NuStar Energy L.P.
Q3 2014 Earnings Call Transcript

Published: 1 Nov 2014

[Operator:]

Good morning. My name is Shurets, and I will be your conference operator today. At this time I would like to welcome everyone to the NuStar Energy LP and NuStar GP Holdings LLC third-quarter 2014 earnings call. [Operator Instructions] After the speakers, there will be a question-and-answer session. [Operator Instructions] Thank you. At this time I would like to turn the conference over to Chris Russell. Sir, you may begin.

[Chris Russell:]

Thank you. Good morning, everyone, and welcome to today's call. On the call today are NuStar Energy LP and NuStar GP Holdings LLC's President and CEO, Brad Barron; Executive Vice President and CFO, Tom Shoaf; and other members of our management team. Before we get started, we would like to remind you that during the course of this call, NuStar management will make statements about our current views concerning the future performance that are forward-looking statements. These statements are subject to the various risks, uncertainties and assumptions described in our filings with the Securities and Exchange Commission. Actual results may differ materially from those described in the forward-looking statements. During the course of this call, we will also make reference to certain non-GAAP financial measures. These non-GAAP financial measures should not be considered as alternatives to GAAP measures. Reconciliations of certain of these non-GAAP financial measures to US GAAP may be found in our earnings press release, with additional reconciliations located on the financial pages of the investor sections of our websites. Now let me turn the call over to Brad.

[Brad Barron:]

Good morning. Thanks for joining us today. As you may have seen in this morning's press release regarding our third-quarter results, the positive momentum from the first half of 2014 continues, as we reported improved results in all 3 of our operating segments, and we covered our distribution for a second consecutive quarter. We continued to increase our throughput volumes on pipelines across our system, including a 23% increase on our crude pipelines over the third quarter of 2013, mostly due to the outstanding performance of our South Texas Crude Oil Pipeline System. Our newly constructed dock in Corpus Christi, which became operational back in February. The completion of Phase 1 of our South Texas Crude Oil Pipeline expansion in May. And increased volumes on our Pawnee to Oakville line that we completed in the third quarter of 2013 continue to contribute to the increased throughput volumes we are seeing in our South Texas system. At the same time, our Corpus Christi North Beach Terminal also continues to benefit from these increased Eagle Ford throughput volumes. As I've mentioned before, our primary goal entering this year was to return to full distribution coverage in 2014. Based on our strong year-to-date performance, we've covered the distribution through the third quarter of 2014, and we expect to cover our distribution for the full year as well. Looking beyond 2014, we remain focused on identifying and developing the next set of internal growth projects that will allow us to continue to increase our earnings and cash flows into 2015 and beyond. We discussed one of these internal growth projects earlier this month in our press release about our non-binding letter of intent with PMI, an affiliate of Pemex. We're working together to explore a joint venture to develop new pipeline and infrastructure to transport liquefied petroleum gases and refined products from the US into northern Mexico to meet the region's growing demand for these products. The new pipeline terminal facilities, which we plan to integrate into our existing pipeline infrastructure, will deliver product to Nuevo Laredo and Burgos-Reynosa, Mexico from facilities in Mont Belvieu and Corpus Christi, Texas. Both companies are working diligently to finalize these agreements in early 2015, and we expect to be in a position to complete the assets and have them in service during the second half of 2016. We also continue to explore additional pipeline growth opportunities in the Eagle Ford Shale and other shale regions that could be synergistic with our existing assets, as well as several potential growth projects on the terminal side of our business. We will provide more detail on these projects as they develop over the next several months. Also at the end of 2013, we identified several non-strategic underperforming terminal facilities with assets we would like to divest. One of the assets targeted for sale was our interest in a non-strategic terminal in Mersin, Turkey, which we sold during the third quarter. With that, I'm going to turn the call over to Tom Shoaf, NuStar's Executive Vice President and CFO, so he can provide you with some additional detail on third-quarter results. Tom?

[Tom Shoaf:]

Thanks, Brad, and good morning, everyone. Before I get into the quarter's results, I'm happy to report that earlier this week we closed on our amended and restated $1.5 billion unsecured five-year revolving credit agreement. Under this new facility, the maturity date for the revolver has been extended from May of 2017 to October of 2019. This is great news for NuStar, as extending this facility to late 2019 provides us with a stable source of financing to help us fund our internal growth program over the next several years. In addition, interest rates on the new facility are slightly lower than our previous facility, resulting in $2 million of annual interest savings per year. Our EPU for the third quarter of 2014 improved 129% over the third quarter of 2013, to $0.64 per unit from $0.28 per unit, within our guidance range of $0.55 to $0.65 per unit. DCF from continuing operations available to limited partners for the quarter was $1.13 per unit, 28% higher than the $0.88 per unit generated in the third quarter of 2013. And again, within our guidance range of $1.05 to $1.15 per unit. Continuing strong throughput volumes in our pipeline and storage segments, as well as solid performance from our bunkering operations in the fuels marketing segment, contributed to the improved third-quarter results. EBITDA in our pipeline segment increased $85 million, which is $10 million higher than the third quarter of 2013. Within the segment, we experienced a 12% increase in total throughputs and a 13% increase in total revenue. Throughputs on our crude oil pipelines systems increased 23% to 472,000 barrels per day, as the segment continued to benefit from increased Eagle Ford throughputs, which increased 46% from about 175,000 barrels per day in the third quarter of 2013 to around 255,000 barrels per day in the third quarter of 2014. Throughputs on our refined products pipelines increased 3% to 514,000 barrels per day, mostly due to the increased production at one of our customer's refineries. For the third quarter, the storage segment generated $76 million of EBITDA, up $8 million from last year. Throughput volumes increased 10%, while throughput revenues were up 16%, due to increased activity at our Corpus Christi North Beach Terminal. Which continues to benefit from the increased Eagle Ford crude volumes shipped on the pipeline system. The segment also benefited from the second unit train at our St. James Terminal that came online in the fourth quarter of 2013. Our fuels marketing segment earned $8 million of EBITDA during the quarter, $17 million higher than the $9 million of negative EBITDA generated in last year's third quarter. Higher gross margins and lower operating expenses at our St. Eustatius bunkering operations drove the segment's improved performance. NuStar's G&A expenses were $25 million, or $6 million higher than the third quarter of 2013, primarily due to the fact that increases to our unit price also increase our compensation costs. Our interest expense, net of interest income, was $33 million, up $4 million from last year's third quarter. This increase was mainly due to higher borrowing costs associated with the August 2013 issuance of $300 million of senior notes. Our September 30 debt balances were $2.8 billion, while our debt-to-EBITDA ratio at quarter-end was at 4 times. On October 29, NuStar Energy's Board of Directors declared a distribution of $1.095 per unit, which will be paid on November 14. NuStar GP Holdings' Board also declared a third-quarter distribution of $0.545 per unit, which we paid on November 19. Now let me spend a few minutes talking about our projections for the fourth-quarter 2014. We project higher fourth-quarter EBITDA results in the pipeline segment than the fourth quarter of 2013, and comparable to the third quarter of 2014. Our fourth-quarter EBITDA results in our storage segment should be comparable to last year's fourth-quarter adjusted EBITDA results, but lower than the third quarter of 2014. Increased maintenance expense as the result of some project delays from earlier this year should have a negative impact on the fourth-quarter results to both pipelines and storage segments. Fourth-quarter EBITDA results in our fuels marketing segment should be comparable to both the fourth quarter of 2013 and the third quarter of 2014. During the fourth quarter, we expect G&A expenses to be in the range of $26 million to $28 million, depreciation and amortization expense to be around $49 million, and interest expense to come in at approximately $33 million. Based on these projections, fourth-quarter earnings per unit should be $0.40 to $0.50 per unit, while the distributable cash flow from continuing operations per limited partner unit should be in the range of $1.05 to $1.15 per unit. With regard to segment EBITDA guidance for the full-year 2014, we continue to expect our pipeline segment EBITDA to be $40 million to $60 million higher than 2013. And our storage segment EBITDA to be comparable to 2013's storage segment adjusted EBITDA. We expect 2014 EBITDA results in our fuels marketing segment to be in the range of $20 million to $30 million. We still expect our 2014 strategic capital spending to be in the range of $330 million to $350 million. However, we have reduced our projected 2014 reliability capital spending slightly, to $30 million, to reflect some delays on maintenance spending that will carry over to 2015. Based on these projections, we remain on track to cover the distribution for the full-year 2014. Now looking ahead to 2015 full-year guidance, we project our pipeline segment EBITDA to increase $25 million to $45 million over 2014 results, due mainly to the planned completion of the Phase 2 South Texas Crude Oil Pipeline Expansion and the NuStar 12-inch pipeline between Mont Belvieu and Corpus Christi, Texas. We expect to put Phase 2 of the South Texas Crude Oil Pipeline Expansion into service the first quarter of 2015, with the ramp-up an additional 65,000 barrels per day by September 2015. We also expect our conversion of the new NuStar 12-inch pipeline will be in service early in the third quarter of 2015, and ramp up to 67,000 barrels per day by September of 2015. We expect 2015 results in our storage and fuels marketing segments to be comparable to 2014 full-year results. During 2015, we expect G&A expenses to be in the range of $95 million to $105 million. With regard to 2015 capital spending estimates, we plan to spend $400 million to $420 million on strategic capital, while our 2015 reliability spending should be in the range of $35 million to $45 million. Based on these 2015 estimates, we expect to cover our distribution full-year 2015. And now let me turn it back over to Brad for his final remarks.

[Brad Barron:]

Thanks, Tom. We're very proud of what NuStar has accomplished during the first 3 quarters 2014, and we're excited about our plans for the future. With continued dedication from our employees, we're confident that our full-year coverage in 2014 marks the first step towards continued future success. As you can see from our 2015 guidance, NuStar is positioned to continue to cover our distribution for the full-year next year, and we're working on the next phase of growth that will allow us to further improve our financial results. At this time, let me turn it over to the operator, and if we could open it up to Q&A.

[Operator:]

[Operator Instructions] And your first question comes from Jeremy Tonet.

[Jeremy Tonet:]

Good morning.

[Brad Barron:]

Good morning.

[Jeremy Tonet:]

Congratulations on the strong quarter. I was wondering on the PMI JV – I was hoping you might be able to share a little more color on the project, in terms of ballpark potential spend and what type of EBITDA multiple you could see. Just any rough numbers you could provide would be helpful.

[Brad Barron:]

You know, we feel it's probably premature to talk about the specifics of that project. We're working with PMI to fully develop the scope, which we expect to have developed in the early part of the first quarter next year, and we're still nailing down the economics. So I'm hesitant to get too far into the details on that.

[Jeremy Tonet:]

Okay, fair enough. Shifting to South Texas, I was wondering if you could update us on what you see your producer customers doing and if there could be room for incremental expansion opportunities over there?

[Danny Oliver:]

We're definitely working some incremental expansion opportunities, where we've still got our Phase 2 expansion under construction, which as mentioned earlier, would go into service in the first quarter of next year. We've got several sizable expansion plans that are in the early stage of development. Just a little bit too early to discuss.

[Jeremy Tonet:]

Okay, great. And then moving over to Piney Point, we've seen some element of contango in the crude curve, and I was wondering if you guys were able to take advantage of that, if it was able to help you out at Piney Point?

[Danny Oliver:]

We're keeping a close eye on the market structure. Like you said, we've seen some contango in the Brent market, but it's not quite steep enough or long enough really to generate any significant interest in contango play yet. But it certainly looks like it may be heading that way.

[Jeremy Tonet:]

Okay. And then last one for me. Do you guys have any updated thoughts on the Condensate opportunity within your footprint, and any opportunities for you guys to capitalize on that?

[Danny Oliver:]

Yes, we're working with several customers in the Eagle Ford area in that regard. We've got a few customers in our system that are stabilizing crude out in the field. We already segregate several streams in that system, and were working with them in that regard.

[Jeremy Tonet:]

That's it for me. Thank you very much.

[Brad Barron:]

Thank you, Jeremy. By the way, that voice you just heard, that was Danny Oliver, who's are our Senior Vice President of Business Development.

[Operator:]

Your next question comes from Cory Garcia.

[Cory Garcia:]

Good morning, fellows.

[Brad Barron:]

Good morning.

[Cory Garcia:]

Coming at the Mexico JV from a bit of a different direction, a broader perspective, recognizing still that some heavy lifting to do in terms of your specific agreement. I was hoping you guys would at least be able to help us better outline the competitive landscape down in northern Mexico. I am admittedly less familiar with LPG dynamics down there, so really any color from a broader supply/demand balance, or really imbalance today that you guys see. And ultimately how that is going to progress over the next – call it 5 years.

[Danny Oliver:]

Sure. I think what we're competing against are trucking economics from Brownsville and other locations – the Brownsville area and other locations in Mexico. So there's a significant amount of demand for propane, diesel, some wide array to feedstock into their Burgos plant, and that's the demand that we're targeting. And we're targeting all that truck traffic and getting those trucks off the road, and replacing it with pipelines.

[Cory Garcia:]

Okay. So it's not even just simply organic growth just from the base level, it's also a little bit of replacement of trucks? What's the organic growth number should we be looking at, just on a year-over-year basis, once you guys have more penetrated and backed out that trucking barrel?

[Danny Oliver:]

You know, we certainly do expect to see some of that. The biggest chunk of the value of this project is going to be replacing those trucks. I don't have a good figure for you on annual organic growth, but there is a substantial amount of product being trucked around in northern Mexico, and that's the really focus of our project.

[Cory Garcia:]

Okay, that's very helpful. A different question all together. Another solid ramp in volumes in the South Texas system again, and just curious as how much further you guys can really push that in the fourth quarter, before you guys get to completion of Phase 2 early next year. Should we see a flattening, or is there a little bit more that you guys are going to see?

[Danny Oliver:]

You'll see some flattening in the fourth quarter. Our first phase of our current expansion, which is already in service, we've pretty much reached our max capacity there until the next phase comes online in the first quarter of next year. So you should see that flatten out in the fourth quarter and then throughout the year. Next year we'll be filling up the remainder of our expansion.

[Cory Garcia:]

Okay. Appreciate the time, guys.

[Brad Barron:]

Thanks, Cory.

[Operator:]

And your next question comes from teve Sherowski.

[Steve Sherowski:]

Hi, good morning. Just on your pipeline guidance for 2015, I think this same quarter last year you were guiding towards, if I'm not mistaken, $50 million to $70 million year-over-year growth. I'm just wondering what the delta is there with the guidance you just provided? And is that just largely due to a higher run rate coming out of 2014? Or is there something else involved?

[Tom Shoaf:]

It mainly has to do with the fact that when we gave that guidance, we had the Phase 2 of our South Texas Crude system all coming online at one time, and not accounting for the fact that it's really going to ramp up over the course of the year. That's the biggest portion of it.

[Steve Sherowski:]

Okay, thanks. And on the topic of crude contango, where do you think we need to see the WTI forward curve go to before you get pricing power and storage? And what percentage of your WTI linked portfolio is up for re-contracting over the next 18 months?

[Tom Shoaf:]

You have to make some assumptions on cost-of-money and storage fees. But I think you probably need to see something in the neighborhood of $1 a month. And it probably needs to extend out something like 6 months to generate a significant amount of storage interest and have enough in that contango to cover those cost-of-money and storage fees.

[Steve Sherowski:]

Got you. So $6 over 6 months?

[Tom Shoaf:]

$6 or something like that.

[Steve Sherowski:]

Okay, that's it for me. Thank you.

[Operator:]

And your next question comes from Brian Zarahn.

[Brian Zarahn:]

The $400 million to $420 million of the growth CapEx next year – can you provide a breakout of some of the bigger projects?

[Chris Russell:]

Yes, Brian. This is Chris Russell. Probably the biggest components of that are, we're going to be finishing up Phase 2 of the Eagle Ford project. That's a good chunk. We'll have some capital costs in finishing up the Houston 12-inch line, the conversion of that line. And then we've got some costs built in for the PMI project we've talked about. We haven't disclosed how much that project is yet. But we do have some costs set aside for that. And we also have some costs set aside for some other projects, primarily in the Eagle Ford that we're working on that we haven't announced yet.

[Brian Zarahn:]

Okay, thanks, Chris. And then just on that pool of projects that you're developing, are you seeing any impact from the pullback in crude prices from your potential shippers or customers?

[Brad Barron:]

No. We've not seen any movement on the producer or the ship side. At these price levels, we don't expect to see any movement at all.

[Brian Zarahn:]

Okay. And then on the Houston line, any update on contracting the remaining capacity?

[Danny Oliver:]

That will be affected by the PMI deal. But the deal that we have in place now are base contract with Oxy. It has that line about two-thirds full. We'll be adding to that with the PMI deal. And we'll have more details on those volumes around the first quarter of next year.

[Brian Zarahn, Barclays Capital:]

So if the PMI project moves forward, you think capacity could be fully contracted?

[Danny Oliver:]

I don't think we'll quite be fully contracted. We'll have a little room for growth still there. And we also have several other conversations going on about the propane movements down into Texas.

[Brian Zarahn:]

Okay. And then on 2015 CapEx, do you expect to finance that with your revolver?

[Tom Shoaf:]

2015 CapEx – yes, primarily with the revolver. I think for the most part, we will. We could be into the capital markets in some fashion in 2015, but for right now I'd say just model that.

[Brian Zarahn:]

Okay. And just the last one for me. On the heels of your Turkey divestment, any other non-core assets you're currently examining for sale?

[Brad Barron:]

Nothing significant or nothing that I would consider material.

[Brian Zarahn:]

Okay, thanks for the color.

[Operator:]

Your next question comes from Robert Zimet.

[Robert Zimet:]

Hello. I'm just an individual investor, and apologize if my question seems to be naive. But I'm not sure I understand the relationship between the price of oil and your lines of business – the profitability on your lines of business. Could you enlighten me a little bit on that?

[Brad Barron:]

Sure. It's a pretty broad question, but I'll give you – well, one answer, and addressing it from a crude oil production side, so US crude oil production side. If oil prices are high, the theory is that producers are going to produce more and they're going to ship more out across the logistics assets. On the flip side, if crude prices fall so far down that producers end up shutting in production, than less will come out across the logistic assets.

[Robert Zimet:]

Yes. And just as a follow-up to that, with the price of oil, especially WTI, going to new multi-year lows here, and all of the pundits indicating that the trends are for it to go even lower, has that been taken into account, with respect to your projections for 2015?

[Brad Barron:]

It has. And you know, I answered a previous question – someone asked something similar, if we saw a pullback. And I said we're not seeing producers cut back at these price levels. The way we view it is, even if prices fell further, they would have to fall significantly further than where they are. And it wouldn't affect the short term at all. People are locked into their production plans. If it fell significantly – and I'm talking about very significantly – than it might start to affect production plans further out beyond 2015. Another thing to keep in mind is that most of our volumes on our pipelines are contractually committed. So we have (multiple speakers) –

[Robert Zimet:]

Great. And just a last, again, follow-up question. Do the fracking operations in the United States, in the Dakotas and elsewhere – if they were to wind down considerably – not that I expect that, but there's been some reports about Saudi Arabia hoping that, that happens. That's one of the reasons that they're not cutting production themselves; they're hoping that the lower prices in oil will produce less production out of fracking. If that were to occur, would that have any impact on your operations? Or have you already answered that question?

[Brad Barron:]

Well, that's really part of that last answer. These prices that we are talking about and the pullback assumes that we're talking about fracking.

[Robert Zimet:]

Thank you.

[Brad Barron:]

You bet.

[Operator:]

Your next question comes from Wesley Whitehead. Wesley, your line is open. And that question has been withdrawn. Your next question comes from [Le Shamy].

[Unidentified Speaker:]

My question has actually been asked already. Thank you.

[Brad Barron:]

Okay, thank you.

[Operator:]

[Operator Instructions] And your next question comes from [Jane Japea].

[Unidentified Speaker:]

It's [James Shentil] from [Height]. I think I heard you say that you needed $1 a month for 6 months for WTI contango to be of interest to you guys. Do you have a similar figure for Brent?

[Tom Shoaf:]

I think it would be similar. I'm just assuming about maybe 7.5% cost-of-money and maybe something like $0.50 a barrel for storage, and to cover both of those, you need about $1 a barrel.

[Unidentified Speaker:]

I see. If we got to that point, what is the EBITDA potential, if we saw both of those?

[Tom Shoaf:]

Well, when our Piney Point facility – which is right now currently mothballed – but it's strictly a contango-use facility. When that facility – back in the days of contango, when it was fully utilized, we made $9 million a year at that facility, and it –

[Unidentified Speaker:]

How many?

[Tom Shoaf:]

$9 million. And it's mothballed today. So it gets significant. Not to mention that in the other areas where we currently have our tanks leased, the contango interest will support higher prices. It's a pretty significant benefit for sustained contango.

[Unidentified Speaker:]

Okay, thank you very much.

[Brad Barron:]

You bet.

[Operator:]

Your next question comes from Andrew Shirley.

[Andrew Shirley:]

Hi. I was wondering if you think you'll be in a position to give guidance on potential distribution growth beyond 2015 at some point during the year next year? And if so, what would be a reasonable expectation that would occur in the second half of the year?

[Brad Barron:]

We'll just see how the year goes. Like I said before, we're on track to continue our one-to-one distribution coverage, and then as we see projects layering and we have more visibility of the growth projects coming online, we might be able to give you some guidance as those develop.

[Andrew Shirley:]

Okay, thank you.

[Operator:]

[Operator Instructions] And your next question comes from [Jane Japea].

[Unidentified Speaker:]

Hi, good morning, guys.

[Brad Barron:]

Good morning.

[Unidentified Speaker:]

We saw in previous guidance that the South Texas system would bring capacity up to 200,000; the Phase 2 would bring capacity up to 2,000 barrels a day. And in this release, we saw that in third quarter, you've moved 255,000 barrels a day. And I'm just wondering if this new number is replacing the previous guidance. Or what are the numbers, or what's the difference in these numbers?

[Danny Oliver:]

Yes, Jane. The 250,000 barrels a day includes 2 other pipelines that we have in Eagle Ford service. Our big system, what we call our South Texas Crude system, is today doing about 175,000 to 190,000 barrels a day. And right there, we are at our capacity until our second phase of expansion comes on, which will allow us to get up to about 200,000 a day in the – say first half of the year. And then we'll ratchet up to about 225,000 barrels a day in the second half of the year.

[Unidentified Speaker:]

I see. Okay, great.

[Danny Oliver:]

We're doing close to 50,000 barrels – a little over 50,000 barrels a day on the other 2 pipelines.

[Unidentified Speaker:]

Okay. And are those going to see any capacity increases over the next year?

[Danny Oliver:]

They may be slight, but nothing real significant. They're small pipelines, smaller pipelines.

[Unidentified Speaker:]

Great. Thank you so much.

[Operator:]

[Operator Instructions] At this time, there are no further questions.

[Chris Russell:]

Okay. Thank you, operator. We'd once again like to thank everybody for joining us on the call this morning. If anybody has any additional questions, please call NuStar's Investor Relations department. Thank you.

[Operator:]

Thank you for participating in today's conference call. You may now disconnect.