NGL Energy Partners LP (NGL) Q4 2015 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Q4 2015 NGL Energy Partners LP Earnings Conference Call. My name is Whitney, and I’ll 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 Instructions]. As a reminder, this call is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Mike Krimbill, CEO of NGL Energy Partners. Please proceed.

Thank you for joining us today. 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 any forward-looking statements. These factors include the prices and market demand for natural gas liquids and crude oil, the level of production for crude oil and natural gas, the effect of weather conditions on demand for oil, gas, natural gas liquids, 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 undertakes no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. Please also see the Partnership’s Web site at www.nglenergypartners.com under Investor Relations for reconciliations of the differences between any non-GAAP measures discussed on this conference call and the most directly comparable GAAP financial measures. Thank you. So we will get started. I’ll turn it over to Atanas for summary of the results.

Thank you, Mike, and good afternoon, everyone. Overall, we’re very pleased with the results for our fiscal year 2015. Adjusted EBITDA for the fiscal 2015 year EBITDA is 443.3 million, excluding one-time acquisition costs of approximately 23.2 million. This compares to an EBITDA of 270.5 million for the same period last fiscal year, which represents an increase of approximately 64%. NGL reported net income of 29.9 million for fiscal year ended March 31, '15 compared to net income of 48.8 million for the same period last fiscal year. The difference in net income was attributable to additional expenses related to acquisitions completed during the year, which increased our operating depreciation and interest expense. In our earnings press release, we outlined some of the accomplishments during the past fiscal year. Most notably, we began construction of the Grand Mesa Pipeline, a 20-inch crude oil pipeline that originates in Weld County, Colorado and terminates at NGL Cushing, Oklahoma terminal. We completed a successful open season in which NGL received the requisite support in the form of ship-or-pay volume commitments from multiple shippers to begin construction of the pipeline system. Presently, we have already purchased 60% of the right-of-way. On February 9, 2015, we closed the acquisition of Sawtooth Caverns, the largest underground natural gas liquids storage facility in the Western United States. The facility will ultimately hold 10 million barrels in eight caverns. Both Grand Mesa and project Sawtooth will significantly increase our repeatable fee-based cash flow and help NGL Energy Partners to get to two-thirds fee-based EBITDA within the next 24 months. We also completed a successful integration of Gavilon and TransMontaigne Inc. At the beginning of the fiscal year 2015, we had indicated our expectation to incur approximately 30 million of maintenance CapEx. For the fiscal year 2015, we spent 34.6 million and that excludes 6.1 million of TLP maintenance CapEx. Interest expense for fiscal '15 was 95.5 million excluding TLP interest of 5.4 million and non-cash interest expenses of 9.2 million. Distributable cash flow for fiscal '15 is 313.2 million. At the beginning of fiscal year '15, we also announced our plans to spend about 500 million of growth CapEx in acquisitions. Our actual spend was approximately 1.4 billion excluding 9.2 million of TLP growth CapEx and acquisitions accounted for approximately 1.2 billion and growth CapEx accounted for 160 million. For fiscal 2016, we recently provided EBITDA guidance of 500 million or greater. We reiterate that guidance. With respect to maintenance CapEx, we expect to be in the range of 30 million to 35 million for fiscal '16 and we anticipate growth CapEx and acquisitions of at least 500 million. We also reaffirm our distribution guidance of 6% to 8% for calendar year 2015. I’d also like to add some color to our operating segments to highlight our year-over-year performance and growth. For crude logistics, volumes were up 82% year-over-year primarily driven by Gavilon, which we owned for the full 12 months of the fiscal year. Margins compressed due to the backwardation in the crude oil markets for the first nine months of the fiscal year, and the significant drop in crude prices. In addition, our storage at Cushing was underutilized as the market was in backwardation and we were not able to lease out the third parties until the end of the fiscal year. In water solutions, we’re continuing to grow that business significantly, expanding our capacity to 1 million barrels a day at March 31, 2015. Average volume for fiscal '15 was 382,000 barrels a day versus 172,000 barrels a day the previous year, an increase of 122% year-over-year. And our current run rate is approximately 600,000 barrels a day. For our liquids business, volume was 2.1 billion gallons versus 1.9 billion gallons last year. The increase of 10% year-over-year was driven by the cold finish to the winter season and margins were similar to last year. Our retail propane business continues to outperform our expectations. Volumes were 169 million gallons versus 162 million gallons, which is an increase of 4% year-over-year. Margins increased to $0.98 versus $0.96 over the same time last year and increased 3% year-over-year, which is mostly attributable to the cold winter, especially in the northeast region. We also experienced net customer gain for the year. Finally, our refined fuels business has grown dramatically with the acquisition of TransMontaigne Inc. Volumes for fiscal year 2015 were 186,000 barrels a day at an average margin of $0.04 a gallon versus $0.02 a gallon in our legacy refined fuels business. With this, I’ll turn it back to Mike.

Let’s open it up for questions.

[Operator Instructions]. Our first question comes from the line of Brian Zarahn with Barclays. Please proceed.

Good afternoon.

Hi, there.

Can you repeat on the water solutions business, what the volumes were?

Yes. So the average volume for fiscal '15 was 382,000 barrels a day, so approximately 400,000 barrels a day versus 172,000 barrels the previous year, so that’s over 122%. And we’re at 600,000 right now.

And then obviously the ramp up from the first half of the year, can you talk a little bit about maybe in the fourth quarter what you saw in terms of the mix of volumes in your different basins just from a high level? So which basins were stronger and weaker?

Well, with respect to basins, if you look at the DJ where our utilization there is close to 100% and most of those volumes are based on acreage dedications. But if you look at our growth during this past fiscal year, it’s primarily been in Permian and the Eagle Ford. So we have significantly expanded our volumes in Texas. So every basin is odd although it’s not same-store, it’s adding the additional wells that we drilled during the year.

Okay.

So we have not seen a – go ahead.

Go ahead, Mike.

I’ll just say we have not seen a falloff in water volumes. Probably some of you have heard it at conferences, we expect to dilute some volumes due to rigs being laid down and flowback water. We believe about 80% of our water is produced in 20 flowbacks, so we thought we’d lose 10% of our water but we haven’t due to producers – many things but producers have – apparently we’re retaining some of their producer water, diluting and use it for fracking and obviously they can’t keep as much water. So we saw more produced water coming to our facilities replacing the flowback. And then we’ve been doing some things where we’re handling solids now and putting in some water pipelines, so we’re getting more water than we were receiving before. So we’re up to 600,000 a day and our capacity is up to 1 million barrels a day.

I appreciate the color. In terms of commodity prices, if oil prices stay in this range, how do you view that for your water solutions business for fiscal 2016?

Yes, when we were looking at prices below $50, we estimate the impact to be at least 40 million reduction in EBITDA but now we’ve come back to 50s and the out months are 60. So it’s going to be less of an impact than that.

Okay. And the last one from me, a lot of M&A announcements today, just curious if you look at Bridger transaction in terms of the – seems like some of the assets were match what your current business mix is, so just curious your thoughts on either that or just the general M&A environment?

A couple of thoughts. We did not look at it. My impression is there was a fair bit of marketing attached to that. And obviously we’re trying to – we are moving more into long-term contracts, fee-based. The M&A market in general is I’ll call it uneven. In some areas, I think in crude logistics, for instance, if you’re trying to buy something it’s still double-digit multiples. If you’re typical seller is a private equity firm, they don’t need to sell, they don’t necessarily have a lot of debt and worry about leverage or covenant like the rest of the public companies do. In other areas, retail propane is pretty much the same as it’s been and hasn’t changed significantly. I think water has gotten I’ll say realistic with values, so the skim oil is worth obviously a lot less and prices have fallen. So I think in a couple of our segments, we’re seeing the M&A market return to normal and others are still I think overvalued. But another advantage of having multiple segments like we do, there’s always something going on in one or two.

Thanks, Mike.

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

Hi, guys. A few questions here. First, can you update us on Grand Mesa and commercialization and what kind of utilization you’re seeing on the pipe so far, and maybe give us the most recent thoughts on timing?

Yes, no change on timing. We expect to be in service by the end of September '16. Obviously, we haven’t said anything about who the shippers are yet but we did upsize from a 16-inch to a 20-inch, so you can – that implies we needed more space for capacity than a 16-inch would provide. 60% of the right-of-way is purchased, 90% is surveyed. We ordered the pipe that gets delivered in November, I believe, so we are actually on or slightly ahead of schedule, which is good. This weather can set you back. Recently we had a two or three-week delay and we’re putting in 240,000 to 250,000 barrels a day crude storage tanks in Cushing to handle the batches, because our pipeline is – the Grand Mesa line is a batch system where the producer puts it in, in the DJ and then get back their specific crude at Cushing. So we’re having to put in a few 250,000 barrel storages. That’s been delayed three weeks due to weather. It’s been raining quite a bit here. But we started it in plenty of time thinking maybe we can use it to take advantage of some contango while we were waiting for the pipeline to be complete. So we’re actually a little bit ahead of schedule at this point.

And you expect to tell us about customers later this summer?

Later this summer, right. We still have some negotiations ongoing and soon as we wrap those up then we will be forthcoming with who our shippers are within the confidentiality agreements we’ve signed.

Okay. Did you say Atanas that you had net customer gains in retail propane and if so, is that on a same-store sales basis or is that inclusive with M&A?

No, that’s on a same-store basis and that doesn’t include any of the acquisitions which we have during the year.

Could you talk about what’s going on in that market? I mean that’s obviously off the trend line from degradation in that market longer term. I’m just curious what’s driving that?

This is Mike. We only had $0.02 gallon increase in our margins even though we had a very – really second back-to-back cold winters. And I think – I know our strategy and I think the result is we don’t have net customer losses. We price more to the mom and pop, so we don’t want to see our margins increase 20%, because we know we’re going to start running off the customer. So I believe it’s more – it’s service obviously. You don’t let people run out and you’ve got to price as close as you can to the mom and pop, so you don’t lose customers.

So do you think that’s market share gains or is the market up in total in there as you service?

We do have some conversion of heating oil to propane in the northeast, so that could be what it is. We don’t necessarily try to go out and steal someone else’s customer, but we just provide good service and good pricing and then the phone rings.

So is it safe to say that these below net to the customer propane prices are seeing some elasticity demand there?

It’s tough to say because the weather got colder at the very end of the winter. We had some snowstorms in March, April up in the New England area, so it could have been a degree-day related. Although at these low prices, I think the hubs are now – Conway and Belvieu are around $0.50. But at this time last year they were a buck, over $1. So our customers try to conserve more. That would just be anecdotal but at lower prices, they’re probably not as concerned about saving money if their bill is lower than it was the prior year.

And are you locking in barrels for next winter now or is it too early for that?

It all depends on what happened in the demand. We’re not locking anything in until the customer locks in with us, as you know, so we have not rolled out our pre-buy program yet. So I don’t think we’re filling up our storage. Atanas, do you?

No.

No. That’s a no. We’re not filling up storage yet.

Okay. Last question for me, sorry for the list [ph] here. Are you thinking about re-hedging the skim oil exposure here?

Yes. We’ve already hedged out I think part of – all of it through September. And was there a little in October or not? No. Okay, we’ve hedged out through September.

Okay. Thanks very much.

Yes.

[Operator Instructions]. Your next question comes from the line of Miles Barnett with HITE. Please proceed.

Hi. This is actually Matt Niblack with HITE. Congratulations I guess in your solid execution here. On the Bridger asset, did you see that deal and have an opportunity to look at it? And if so, why didn’t you pursue it?

We did not see it.

Interesting. And then just on Grand Mesa, it sounds like it’s safe to say that the negotiations have gone quite well overall and you’re almost more in wrap up mode at this point. Is that a fair statement?

Yes. We only had one open season and we made sure we had sufficient take-or-pay or ship-or-pay commitments. So that is correct.

Great. Thank you.

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

Hi, Mike. A couple of quick questions for you. I want to go back to your comments around the storage at Cushing, the opportunity to kind of capitalize on contango. So if we think about the 7.5 million barrels of storage that you have, you back out the 3.6 of lease capacity and then further the 1.3 that’s subleased, the way we’re looking at the math you’ve got about 2.3 million barrels and a portion of your 4 million barrels of owned capacity that you have, let’s just say the opportunity to better optimize. Can you just talk about how the market looks, maybe the carry trade July, August, or how are you thinking about fully optimizing that capacity?

Sure. When we cut through what we have subleased, so I think on a prior call we had a portion of what goes back to Rose Rock with 1.4 million barrels --

1.3.

1.3 million we leased out at about $0.42, $0.43 earlier in the year, which we didn’t want to gamble everything on contango. You’re right, we got 1 million barrels that went into the Glass Mountain JV of that, and then we had leased out some others. But then we had storage and other parts of the U.S. with some of our terminals. So in total, we’ve got say 4 million-ish barrels that we can play the contango on. And then we have our inventory on top of that that is obviously benefiting from rising prices. So, that said, the contango started a little bit in March. I think we got about $1.8 million or $2 million in March on contango. More importantly, we stopped losing money on falling prices. So, let’s see, in April the contango came on a little higher, I’m not sure where it was, but I know May, June and July were the big months where we saw contango over $1 per barrel. It’s now of course fallen off and it’s been I think $0.30, $0.40 for August and kind of stays at the level down to maybe $0.19 or $0.20. What we think is going to happen – originally we had hoped to see some kind of a one or two-month super – maybe some mini super contango, it did not happen. The storage was perhaps full, but it wasn’t overflowing at Cushing. But we do think we’re going to see some production come back in the shale, because folks can go out and lock in $60 crude. So we may have another shot at a more meaningful contango say in October.

Okay. Just looking at your existing asset base, where do you think that threshold is? Is it 60, is it maybe a little bit higher, maybe three to six months out where your producers start picking up the phone and it’s almost exponential, or where do you think that pricing inflection point is?

You mean if they start drilling or putting rigs back to work?

No, that they’d start locking in the forward curve and hedging forward locking in that spread?

I don’t know. We’d have to check with our crude guys. I did not ask that.

Okay.

I can’t tell you.

Yes, it’s no problem. I was just curious. Last question from me, I want to go back to a comment that you made around the refined products business and specifically I’m thinking about Colonial and Plantation. Obviously, that’s a positive. Correct me if I’m wrong, I thought you had about 130,000 barrels of line space. So again, in the same seam of optimization here, how do you think about that? Where do you think that could transition over the next six months and how much more of a downstream upside from optionality does that give you?

Those are a lot of questions. Yes, we purchased 120,000 a day of contracts from Morgan Stanley. We have been able to purchase a little more Line 1 space, the gasoline line that’s on allocation. On those lines I think we actually have over 400,000 barrels a day of line space, but that would include the distillate line. It’s going to be interesting because we’re seeing an increase in motor gasoline demand. Obviously, it can only get so much through Colonial and Plantation. So we think the margins are going to remain strong. Hopefully, we’ll see some increase but what we’re focused on is butane blending. We have exclusivity on the southeast terminals, a TLP we’re going to get into Collins/Purvis with some newbuild their doing. So we’re spending a little more and I guess we’re seeing some upside on the blending side, which under Morgan Stanley they hadn’t pursued, they being TLP. We’re also seeing some increases in Brownsville but that would be accruing the TLP.

Okay.

Any other thoughts, Atanas? What we’ve really tried to do is get all the internal growth projects that TLP has that they weren’t pursuing and get them moving on those. So certainly, for instance, if there’s more butane blending we will hopefully be the successful supplier of butane, so we’d make money on that side of things in our liquids business and then TLP and ourselves would benefit from the blending in addition.

Okay, that makes sense. Thanks, Mike.

There are no further questions in queue. I’ll now turn the call back over to Mr. Krimbill for closing remarks.

Great. Thank you guys very much and we appreciate your interest and we’ll see you in a few months. All right. Thanks.

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