become blue and purple, and if you look at the weather maps, they're just covered with blue and purple. We're off to a great start.

With respect to our pre-sold gallons, last year we performed very well for all of our customers. We didn't have to short-fill anyone on retail. We fully supplied all of our wholesale accounts according to their contracts. We didn't cut anybody off. We think that's why this year our pre-sold gallons at this point in time are 220 million, versus 100 million this same time last year, an increase of over 100%. These have good margins and will be pulled by March 31. It's another reason, in addition to weather, that we are feeling very good about our liquids and retail business.

We also have a butane rail facility that is coming onstream at the end of November. We'll have four months where we will be hauling quite a bit of butane in for gasoline blending, and we will get four good months in this fiscal year.

Switching over to refined products with TLP, we thought we'd give a little more visibility on what has now occurred since our attempt to merge the MLPs didn't work. It was unsuccessful. As you know, would we purchased about 130,000-barrels a day of line space on Colonial and Plantation pipelines from Morgan Stanley. We also acquired the refined products purchase and sale contracts of a similar volume, approximately 20% of the common units of TLP, and 100% of the general partner.

We had previously given some guidance that the first year, I think, was going to be EBITDA of about [$35 million], the next year, [$50 million], and then year three, [$70 million]. That's been accelerated. In the next 12 months, we anticipate the annualized EBITDA of about $45 million. We have some take-or-pay obligations on certain terminals, which were the Florida and the Southeast systems, where we stepped in Morgan Stanley's shoes, and these are going to be reduced by approximately $8 million here in the future, as we bring in new customers to take over our obligation in the terminals.

The opportunities we're pursuing, we talked a little bit before, but there is butane and renewable blending. The Brownsville terminal, we think there's some upside there. Then we're looking at how we can increase volumes in the Southeast. That's been a great transaction, great people. We have already taken a number of their people up to the NGL level, and they are now officers of NGL, which you can see on the website.

With respect to water, we've been very active in this segment, having nearly doubled our disposable volumes over last year. We began this year with capacity of about half a million barrels, and we will have 1 million barrels a day of capacity at the end of this fiscal year, in March of 2015. That's probably a year ahead of time, where we had hoped to get to a million barrels.

We have entered the Granite Wash recently, and we're very soon going to have a presence in the Bakken. Our plan is to increase our capacity to 2 million barrels a day within the next 24 to 36 months. Some of the current trends in water, we have doubled our capacity, are doubling our capacity in the DJ with long-term contracts. The disposal fees are steady to increasing. We had previously hedged our commodity price exposure through June of 2015, so we're not going to see an immediate impact from the decline in crude prices.

Producers are now focused on pipeline access to our disposal facilities. This is a relatively new trend. We have half a dozen to 10 projects now where we are connecting our customers by pipeline to our facilities. We expect our EBITDA from water solutions to increase at least 50% in fiscal 2016 over the current year.

Our crude oil logistics segment has been really the challenge, with the price backwardation and some pipeline project delays. Specifically, we have been impacted by, number one, the backwardation impact on our monthly inventories, which has cost us $1 million to $1.5 million per month. The inability is a result of backwardation to lease out our Cushing storage. We have signed up for space on a couple of pipelines to the Gulf Coast that have been delayed, and that's cost us about $1 million a month over what we thought we would make this fiscal year. Our marketing margins have been reduced by the backwardation as well.

On the plus side, our daily volumes have increased to 300,000 plus a day. The Cushing crude oil prices have gone slightly contango to flat depending on the day. The pipelines we are committed to will be in service, I believe, by the end of this calendar year. We will be getting some of that EBITDA back this year, and then next year of course, we'll have a full year.

One of the strengths of our business model is that when one segment experiences challenges, the others can offset the temporary decline, so we continue achieving our annual EBITDA guidance which is exactly what's happening this year. We do have several opportunities to actually exceed our guidance. At this point, we'd like to see the weather develop and the impact on the crude business before we increase our guidance.

Finally, the crude logistics crew, led by Don Robinson, from the Gavilon merger, have brought us the Grand Mesa pipeline project out of the DJ and crude oil (inaudible) facilities serving the San Juan Basin. These are big projects for us. It will be decreasing the percentage of our business, even though we are increasing our marketing where it makes sense, it will become a smaller piece. It 's also going to dramatically or significantly increase our fee-based business. With these longer-term contracts on these projects, we're also getting credit-worthy customers.

I think all of this leads us to feel that our 10% future distribution growth is very visible. You can see where it is coming from, without any further acquisitions or internal growth past what we have this year, and what we're going to achieve over the next two years. With that, why don't we open it up for questions?

(Operator Instructions)

Your first question comes from the line of TJ Schultz with RBC Capital Markets.

Hi, guys. Good afternoon. 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 you get to 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? Just some color on what else is going on beyond just the opportunity you saw in Florida?

Sure. David Kehoe's on the line, and he has responsibility for all of the refined product, David, you might go into what we're doing in Florida with butane or Brownsville, other places?

Sure. We have some opportunities in Florida outside of what we have leased out. We're looking at expansion projects there around butane blending as Mike mentioned as well as some conversion of tankage from current live products, still live products, but into some jet fuel and some repurposing of additional tanks. Then within the Southeast system, we're evaluating a project to expand some of the facilities on the Southeast.

Then with Brownsville, we've got the expansion opportunities of crude oil and refined products. We are looking at each of the segments, if you will, of our various locations, whether they be on the River Florida, in Midwest, and we've identified what we feel like are some very strong organic growth potentials behind the existing facilities.

There was a period of time under the previous ownership that the expansion and growth opportunities were considered on an ongoing basis, so we've backed up and started looking at that. The business model will be the same as [we continue to] -- as NGL continue to -- will look to diversify our customer base, and expand out the tankage and/or change the product mix in the terminals. We think that adds to significant growth.

Okay. Thanks. 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 stand until the end of the year.

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 will offset some of the 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. The increase in the liquids segments would be a plus to the $425 million. We feel pretty good about the water and the crude based on the $425 million.

Just to clarify, so that $425 million includes that accelerated cash flow that are you 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. Then just lastly, on the distribution growth guidance at 10% annual growth that you're targeting, what is 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?

We would decrease from a [1.5] to, we'd have to look at it, but maybe a [1.2], [1.25]. Our goal is to get 60%. We can see 60% fee-based once Grand Mesa is complete. We're probably two years or so away from that kind of a coverage ratio.

Okay. Thank you.

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

Hi, guys. Good afternoon. Mike, I had a couple 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?

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. Do a million barrels of capacity. Let me think how many wells. That's going to be 50 wells, 50, 60 wells. Let's say average facility is 6 million, 7 million. You're 300 [million], 350 [million] on water, and some of them, we're probably going to double that on crude. It is probably two-thirds crude, one-third water.

In terms of the aggregate cap spend, is it still fair to assume, what Atanas outlined, for this fiscal year, $500 million would be the expectation for fiscal 2016 too? Or is there going to be a little bit of upside to that?

There will be upside to that.

All right. That makes sense. 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, do you have thoughts?

You bet. We have other opportunities, and we're working diligently on them. There are probably fewer in the San Juan, although there is one other asset opportunity we're looking at there. The remainder of them, we're really focusing around the Gulf Coast and the Canadian market.

We have both rail and pipeline synergies in both of those two locales, and we shouldn't forget the Permian as well. 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'll have additional (inaudible) pipe and rail facilities with long-term customer in those three geographic regions.

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

If I take that over a two- to three-year time frame, I would say you're looking at $750 million, maybe just a little north of there.

Okay, wow. Thank you very much. I appreciate it.

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

Your next question comes from the line of Abhi Sinha with Wunderlich Securities. Please go ahead.

Hi, and I apologize if you've already answered this. I'm just trying to understand if you can provide any update. There's a replacement of the lost transportation customer that you have mentioned in the last quarter that was costing you around $500 million or so in EBITDA every month. I'm just trying to get an update on that, if you have any.

Sure, that was $500,000 a month, we did lose to that customer. We're just slowly repositioning our vehicles in other basins as we get the additional volumes. We are getting those volumes. As we said we are up to $300,000 plus a day, but it just takes time. You've got to relocate and find drivers. David?

Yes, I was just going to mention that the biggest challenge is around finding the drivers. The trucks themselves are easily portable, movable to 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. That's our biggest challenge, is finding enough drivers.

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. We think it may benefit, we could build our pipeline [with river rock] perhaps, at a lower cost than otherwise, if crude prices were still $100 a barrel.

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

Operating unit expenses have increased in the water business? Is that the question?

Yes, sir.

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

We should be lowering our per unit cost. It depends somewhat on the mix. Our costs in parts of the Eagle Ford are higher than, say, the DJ, but we've been working hard on our chemical costs, to get the benefit of larger, [supplier] demand from our water business.

We've been looking at putting in some new systems, so we can reduce the labor costs. That will continue to actually decline over the next couple of years on a per unit basis.

Okay. Sure. That's all. Thank you very much.

Your next question comes from the line of Michael Blum with Wells Fargo. Please proceed.

Thanks. 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 spot business? You made an interesting comment about the change where you're hooking up pipelines directly. I would assume that that keeps that customer captive to your system, but I just wondered if you could just talk about that whole concept?

I will start out, and then Jim Burke is on the line. I will ask him to jump in. Obviously, we have Pinedale's contracted. The DJ is contracted, so that will be a fourth of the million barrels that we were talking about, capacity-wise.

Then we had the customer in the Eagle Ford, where we have that volume commitment of a minimum of 50 a day. We're actually getting almost double that, from that customer.

You're right; the pipes are great. It takes trucks off the road, and we can make perhaps a little higher margin because we're sharing a bit of that truck costs the producer no longer is paying. All in all, Jim, what do you think we're contracted?

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

We're seeing the trend is that we think the producers are seeing value in a public Company that has financial strength. Building these pipelines, in Texas, the model, we're dealing more with the trucking companies, and billing them. We've now gotten quite a few of our relationships where we're billing the producer directly, and then they are paying the transportation, so it is moving them in the right direction. This is what we thought. It's just going to take some time.

Okay. That's very helpful. Thanks. Then just one other question on that, I'm 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 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 is both. We are making an acquisition in the Bakken. It is not a big one, but it's two wells. That's the acquisition side.

We're not buying much. We would much prefer to drill our own, but that is the first presence we will have in the Bakken. We found a nice couple of wells to start from.

We are moving into, with our customers, into new areas, so it is not stealing someone else's water, but the [Eagle Bine], the Delaware. We moved over into the Granite Wash. It's really new areas of production, and following our customers, which is great. Then there is, I think we're getting water that perhaps one of those two competitors because of our reliability in being a public Company. Any other thoughts, Jim?

Yes, Mike, I think that because of our size, being a dominant player, it is so much easier for some of these 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, or location by location. A lot of the large independents do like the fact we're a strong public Company, but also because of simplicity for the basins. The operators can call up and make one call, and we can service almost all of their needs in a lot of the basins.

Okay, great. Then on the Grand Mesa project, I think you said you are not going to tell us what the capital cost is, but I'm 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? Of the 130,000 a day, how much of that has been committed, and does that get your minimum return and then there is upside? Just trying to get a little more flavor around that.

Sure. Let's see. I'm trying to think through all of your questions. The completion first, I think we've indicated the middle of 2016. We already started acquiring right-of-way. We are on target to hit that.

Cost, this sounds silly to me, but it is all downhill so we don't necessarily have a lot of pump stations which cuts down on the cost and the power needed. If we could end up return-wise, in the six to eight multiple range, I think that would be a great project.

Okay. 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'd contemplate an offer in the future, but at the moment, we wouldn't have any interest, due to just really where the unit price is.

Okay. Great. Thank you.

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

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

David, do you have a flavor for that?

We're starting to get some interest in storage rates and [piecing up] the tankage now. The Gulf Coast is somewhat filling up. (inaudible) with Cushing, if we can get into a little stronger contango market, we think 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 that $0.25 to $0.35 range.

Got it. Then just coming back to the water business, can you just give us a feel for what is actually your direct commodity price exposure, realizing you're hedged through 2015, 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 a smaller or bigger oil cut or maybe you keep less of it? Could you just give us a feel for where that commodity exposure is?

Ted, we've never talked about the oil cut. It moves around on us. It tends to move down and not up. I think we will go back and look to see what that is and maybe we will talk about it on the next call. No, for the rest of this year, and part of next year, we are not going to see a decline.

Right, because of the hedges. Okay.

Right.

Fair enough. 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?

You should be ratable. We're not going to have a lot of seasonality around the business.

Okay. Great. That's it for me. Thanks.

Thank you.

(Operator Instructions)

Your next question comes from the line of Matt Niblack with HITE. Please proceed.

A follow-up on a couple of those questions in the water business. The first question is about the revenue per barrel came down quarter over quarter, just commentary on that, and if it has to do with the oil cut and if that's the pre-hedging revenue?

Secondly, if you can 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?

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

If you look at the margin itself, the margin itself is materially the same as it was last quarter. You really ought to be looking at the (inaudible).

Yes, we get to the same returns and margin, but you will have perhaps a lower revenue in Texas because your costs are lower.

Okay.

Then rig count, what we're anticipating, we don't really look at our business as a real scientifically, I guess, trying to calculate anything per rig, but we're anticipating that the upstream guys will be somewhat limited by their cash flows.

We'll see them cut back their expansion plans perhaps for next year, to a level of duplicating what they did this year. We would not expect to see an impact on our business unless the rig count is declining over what it was last year.

In terms of the base business though, if we were to see a rig count decline, isn't the water business 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 count can impact your flowback and not your produced. Certainly as the producers cut their rig count in half, we're going to have, in theory, half as much flowback water.

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.

Flowback is going to be probably, what is flowback? We ask ourselves that, and it is like you trust everyone to say, this is flowback water. Sometimes we have a two-tier pricing for flowback and produced, so it's flowback water the first three months coming out of the well, [for] six, [first] two. After that, there isn't any. It's going to be, as we get bigger, the flowback percentage drops, because the number of wells being drilled stays the same. It's going to be a smaller percentage of our total volume.

Right. The portion of the base revenues that are really impacted by rig count directly is somewhere south of 50%, and declining over time.

Right.

Is that a fair statement?

Hey, Mike? This is Jim. I think I'd add a couple things. First of all, in some of the basins we are at capacity right now. For example, the DJ, we're at capacity.

We're trying to keep up right now by building several facilities all at once. As far as utilization, we're very high throughout the entire business unit.

The other thing I like is we're doing a lot more than just the oil cut, the fee, and recycling in some cases. Now we're into fresh water, and we're way down stream, as far as taking care of the solids, the bottoms and the drilling muds and things like that, which are high margin. We've got more of a full slate. We're diversifying our approach if you will to that produce with some very high margin items.

Great. Thank you.

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. Thanks for your time, guys, and your good questions. We will talk to you next quarter.

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.