NuStar Energy LP (NS) 2011 Q1 法說會逐字稿

Good afternoon. My name is Tiffany, and I will be your conference operator today. At this time, I would like to welcome everyone to the NuStar Energy L.P. and NuStar GP Holdings, LLC first quarter 2011 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions). Mr. Russell, you may begin the conference.

Thank you. Good morning, everyone, and welcome to our conference call to discuss NuStar Energy L.P. and NuStar GP Holding, LLC's first quarter 2011 earnings results. If you have not received the earnings releases and would like copies of each, you may obtain them from our websites at nustarenergy.com and nustargpholdings.com. Attached to the earnings releases we have provided additional financial information for both companies, including information on NuStar Energy L.P.'s business segments. In addition, we have posted operating highlights and fundamental data for our asphalt operations under the Investors portion of the NuStar Energy LP website. If after reviewing the attached tables and operating highlights you have questions on the information that's presented, please feel free to contact us after the call.

With me today is Curt Anastasio, CEO and President of NuStar Energy L.P. and NuStar GP Holdings, LLC, Steve Blank, our CFO, 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 certain statements concerning the future performance of NuStar, and other statements that will be forward-looking statements as defined by securities laws. These statements reflect our current views with regard to future events and are subject to various risks, uncertainties and assumptions as described in NuStar Energy L.P. and NuStar GP Holdings interim reports on Form 10-K for the year ended December 31, 2010, and subsequent filings with the Securities & Exchange Commission. Actual results may materially differ from those discussed in these forward-looking statements and we undertake no duty to update any forward-looking statements to conform the statements to actual results or changes in our expectations.

During the course of this call, we will also make reference to certain non-GAAP financial measures. We have provided an additional schedule under the Investors and Financial Reports and SEC Filings portion of the NuStar Energy L.P. website reconciling these non-GAAP financial measures to the most directly comparable financial measure, calculated and presented in accordance with the US Generally Accepted Accounting Principles, or GAAP. Our non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income, operating income, net cash flows provided by operating activities, or any other GAAP measure of liquidity or financial performance.

Now let me turn the call over to Curt.

Good morning and thanks for joining us today. I'm happy to report that first quarter 2011 results were higher than first quarter 2010 results in all three of NuStar Energy's business segments. I'm also pleased that we've been able to start the second quarter with an announcement regarding another internal growth project in the Eagle Ford shale and an announcement regarding the acquisition of a small refinery located on the south side of San Antonio in close proximity to the Eagle Ford oil shale production.

Before I go into further details regarding those two second quarter announcements, I'll spend a few minutes talking about the first quarter results. NuStar Energy generated $93 million of EBITDA in the first quarter of 2011, higher than the $81 million earned in the first quarter of last year, and well within our first quarter 2011 guidance range of $80 million to $100 million. Our Storage segment earned $70 million of EBITDA in the first quarter, approximately $8 million higher than the first quarter of 2010. Not only did the Storage segment outperform last year's first quarter, the $70 million earned during the first quarter of 2011 was the highest quarterly EBITDA ever for our Storage segment.

Higher storage rates on existing contracts and an increased customer demand for storage services had a positive impact on first quarter Storage segment EBITDA. In addition incremental EBITDA generated by the May, 2010 Mobile, Alabama terminal acquisition and the completion of our St. Eustatius terminal reconfiguration project in the fourth quarter of 2010 contributed to the Storage segment's increased EBITDA.

Transportation segment EBITDA of $47.1 million, was slightly higher than the $46.5 million earned in the first quarter of last year. Increased shipments on higher-tariff pipelines and operating expense efficiencies more than offset lower pipeline throughputs. Throughput volumes were down on both our crude and refined product pipelines. Turnaround maintenance activity at one of our customer's refineries and the impact of competing supply economics affected throughputs on our crude oil pipeline system. Market conditions that made it more favorable for some of our customers to export refined products, especially diesel, then to transport them to Houston on our Corpus Christi to Houston, Texas pipeline adversely impacted throughput on that line. However, we have identified a project to significantly increase throughput on the Houston line whether or not shippers favor such marine exports.

The Asphalt and Fuels Marketing segment generated $5 million of EBITDA during the first quarter, approximately $8 million higher than the negative $3 million of EBITDA in the first quarter of 2010. The asphalt refining and marketing portion of the Asphalt and Fuels Marketing segment lost $8.6 million in EBITDA during the quarter, $2.4 million worse than the $6.2 million lost in the first quarter of 2010. Lower sales volumes due mainly to wholesale customers opting not to build winter fuel inventory levels during the perceived high price environment that existed in the first quarter, was the primary cause of the lower results. This part of our business is always weak in the first quarter and our outlook remains good.

Fuels marketing operations first quarter 2011 EBITDA increased to $13.6 million, $10.2 million higher than the same quarter last year. Improved results in our crude oil trading and products trading businesses contributed to the higher results. Our crude trading business benefited from wide spread between WTI and Brent during the quarter, while our products trading business benefited from the sale of diesel fuel inventory stored in one of our Northeast terminal facilities.

Taking a look at our first quarter corporate expenses, G&A expenses were $26 million, down $1.3 million from last year's first quarter. This reduction was mainly due to lower stock-based compensation expense. NuStar Energy's unit price decreased $1.60 per unit in the first quarter, versus increasing $4.35 per unit in the first quarter of last year. Interest expense for the quarter was $20.5 million, up $1.9 million from last year mainly as a result of our issuance of $450 million of 4.8% senior notes in August 2010. First quarter earnings of $0.30 per unit were higher than first quarter 2010 earnings of $0.19 per unit. These first quarter 2011 results include $5 million or $0.08 of expenses related to the early termination of a third party storage agreement at our Paulsboro, New Jersey asphalt refinery.

This decision to terminate early was part of the economics of bringing 10,000 barrels per day of Pergrino crude oil to our Paulsboro plant, an accretive project that will start up at the end of the year. The lease buy-out enabled us to avoid the capital expenditure required to build a new tank. First quarter 2011 adjusted net income applicable to limited partners, excluding the effect of the early termination costs and other smaller items, would have been $0.40 per unit, which was above our first quarter 2011 guidance of $0.15 to $0.35 per unit.

NuStar Energy's distributable cash flow available to the limiteds of $45 million for the first quarter of 2011 was $22 million or 98% higher than the first quarter last year. The increase in first quarter 2011 distributable cash flow available to the limiteds was a result of our $12 million increase in EBITDA, reduced reliability CapEx and lower mark-to-market deductions relating to hedging. With regard to our first quarter 2011 distributions, NuStar Energy's Board declared a distribution of $1.075 per unit, which is $0.01 per unit or about 1% higher than the first quarter 2010 distribution of $1.065 per unit. The distribution will be paid on May 13.

The Board of NuStar GP Holdings declared a first quarter distribution of $0.48 per unit, which is $0.03, or around 7%, higher than the first quarter 2010 distribution. The NuStar GP Holdings distribution will be paid on May 18.

As I mentioned earlier we already had a very busy start to the second quarter. On April 5, we announced that we'd signed a letter of intent with TexStar Midstream Services LP to develop a new pipeline system to transport Eagle Ford crude and condensate to Corpus Christi, Texas. This is the second Eagle Ford pipeline deal we have signed and announced. TexStar will be constructing a 65-mile 120,000 barrel per day pipeline that will be interconnected with a new storage facility to be constructed by NuStar at Three Rivers, Texas. This storage facility will connect to NuStar's 200,000 barrel per day pipeline that will have the ability to transport crude and condensate from Three Rivers to storage tanks at NuStar's Corpus Christi North Beach terminal.

We expect this transaction to improve earnings in both our transportation and storage segments beginning in the second quarter of 2012. Currently we're still working with TexStar to finalize the definitive agreement for the transaction and once that definitive agreement is done, we should be able to provide capital spending and EBITDA guidance regarding the transaction.

As we move through the remainder of 2011, we expect to announce more deals related to shale development opportunities. As we mentioned before, NuStar has transportation and storage assets located in areas within Texas and Colorado that can serve as effective means to transport or store shale production. On April 19, we closed on the $41 million acquisition of certain refining assets of the former AGE Refining, now the NuStar San Antonio refinery. The refinery is a 14,500 barrel per day nameplate capacity refinery located on the South side of San Antonio in proximity to the Eagle Ford crude production. The plant is currently operating at around 11,800 barrels per day with plans to increase the run rate. The acquisition also includes 200,000 barrels of storage tanks in Elmendorf, Texas, about 12 miles from the refinery.

The refinery purchases and processes crude oils and condensates for across South Texas, including the rapidly developing Eagle Ford Shale. It produces and sells high value refined products including jet fuels, ultra low-sulfur diesel or ULSD, naphtha, refrimates, liquefied petroleum gas, specialty solvents and other highly specialized fuels to commercial and retail customers as well as the United States military. Estimated product yields from the refinery are 40% jet fuel and ultra low-sulfur diesel, 30% refinery feed stocks -- mostly naphtha and cat feed, 20% gasoline blending components -- mostly light and heavy refrimates, and 10% LPGs and specialty solvents.

Unlike an asphalt refinery, the margin on these products can be hedged. And we have in fact already hedged our margins on approximately 70% of the refinery's current production level of around 11,800 barrels per day through the futures market for crude, distillates and gasoline related products for the next three to four years depending on the product. Based on those margins we expect to add $15 million to $20 million of EBITDA and $5 million to $10 million of distributable cash flow for the balance of 2011. Over the remaining life of these hedges, the refinery should generate $30 million to $40 million of EBITDA and $20 million to $30 million of distributable cash flow annually. Based on those projections we expect this acquisition to pay out in approximately two years.

Working capital requirements for the refinery will be minimal. Industry payment terms for domestic crude purchases usually average 30 to 35 days, which exceeds the payment terms associated with the refinery sales. This should allow us to keep our working capital balances related to this refinery very low. Capital spending at the refinery should be around $35 million over the next five years. About $10 million should be spent in 2011. The majority of this capital will be reliability CapEx and it will include but not be limited to improvements to drainage at the plant, environmental cleanup and the modernization of the refinery's control systems.

We're currently evaluating the possibility of constructing a pipeline from the Elmendorf storage tanks I mentioned to the San Antonio refinery. This pipeline would significantly reduce, if not totally eliminate, the need for trucks to deliver crude to the plant. The pipeline project would significantly reduce traffic congestion in the refinery's neighborhood and also reduce truck transportation costs. Preliminary cost estimates on this strategic capital project range from $10 million to $15 million.

Taking a look at NuStar's projected results for the second quarter, we expect our EBITDA to be in the range of $130 million to $150 million. Our Storage segment EBITDA should be slightly higher than it was in the second quarter of 2010. Increased EBITDA from our recent terminal acquisitions and some completed internal growth projects will be mostly offset by increased maintenance expense at several terminals. EBITDA in our Transportation segment should be down $5 million to $10 million compared to last year's second quarter, lower tariffs as a result of the July 1, 2010 negative tariff adjustment, reduced throughputs and increased maintenance will contribute to the decrease.

Late in June of this year, we expect to complete the work associated with the pipeline connection and capacity lease agreement we entered into with Koch Pipeline Company in October of 2010. Under that agreement, NuStar will reactivate a previously idle pipeline in South Texas that will then be used -- now be utilized to transport Eagle Ford crude oil shale production to Corpus Christi refineries and terminals. That project should provide the Transportation segment with incremental EBITDA in the last half of this year.

Asphalt and Fuels Marketing segment second quarter EBITDA should be $10 million to $15 million higher. Asphalt refining and marketing operations should be comparable to last year's second quarter. Margins should remain fairly strong in the $11.00 to $13.00 per barrel range, supported by the strong six oil market and higher coker unit run rates. However, second quarter sales volumes should be comparable to down slightly from last year.

Our new fuels refining operation, or the San Antonio refinery acquisition, should contribute $3 million to $5 million in the second quarter of EBITDA. We expect that amount to increase as the year progresses. Fuels marketing operations should see an increase of $5 million to $8 million in EBITDA in the second quarter. Increased earnings from our growing heavy fuels and bunker marketing businesses should contribute to this increase.

Earnings per unit applicable to limited partners for the second quarter are expected to be in the range of $0.90 to $1.10. Second quarter 2011 operating expense is expected to be around $140 million to $145 million, G&A in the range of $28 million to $29 million, depreciation and amortization around $40 million to $41 million and interest expense $20 million to $21 million. For the full year 2011, we expect EBITDA to be $35 million to $45 million higher than 2010. Storage Segment full year 2011 EBITDA should increase by $25 million to $35 million. This segment should realize a full year of EBITDA from the Mobile, Alabama acquisition and the St. Eustatius terminal internal growth project.

In addition EBITDA from the February, 2011 Turkey terminal acquisition and third quarter 2011 completion of the 3.2 million barrel tank expansion project at St. James, Louisiana should contribute to the segment's increase in EBITDA. This Storage segment guidance is lower than the full year guidance provided on January 31, the fourth quarter 2010 earnings call. Lower than expected unit train activity at some of our West Coast terminals, unplanned tank maintenance, causing some of our tanks to be taken out of service, and lower vessel call projections at one of our terminals are the main causes for the reduced guidance.

In regard to Turkey we already have two expansion projects planned totaling $20 million to $30 million. Spending on the projects has already begun. We expect one of the projects to be done by the end of 2012 and the other by the end of 2013. Full year 2011 EBITDA in our Transportation segment should benefit from the estimated second quarter 2011 completion of the Eagle Ford Shale project for Koch Pipeline Company and a July 1, 2011 FERC tariff increase of close to 7%. However, these projected benefits should be more than offset by lower throughputs in 2011. Increased customer refinery turnaround activity and changing market conditions should cause our Transportation segment's throughput volumes to be down around 4% in 2011. As a result, our Transportation segment EBITDA is projected to be $5 million to $10 million lower in 2011.

2011 EBITDA in asphalt and fuels marketing should be $35 million to $45 million higher than the $111 million earned in 2010. Asphalt refining and marketing operations' 2011 EBITDA should be slightly higher than 2010. We believe gross margin should be slightly higher than 2010 and in the range of $7.00 to $9.00 per barrel. Strong demand and high prices in the six oil markets, high coker utilization rates as crack spreads remain strong and an increased coking capacity, due a coking unit coming online late in the year, should all contribute to the higher gross margins. However, we expect 2011 asphalt demand to continue to be tepid by historical standards. We expect the RAC asphalt demand to be comparable to slightly higher to last year. Demand in the other classes of trade is projected to be down year-over-year so long as wholesale customers are reluctant to build inventory levels.

Fuels refining operations, that is to say the San Antonio refinery, are expected to contribute $15 million to $20 million of EBITDA in 2011. Our fuels marketing operation should benefit from a full year's worth of EBITDA from the new US heavy fuels and bunker fuels markets that we entered last year. We expect these fuels marketing operations to contribute an additional $15 million to $20 million of EBITDA in 2011. It should be noted that our 2010 results included about $15 million related to property insurance proceeds received due to damage caused to our Texas City terminal by Hurricane Ike in the third quarter of 2008. We do not expect to benefit from any type of insurance proceeds settlements this year.

Reliability capital spend for 2011 should total $65 million to $70 million, up from our prior guidance of $50 million to $55 million, due mainly to reliability CapEx associated with the San Antonio refining assets. 2011 strategic capital spending should fall in the range of $350 million to $370 million, again higher than our previous guidance of $330 million to $350 million. The addition of a couple of attractive terminal expansion projects causes the increase in strategic spending.

Of the $350 million to $370 million we expect to spend this year, around $165 million relates to projects that will be placed in service this year. The majority of the remaining spending relates to projects at St. James, Louisiana and St. Eustatius terminals that will not begin generating EBITDA until next year. If you include the February 2011 Turkey acquisition and the recent San Antonio refinery acquisition, our estimated 2011 total capital spending related to strategic capital and to acquisitions should be around $450 million.

With regard to 2011 distribution growth, we still feel 2011 distributions should exceed the distribution growth rate of last year. The immediately accretive distributable cash flow we expect to generate from the San Antonio refining asset acquisition provides the potential for greater 2011 distribution growth than we would have had absent the acquisition, until some of our large internal growth projects come online in 2012.

So let me close by saying I'm very excited about the two acquisitions we completed in the first four months of 2011, the recent signing of the letter of intent with TexStar Midstream, the additional opportunities we're pursuing in South Texas and the ongoing expansion projects in the Storage segment. As these acquisitions, opportunities and expansion projects are fully integrated and completed, they begin to generate the incremental EBITDA and distributable cash flow that allows NuStar Energy to increase distributions at levels significantly in excess of the increases seen in 2010.

So at this time let me turn it over to the operator so we can open up the call to Q&A.

(Operator Instructions). Your first question comes from Darren Horowitz with Raymond James.

Hey, good morning, guys. How are you?

Good morning. Good.

Hey, Curt, regarding the new Eagle Ford pipeline system that you guys are talking about with TexStar and of course, I realize you're still working to finalize a few things, but can you give us a little bit more color on the throughput and the storage agreements? I'm just trying to get a feel for the volume commitments and the contract duration there.

Yes. Sure. We can give you some color. Ask Danny -- Danny Oliver is here. Go ahead, Danny.

Well let me start off with the pipeline itself. It's a 200,000 barrel per day pipeline. This TexStar agreement, they are the base tenant basically in that pipeline they will be filling -- we're talking about is -- 40,000 to 100,000 barrels a day of that pipeline space. But then we are already well into conversations with other shippers that we believe will fill that line ultimately. It should start off receiving product in second quarter of 2012 and we expect the line could be full by about that time 2013.

Okay. Danny, is it still too early to tell what kind of contract durations on a blended basis you're looking to achieve?

Yes. I think they'll be a good five-plus years.

Okay. And then just thinking about the approved lease option that you have for the adjoining 15 acres in Corpus, how are you guys thinking about incremental capacity at that North Beach terminal?

Well, we're not entirely sure we're going to need that land but we may have enough space to handle it. It depends on how much of this crude is going to be delivered locally to refiners versus loaded out over our dock. But we're working through those issues right now.

Okay. And then last question for me just from a bigger picture perspective and you guys have done a good job touching on this before but when you think about all the opportunity that you could have across South Texas moving a lot of that product East, with those five or six lines that you have going through touch Eagle Ford, the Niobrara, has your thought process changed as it relates to maximizing efficiency on those lines or further expanding a lot of those opportunities?

No, in fact it's a little better than what we had originally anticipated. You know about two of the projects - the Koch pipeline project and we announced this TexStar project, there's two others that we're working on that are a little too early to get into specifics, but I think across four different pipeline projects we're looking at increasing capacity from -- or throughput from about 80,000 barrels a day to about 365,000 barrels a day once those lines are full. And that'll take a year or so to get there once they start flowing but that's what we think is (background noise).

Okay. I appreciate the color. Thank you.

You're welcome.

Your next question comes from Brian Zarahn with Barclays Capital.

Morning.

Morning.

Can you discuss -- do you expect -- how much production you expect to hedge with your San Antonio refinery? Do you expect to hedge the remaining unhedged volumes or you're comfortable with this level?

We're comfortable where we are with about 70% of the product yield we were able to lock in very favorable margins, which give us that sort of payout that I mentioned within two years. And then Paul Brattlof is here who did the hedging. Do you want to comment any further on that? We don't plan to do any more at the moment.

No, we only want to hedge the components that we thought we could get hedge accounting so we wouldn't have any fluctuations in earning results. So I think this is the conservative approach and really, the upside is that we can get those products through the refinery, that's where we see -- once we get some efficiencies worked out.

You understand what he's saying. What he hedged was highly correlated to the actual physical market. The balance of that, roughly 30% of the yield, is products where you wouldn't have that opportunity, you wouldn't have that benefit -- four oil and some other things that come off the plant that are not highly correlated from a hedge standpoint.

Okay. And then in terms of -- this is a relatively modest size acquisition but it is diversifying your products, latent refining, are you in the market for more non-asphalt refinery acquisitions?

No. We really aren't. This was an opportunistic buy for us. Because of all the things Danny commented on, we've been very closely following what happens in the Eagle Ford Shale and where that oil is going. And then it just so happened that this -- the ownership of this plant went into bankruptcy really because they over-extended themselves, they took on too much debt. And so the bankruptcy trustee started a process and then started talking to us privately about buying the plant in a private sale process, which was what we ended up doing.

But no, when you look at -- I kind of summarized where all our growth capital is going and you see it all going into storage and pipelines and there's -- the acquisitions that we've done recently are all storage and the one frankly that are most likely get done next are in the Storage segment. So, no this is not the start of a refinery acquisition program for NuStar.

And then looking at -- Valero acquired some assets in the UK from Chevron and it included some pipeline terminal assets. Have you had any discussions with them about or have you looked at them as a potential acquisition opportunity?

No. No, we haven't talked to them about that at all. We've talked to them about a lot of things including things we can do more of together in South Texas, so it's much more likely that we would do things with them right in our own backyard than over in England.

Okay. And finally, appreciate the color on the CapEx, you have a lot of new projects and some acquisitions, on the first quarter though can you provide what the total CapEx was?

First quarter, yes, we'll dig it out for you right now. I just don't have it.

Yes, Brian, first quarter we spent a total of $66 million on strategic and $8 million on reliability. So a total of $74 million.

Thank you.

It's going to be a lot harder in the second for growth than in the third. The first is probably the lightest CapEx -- yes, it will be the lightest CapEx quarter for us this year, excluding acquisitions. Just organic growth, capital and reliability.

Does that answer it?

Yes. Thank you.

Okay.

Your next question comes from Steve Maresca from Morgan Stanley.

Hey, good morning, everybody.

Morning.

Curt, you mentioned competing supply for crude oil hurting results on I guess your line to Houston and you were identifying -- you had identified some projects. Is that what you were talking about with the TexStar line?

No, no. It's two different things going on. One on the -- with regard to the Houston line there have been less and a bit chronically that line's been underutilized. Not just this quarter but for a number of quarters past and it's principally because the Gulf Coast refiners that ship on that line are seeing a lot of better export opportunities, particularly for distillates to Latin America to Europe on bench putting it on a pipeline to Houston. So as a result and we think that has continued for a while and could continue for a while longer. So as a result, we are in the process of developing projects and it relates to what Danny was talking about on the oil and the liquids coming out of the Eagle Ford production that we think is going to fill up that line over the next one to two years.

So it's really going to be a change in service of that line. It'll have different shippers from the ones that were conditionally using the line at higher rates of utilization in the past that because of that change in market conditions that I just mentioned, the export market being favored over the Houston pipeline shipments. We are developing alternative shippers and uses for the line. So that was part of what Danny meant when he said we're going to fill up all these lines. The Houston line is included in that.

Okay. And then on the new Eagle Ford line, 200,000 barrels a day, TexStar being possibly 40,000 to 100,000. Are you waiting on getting that remainder to 200,000 filled before we get from a commitment standpoint before you come out with a more detailed announcement or more details in general?

We'll have more details when we have more definitive agreements but the line is built, it exists.

That 16-inch he's talking about between Three Rivers and Corpus. So that's already there.

Our portion -- we have some tanks to build but the line exists.

By June I guess is what we're estimating we'll --

Yes, early summer we'll have the definitive agreement done and we'll have with certainty we can give you detailed guidance on some of the principal financial highlights by that time.

Okay. And then finally, Curt, you touched upon just thinking that there's going to be more opportunities for you, more announcements possibly with the shale opportunity. I mean, where do you see the biggest opportunity for you guys, whether it's a region or a type of asset over the next 12 months?

For us it's really been -- on the pipeline side, really been around the Eagle Ford and this Niobrara oil shale development, more up toward Colorado and the Rockies because we have spare capacity in our pipelines and storage terminal assets that can be filled up by these developments. So those are the most likely announcements from us.

Okay. Thanks a lot, everybody.

Yes. Thank you.

Your next question is from Joseph Siano with Credit Suisse.

Hi, good morning.

Good morning.

So I guess first to just quickly follow-up on the refinery acquisition, how do you view -- it seems like you've locked in some pretty attractive cash flows but how do you view those cash flows in terms of how comfortable you are with paying that out? What kind of coverage ratio are you thinking or feeling comfortable with?

Yes. It's different from say buying an asphalt refinery where you can't lock in the margins the way you can here. So actually our timing was very, very good on this -- part strategy, part serendipity. Because we bought the plant really at very favorable crack spreads compared to recent history. So we've been able to lock those in. Because of that we have a high degree of confidence that there's distributable cash flow from this asset that will be available for distribution to limiteds. So we've taken, as Paul mentioned, we took the volatility out of it by using the futures markets to use hedges that are highly correlated to the actual physical sales of these products.

So like anything else you have to run the plant, you have to sell the products to capture the benefit, so I wouldn't say it's no risk because you locked in the margin but it's substantially lower than just buying another refinery where you can't take advantage of locking in those spreads.

Right. Okay. And so would that be something you'd try to keep rolling every year, keep that three to four year horizon kind of hedged? (multiple speakers)

(multiple speakers) I think we'll look at it all the time, yes. But right now we've got for this wish you've got four years locked in the gasoline, close to three, two and a half. We have the balance of this year and then 2012 and 2013 so Paul and his guys watch it all the time to see if there's something we can do to extend or improve the economics that we have. So that is part of the whole process but we're very happy with where it sits right now.

Okay. Great. And in terms of incremental opportunities, I guess you discussed all the opportunities around shale and -- but in terms of -- on the international acquisition side are you still pursuing anything there or are you --?

Yes. Yes. We are and those are most likely to be in the storage area because there are still favorable locations, both domestically and internationally, where big customers and traders, many of whom are already customers of ours. We have a lot of interaction of feedback with them about where they want to be and where they would support, with long-term commitments, storage acquisitions by NuStar. And so we do have some of those in the hopper and so if we do something internationally, it's most likely to be in the Storage segment.

In addition to acquisitions we're still very active on the internal growth side in our storage segment, most notably the work going on at St. Eustatius and St. James.

All right. Thanks, guys.

Thank you.

Your next question is from Ross Payne with Wells Fargo.

How're you doing, guys?

Hi, Ross. Good, how are you?

Hey, Curt. If you could just comment a little more on what you're seeing out there in the asphalt market from a demand standpoint. And secondarily, you've obviously probably talked to the rating agencies on this most recent purchase. I assume they're comfortable with the size of this refinery and where you guys are strategically --

On the second one, yes. And I'll let -- Steve will chime in, but basically yes. It's a small deal. We've locked in the margins and so we have talked to them about all that. With regard to where we are on the asphalt market, what we've been saying overall just in terms of the asphalt it should be slightly better than it was last year and we're sticking to that for now. Obviously in that segment we've really had a big pick up in the fuels marketing contribution to the bottom line of that segment just because of how well we've done on the crude trading and the fuel oil, all those things that we invested in last year to do it start to come through to the bottom line. So that's why that segment gets the big pick up.

But on the asphalt demand side, I've got Mike Stone here, who is head of asphalt marketing and Paul can chime in too, but overall I would say by historical standards in 2011 it's still pretty tepid. The federal funding will be there. They've had the extension for this year. We still are pushing politically for a multi-year extension, which would be better for everybody in the road repair and maintenance industry. But the federal funding is there for this year. There's still stimulus dollars to be spent, particularly in our main markets on the East Coast where the stimulus spending lagged last year compared to spending in other parts of the country. It's true that states are fiscally challenged but so far all indications are the states are going to spend their normal amounts of money on this area of their budgets.

And they have had upticks in sales tax. There is some modest economic recovery going on, albeit not that great. It's probably the localities that are really being hurt the most right now because even though there is some signs of life in the housing market, it's still very, very low compared to what it was. And so you have localities that depend on property valuation for their revenue are struggling to do everything that they did in the heyday. But overall like I said, we think demand is sort of comparable to slightly better than last year. Then you do have a little bit of the factor of how high pricing is going to go. So far our guys have done a very good job keeping the asphalt prices up, outpacing the rise in the crude prices.

You pay a little bit of a cost for that the first quarter because you had, I mentioned, the wholesale customers kind of waiting to see if they could get better prices later, so that hurts first quarter volumes. On the other hand I think it's the absolute right position for us to be in because now you've got very low asphalt inventories, well below historic measures. You've got guys who didn't winter fill. We'll be there with the product when they finally cry uncle and they need it. So I don't know, do you guys want to chime in on -- there also -- another thing that's helped us is there is an export market this year.

I think you said it exactly right. It's the shift -- we're cautiously optimistic that the shift from wholesale to our higher margin RAC sales will happen this summer. So we've got big expectations.

And the only thing I would add is that the whole industry has been very, very conservative in their consumption because of the funding or lack thereof. But now that the federal government has passed a law for this year, now you're going to get some activity. So even though the demand was off for the first quarter we expect it to get back to the level that Curt's talking about.

Okay. Great. Thanks a lot, guys.

Thank you.

Your next question is from Michael Blum with Wells Fargo.

Hi, good morning, everyone.

Hi.

Let me perhaps if you don't mind a sort of dumb question but just so I understand it, in terms of the latest asphalt acquisition when you say you've hedged your margins, does that mean you've hedged the crack spread so you've hedged both the input costs, meaning the crude and the product yield?

Yes. No, it's not a dumb question at all. It's important to understand because people throw around these terms and sometimes -- I spent 20 years trying to understand what people were saying in this business half the time so it's not a dumb question. But first of all let me clarify one thing, the recent refining acquisition we did is not an asphalt acquisition. This plant does not make any asphalt at all and one of the disadvantages of running an asphalt plant is you can not lock in the margins in the futures markets the way you can with the plant that we just bought in San Antonio.

So that's what we've done. And what you do by locking is you're basically selling a spread between a given crude oil price and a given product price. And so that's what we did. We said, okay the spread is let's say it's $25.00 or something for the distillate. We've sold that to somebody else and we get paid for that over time. Paul do you want to --?

No, that's exactly right. We bought crude in four markets and we sold products, which is the spread Curt is talking about, and so it's really -- it's just how that spread goes forward. Our plant should enjoy the benefit or make that extra money if the market -- if the spreads go up even higher. Refinery will make it and we'll pay back those hedges.

Okay. Thanks for that clarification. The second question just back to the Transportation segment, you cited sort of changing -- "changing market conditions." You've already talked about the issues down in Houston refining market. Are there any other sort of big picture conditions that or dynamics that are effecting The transportation segment right now?

No. I think we covered it there. It's a little bit of a transition year for us to be honest in the Transportation segment because for many, many years and even in our first quarter results you see that the throughputs were down but the financial results were a little bit better. This has been probably the steadiest segment that we've had in the 10 years since this company IPO'd with really slow growth associated with it. And we're going through sort of a transition year kind of like that again. We're taking some hits on some of the lines because of the changed market conditions we mentioned.

But we finally have a lot of growth associated with the pipeline Transportation segment which we really haven't had since the beginning of this company because of this oil shale development. And so over the next one to two years that's going to be a big growth area for us and you're going to see a lot of that benefit flowing to the bottom line. So that's -- I hope that's a helpful summary of where we are and where we're going in the near-term.

Great. Thank you very much, Curt.

Thank you.

Your next question is from Noah Lerner from Hartz Capital.

Morning, everyone.

Morning.

First question, just to beat the dead horse a little bit over the AGE acquisition, I was just curious, with the asphalt probably because you couldn't do any kind of hedging you generally had a rule of thumb that 50% of the expected cash flow you would build into the distribution projection -- or the cash flow for distribution, and 50% you wouldn't. That would give you some downside that you wouldn't find yourself with a big gap on your distribution. I was curious if you think of the cash flow off of this refining asset similarly because even though you've hedged for three or four years, nobody knows what the crack spreads might be a year from now, two years from now looking out to that period that you could end up with a whole kind of like a contract renewing and not necessarily having a customer to fill up that gap. So just curious if you give any thought to how you're going to use that cash?

Well first of all, no, we're not doing the same thing like with the 50% holdback on this plant because we've been able to lock in the margins for the periods that we've mentioned. But it's a relatively small part of our overall company. So we're going to manage our distributable cash flow, our coverage and our distribution not just depending on whether the refinery is cash flow -- how much it's cash flowing three or four years from now but how the overall company is cash flowing three or four years from now. And as you can tell from the comments we've laid out in this call and in our recent calls that a lot of our growth is in the Storage and Pipeline segments going forward, which further diminishes the significance of this $41 million acquisition going forward.

So, no we're not going to have the same holdback as the asphalt because it's different from a financial point of view. We think this throws off cash flow that will be available for distribution, more so as I said in my remarks than we would have had this year without the acquisition and I don't really see it as an issue for the management of our distribution growth going forward because it's a relatively -- it's quite a small part of our overall company, especially as our company grows in the Storage and Pipeline segments.

When you start talking about three, four, five years out from now, this is going to be a substantially different company than it is today and this plant will be even a smaller part of the overall picture.

Great. Good points. I guess another question is really small but just for edification, on the Paulsboro situation where you paid $5 million to terminate a contract earlier so you didn't have to build a new tank, could you share with us what the approximate cost would have been to build a new tank?

Yes, it would have been more than we paid in the buy-out for sure but it's not only just the cost to be honest with you, it was also the timing. We had to be ready to take this -- it's a very highly accretive deal for us. Let me take one step back. This Peregrino crude deal with Statoil does a couple of things for us. First of all it's a very valuable crude contract. It was better than our alternatives even from the Venezuelans, but secondly we said when we bought the CITGO asphalt assets in 2008 that we would work over the next few years to diversify the source of crude supply to this plant. We've run some Mayan, we've run some other crudes so we've made some minor tweaks to the plant to be able to do that on a spot basis.

But this is our first term contract that moves us away from the Venezuelans over time and so it had a lot of attractions to us because it's accretive. It's a valuable crude to run. It's an asphaltic crude. But also it diversifies that crude supply, which we liked about it too. Now the -- Rick Bluntzer is here, head of our operations, I don't remember the tank building cost but it was higher than the $5 million --

It was actually up around $8 million to $10 million and the timing would have -- we would have missed that window for this opportunity.

Yes, so when you consider the opportunity of being able to run the cheaper crude and the cost differential, it's like a one or two year pay back on this decision. So it was well worth taking the cash hit and the charge in the first quarter to be able to run this crude when the field comes online.

We don't like [lack] in the first quarter with it, but it was definitely the right decision from a business standpoint.

It's a trivial matter, I'm just trying to, pardon the expression, get inside your guys heads to understand how you guys think this all through because one could argue that really the $5 million cost to this tank because that's what you're paying to free up the tank.

Yes. That's true. As compared to spending, Rick just said $8 million to $10 million and then missing really more important (multiple speakers) is missing the opportunity that we have with Statoil.

Obviously the one to two year pay back doesn't come from the difference between $5million and $8million to $10 million. It's the savings on the crude cost and --

Great. Thanks a lot. Really appreciate the information.

Thank you.

Your next question comes from John Tysseland from Citigroup.

Hi, guys. Good morning. I just had a couple of quick clarifying questions regarding -- around the refinery hedges. Do you have any kind of contingency plan if the refinery goes down? Obviously you've locked in multi-year spreads but what happens if the refinery goes down? How do you handle that?

We get it back running again. That's why we've got a whole bunch of refine -- people with refining experience in this company. But -- I don't know if anybody wants to chime in --

If you look at our first year capital spend, the $10 million, most of that's going to go into mechanical reliability, trying to improve the efficiencies of the refinery. And then in the outgoing years we'll spend an additional $20 million to $25 million on the same type strategies.

And the hedge levels that we use plan for two weeks of turnaround and -- (multiple speakers) -- unidentified down time, so we hope we're conservative just in the level of the hedges we've done.

And then also you mentioned that I think throughput was 11,800 barrels per day at the time, is that kind of a flat rate that you've assumed over the next several years or -- ?

That's kind of sort of current average like if you look at -- we've only owned this thing for a couple of weeks but if you look at the last week or so it's averaged about 11,800. The problem they've had the way they -- they were very up and down because they had a lot of operating inefficiencies and so forth that Rick's commenting on that we can solve. But over time we'll get it up above 11,800. We're using that for right now. That's pretty much what we based our economics on when we talked about -- I think in the press release we talked about an IRR of about 70%. We used the 11,800 there with the down time that Steve mentioned, two weeks of planned and two weeks of unplanned down time every single year. And we really think we've been very conservative on that. So over time we'll get the plant up. We'll see how high we can get it. We're thinking maybe 13,000 barrels a day is more of a normal run rate than 11,800. And with the margin environment we're in right now every barrel is money. So the sooner we can get that rate up the better for everybody.

And then lastly I think you had mentioned what was it -- $15 million to $20 million of inventory that you purchased with the transaction, is that correct?

I don't think I mentioned that inventory, no. The net working capital is going to be pretty much close to nothing. We're going through that adjustment right now and so we're finalizing that with the seller but it'll be minimal to zero we think.

Okay. And then do you plan on hedging any of that inventory? I know when you did the asphalt acquisition you chose to hedge some of the inventory. How do you handle that this time?

No that was quite different because we -- there we did buy a substantial amount of inventory. It was like over $300 million worth of inventory. Here as I said the net working capital is going to be around zero.

Curt, the only thing I would say is the inventory levels are so minimal that we'll turn the inventories over every two to three days, and so it's not like a big exposure (inaudible - microphone inaccessible)

Yes, they don't have a lot of storage. It's much different than the asphalt business where you've got periods where you're not selling and you winter fill and you're holding inventory and all that. Here you're paying 20 days the month following the crude purchase so you've got 50 to 20 days of credit but you're turning your product in three, four days. So it's really almost negative working capital actually.

That's what I tried to say in my remarks but -- so it's quite different from when we took the decision to hedge a portion of the CITGO asphalt inventory.

No. That's good color. I appreciate it and sorry to harp on a small acquisition --

No, it's an important point. I'm glad you're helping us clarify it, bring it out.

I appreciate the color. Take care.

Thank you.

Your next question is from Michael Cerasoli from Goldman Sachs.

Good morning. I too have just a few questions on the AGE assets. I'm just kind of curious to know how much refining capacity exists in the San Antonio region and if you could talk a little bit about that market that would be helpful.

In San Antonio proper, this is it. Now there obviously -- we're in South Central Texas here. There's a lot of refining capacity in the region, a lot of which we serve, like Valero's plant in Three Rivers. But this is all there is in San Antonio proper.

Okay. And then just on asphalt guidance it sounds like your views haven't changed much from last quarter's conference call, is that the case? What I'm trying to get at is the underlying change to your EBITDA guidance for the segment if you exclude the impact of AGE.

Yes. We did reduce it some but for the reasons I tried to outline in my notes with regard to the unit train projects that we're not going to do on the West Coast.

(multiple speakers)

-- you're talking total. No I would say that asphalt, that segment really hasn't changed since the first quarter call other than going up because of the AGE contribution.

Okay. That's what I was looking for. And then --

I think on overall, down a little bit from what we talked in January really on the storage side due to the unit train on the West Coast -- really just a few things -- more turnaround activity impacting us on tank farms and what not and other people's refiners.

Okay. And then just finally and separately on refined products throughput, do you guys get the sense that there's any demand destruction occurring as a result of the higher prices at the pump right now?

There hasn't been much yet. But if these prices keep going up my bet is there will be. You're starting to see a little bit of signs of softening when you do like -- look at four week averages for gasoline demand and all that. You're starting to see consumers back off some on their purchases but it's really been immaterial to this point even with the run up to close to $4.00 a gallon. Now if it goes higher than that then I think you're having a different conversation but right now it's really been minimal, if anything. Anybody have any comments on that?

Okay. Thank you. That's helpful. Thanks for taking my questions.

Your next question is from Selman Akyol with Stifel Nicolaus.

Thank you. Good morning.

Morning.

As it relates to the Turkey acquisition clearly you're committing more capital there, but I'm just curious, is this going in line with your expectations? Better than what you thought?

It will be. Yes, I mean Turkey is like a miniature version of what we used to say about St. James. St. James when we bought it based on what he'd done historically we paid a pretty high multiple for St. James but because we saw the potential of it we knew on a go forward basis that after you factored in the acquisition cost, cost of capital we actually had a really, really good deal. And Turkey is a little bit like that. We bought an asset in a great location with a booming local economy that was run by a local entrepreneur that didn't really have the business that we're going to bring to it.

He's got a lot of local -- little local customers. We're going to bring big international customers to that site. So what you're going to see with Turkey over the next couple of years is substantial improvement. It doesn't do much for us this year. Next year it starts to do noticeably better and then we think from 2013 forward, this is like a five to six times multiple deal. When you factor in the acquisition price plus the $20 million of capital that we're going to spend on it and then sort of the EBITDA run rate from 2013 forward, it turns out to be an excellent deal. But we're going to go through an adjustment period -- in the year 2011, 2012 because we're basically wiping out and changing over who they dealt with and the way they did business.

It's kind of similar to what we did at St. James, Louisiana. So, short-term it doesn't give us much. But over the next couple of years, it's going to turn out to be a very attractive deal.

Okay. And you also talked about you're seeing other international opportunities. Would that also involve a partner as well? Or would you --

Not necessarily. No. It's -- we tend to have a partnership deals on the negative side of the ledger because it always brings complications -- having to deal with a partner. We like to sort of do things our way if you will. But it's not -- we won't rule it out. There are some jurisdictions where it's to your advantage to have a local partner with local knowledge and local customer base. But not necessarily. We've got deals in the hopper right now which would be 100% deals in international locations.

Great. And last question just housekeeping here, can you remind us of revolver capacity?

It's $500 million at the end of March. It's $1.2 billion total size but $500 million is available to us.

Thank you. Appreciate it.

Your next question is from Yves Siegel with Credit Suisse.

Thanks. Good morning.

Morning.

Just real quick ones, beyond the $35 million that you'll spend over the next couple of years on that refinery acquisition what -- I'm sorry?

That was five years.

Okay. Because my question was going to be what kind of run rate on maintenance CapEx do you think you'd have on the refinery?

Well the $35 million was over the next five years, and we have -- and when you go out beyond that we have ups and downs -- Rick, do you have it handy?

The run rate --

What I gave you is $7 million. And after that some years a little less, some years a little more.

As we get into it, Yves, and as, Rick, gets into it, and we haven't owned it very long, some of what we currently are just labeling reliability, about seven a year let's say on average. Five years may actually be strategic growth because it's probably going to have a return.

Okay. Yes. I was just trying to back into what the distributable cash flow it's actually going to be throwing off.

I think I gave you the balance in 2011 and that's pretty representative of what we have in our economics. Now if you increase it for a full year, that's almost linearly, that's pretty representative of what we have in our economics over the next several years.

The reliability is probably a little heavier this year simply because we're going to get in there and do some stuff and the run rate goes down a little bit but $7 million on average for the five years is the way to think of it.

Okay. And then when you look at the overall growth CapEx for the year what's like the single largest project that is in that number?

It's going to be St. James and St. Eustatius. Those two competing for that top spot. And that's all just tank expansion, storage tank expansions.

It's really St. James. St. James is really the big one and then St. Eu is second.

And St. James, what's the number there?

For 2011 it's about $100 million.

Okay. And then where I'm going with that is just trying to figure out how do you think returns are going to be trending over the next several years?

On those type projects?

Yes.

Well we've been building them on economics that are like six, six to seven time multiples.

Okay.

But I don't see it really changing. It's location dependent. But we've got some pretty good locations.

Yes. And the other aspect of that too is that you would think there would be low execution risk as well because they're not that sizable.

Yes. Well for us they are but I hear you.

Thanks, guys.

Okay.

Your next question comes from Avi Feinberg with Morningstar.

Good morning, everybody. Thanks for all the detail around acquisition and the segment outlook. Just on the Transportation outlook you had mentioned a roughly 40% decrease in throughput I thought based on some of the changing market dynamics and turnaround schedules. I'm just wondering is the base business going to be pretty flat do you assume or does that factor into the 4% one way or another?

You're talking about the refinery did you say?

Transportation. Yes.

I think the base business, other than that Corpus-to-Houston line that Curt had mentioned that we're looking for an alternative solution, I think the base business is pretty solid. What we're seeing here in the first and second quarter is more turnaround related than demand related.

Okay. Great. And are the impacts from the turnaround you mentioned particularly pronounced this year? I mean if you think relative to previous years, is that an especially large impact this year?

I don't know about year-on-year but they're loaded in the first and second quarter. That's where the real effect of turnarounds is for us but year-on-year I don't know if I have --

Maybe a little heavier this year, but not a lot.

Okay. All right. Appreciate it.

Okay. Thank you.

There are no further questions at this time.

Thank you, operator. I'd like to thank everyone for joining us on the call this morning. If anyone has any questions please call NuStar's Investor Relations. Thanks. Have a great day.

This does conclude today's conference call. You may all disconnect.