NGL Energy Partners LP (NGL) 2015 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q3 2015 NGL Energy Partners LP earnings conference call. My name is Sue, and I will be the operator for today.

(Operator Instructions)

I would like to advise 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; the effect of weather conditions on demand for oil and natural gas, and natural gas liquids; and the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to financial results, and to successfully integrate acquired assets and businesses.

Other factors that could impact 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 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, 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 excludes 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 12/31/2014, which compares to a net income of $24.1 million for the same period last fiscal year. The primary driver of those 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 is $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 and 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 FY15. 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 calendar year 2015. Our EBITDA guidance for FY16 is in the range of $485 million to $500 million, based on current economic conditions. And with this, I will turn it back to Mike.

Thank you, Atanas. We will open it up for questions.

(Operator Instructions)

Abhi Sinha, Wunderlich Securities.

Quick one on operations. Last time you were expecting margins from the water segment to be 50% higher in FY16 than 2015, so how has that -- do you still maintain that to be enough? Of course, there's low volume. I think you were expecting double the volume in two to three years. Will 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 decreased, actually, as a result of more wells in the Eagle Ford and Permian which is where most of our activity is.

The disposal fees down there is less than it is in the anticline or the DJ. So going forward, we would expect to see volumes continue to increase, although we are all looking to determine what's the impact from drilling on flowback volumes. So if our volumes were consistent, then the margins will be equally consistent, and we would be very happy, so it's probably a decent projection going forward.

Sure. For the Magnum assets, can you talk about the cash flow ramp-up here? What's the cash flow for the first year and what's driving the ramp-up? Is it your [addition] or more expansion project baked into it?

Yes, 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, so that ramp-up will occur as the different caverns are completed, which will take about, I think we said, through 2017. Neutral on DCF in the first year, and then it will increase to a number that gives us a seven multiple deal.

Sure. And the equity assurance, would that impact distributions for fourth quarter FY15, I suppose?

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

Sure. The last one, if I could. Any update on the butane burning facility that you were talking last quarter?

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, and we'll have, obviously, a full quarter, full three months next quarter.

Sure. That's all I had. Thank you very much.

Darren Horowitz, Raymond James.

Mike, I've got a quick question for you on crude oil logistics, and I know a lot of this really hinges 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's a little bit more opportunity from a Gavilon asset perspective to get more asset optimization, maybe a little bit more profit? Or how do you think about 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 FY16?

Well, I'm glad you asked that question, because we are very excited about the change in our fade from backwardation to contango, and we have Don Robinson on the line who can comment too on the difference on the peak. Don can start out answering -- I would like to put that in perspective with what's going on on the water side with the skim oil. Don?

Yes, we basically, we entered into a couple of agreements for around 25 months for some of our storage, that was at real healthy rates versus what obviously had been in the past at Cushing. That's about a 1.3 million of the barrels we have there. Then we have about 3.5 million barrels at basically -- we are looking at from a contango point of view doing some shorter and longer-term deals to take advantage of that market. 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? Are we back up in that range?

Actually they are a little bit higher than that, so they are more in the $0.40 range.

Okay. 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?

Actually we were able to achieve those two-year rates around 25 months at those higher numbers, because obviously with the contango where it's been the last 30 to 45 days, we are looking at if someone wants to look at tankage, we are expecting that those terms to be longer, and not short-term deals.

Okay. Thank you.

Darren, just to add to that, I haven't seen what the curve looks like this morning, but I think for the next six months we are probably $1 a barrel. So to Don's point, we had have 3.5 million at Cushing, and 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 are probably going to lose, if the prices stay where they are 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.

I think that's something everyone should realize, that we have this natural hedge. When you have low prices, you are going to have excess supply, so storage is valuable. When you have high prices, then storage isn't as valuable, but our skim oil is very valuable. We will really emphasize more and more that having this portfolio of companies, five different segments, there's 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.

Gabe Moreen, Bank of America.

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

Excluding Grand Mesa, we're very comfortable, and that's why 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 a $600 million or so remaining to spend, and we would like to do, say, half of that in equity.

Got it. And I guess, Mike, are you looking at other sorts of transactions, versus where you would be able to issue equity for a substantial portion of any deal you do? Seems like you killed two birds with one stone potentially?

Yes, an obvious example would be if we come back and try to merge with TransMontaigne. That would be one where we would just issue equity for [A B self].

Got it. Then turning, speaking of TransMontaigne, how things are going in terms of the marketing business? Can you talk about -- I know you talked about getting third-party volumes into a lot of those facilities which were proprietary previously. Can you talk about how that is going?

Part of the transaction, we step in Morgan Stanley's shoes on the backstop, recall they had a take-or-pay on Florida, the Florida terminals in the Southeast, which is Colonial and Plantation, and the guys at TLC did a fabulous job finding a partner that replaced us in Florida. Press release some time ago, Metroplex was in. So we eliminated in FY16 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 allows us to sell the products through Colonial and Plantation, with the product that we -- with line space we purchased from Morgan Stanley, which I think was 130,000 barrels a day and we picked up the marketing contracts of something just a little less than that.

So we are very pleased with that transaction. Margins are actually better than what we had modeled. And, of course, lower prices for gasoline and distillates we would expect that there would be some increase in demand.

Last one for me, Mike, I think you put out slides recently at another conference talking about future distribution growth expectations, and it seems like it was little bit of an iterative process. In other words, your unit prices may be higher as your distribution growth is a little bit higher. Can you just talk about that, and is there any specific level you are looking at, any specific duration of time particularly considering the volatility?

Yes, previously we had indicated 10% growth in calendar 2015, 2016, 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 are back to $30. It didn't make any sense because we weren't going to get credit for 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 will just pay down debt and improve the balance sheet. So at this point around $30, we think 6% to 8% is fair, and if our unit price it was higher, significantly higher, then we would like to increase that rate.

Got it. Thanks.

Ethan Bellamy, Baird.

Mike, could you refresh us as to the current stakes at SemGroup, and if there's 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 back in mid-January, they were around 6 million-plus units down from 9 million, I think they had 9.1 million at the high point. So you know as much is I do there. 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, say the purchase price of 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. 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 will start and then Don can add to it. We haven't disclosed that. We still have one competing pipeline out there. I think it is 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 the length of our terms with the producers that we have on the pipeline are a little bit north of seven years.

On average?

On average, right.

So our shippers are five- to 10-year contracts, and in the Q, you can see we did indicate we are building a 20-inch pipeline.

And that's an increase, right?

Yes.

What capacity is spoken for?

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

All right, thanks. Appreciate it.

(Operator Instructions)

Michael Blum, Wells Fargo.

Just one question on Magnum. You said you are going to be drilling eight additional caverns. What's going to be the cost or CapEx associated with that? And when we think about the 7 times multiple in FY17, 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 we have room to drill are 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 a lot of dollars or not that many.

This is Jay Furman. The approximate per-cavern spend for additional caverns, was $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 somewhere in that $12 million to $15 million per cavern range is a good estimate.

So, Michael, that's a part of the answer. The other part would be, if we look at the total CapEx we are anticipating to spend in addition to the purchase price, I'm going to guess, Todd, Jay, another $50 million, $60 million, $70 million?

That's correct, Mike. Probably $60 million to $70 million incremental.

Okay. So you can divide that by seven, Michael and you will have your EBITDA.

Okay, great. Then can you also just talk more broadly, obviously we're seeing lots of announcements out of E&Ps cutting CapEx, laying down rigs. And can you talk about how you see that impacting the water business problem?

Yes. I think in the Q we also disclosed that our flowback water is approximately 20% of our total water. We expect to have half the rigs laid down. Some of the rigs, we talked to producers, we're already going to be laid down, because they were drilling from these super pads here more recently, so they can drill the same number of wells with fewer rigs, so rather than just a quarter or a third going down, we think half will go down.

And that would, in theory, relate to about half our flowback, which is 10% of our water. We are replacing that with a couple other initiatives, as I think we've talked about in the past, we developed some processes to dispose of solids for the producers. They are currently taking much of that to landfills where they are paying $20 to $30 a barrel. We can dispose of it at our well sites for much less.

And what we are trying to be is a solution, and not a problem. Meaning once the drilling and completion costs are hammered by the producers and lowered, then they are going to be looking at their lease operating expenses, which would include our disposal fee, which is relatively a small number, as you know, compared to their total. A lot of their expense on water disposal is related to water trucks and trucking, 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.

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 are anticipating offsetting the declines from the flowback.

And also the water is a very different business, in that, 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 will get some increased EBITDA to offset what 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.

Matt Niblack, HITE.

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 look 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 flows 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 terms are three years, Mike.

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

Jay, do you have thoughts on that?

Yes, it is really this business is built around the Western mountain region. Again being outside the Salt Lake City area, so the biggest customer base is your refiners west of the Rockies and then marketers, and the other support companies west of the Rockies. If you look at the regional growth in refining and the health of that industry, that's definitely our primary customer, versus it is not a big production-backed facility. So if you look at production risk and the impact of that, there's not the exposure there, versus it is really a 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.

That's kind of a normal term, if you look at Belvieu and Conway liquid storage, those contracts or anywhere from one to five years, and we obviously lease quite a bit of space in Conway ourselves.

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

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 useless, and that this portfolio is doing exactly what we had anticipated it would do. And when you have things that aren't so great in one segment, we have another one that's a natural hedge. Thank you very much, and 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.