NuStar Energy LP (NS) 2013 Q2 法說會逐字稿

Good morning. My name is Holly and I will be your conference operator today. At this time, I'd like to welcome everyone to the NuStar Energy LP and NuStar GP Holdings LLC second-quarter 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).

I would now like to turn today's conference over to Chris Russell. Please go ahead sir.

Thank you. Good morning, everyone, and welcome to today's call. On the call today is Curt Anastasio, President and CEO of NuStar Energy LP and NuStar GP Holdings LLC; Steve Blank, Executive Vice President and CFO; and other members of our management team.

Before we get started, we'd like to remind you that, during the course of this call, NuStar management will make statements about our current views concerning the future performance of NuStar that are forward-looking statements within the meaning of the federal securities laws. These statements are subject to the various uncertainties and assumptions described in our filings with the Securities and Exchange Commission and will not be updated to conform to actual results or (technical difficulty) expectations.

During the course of this call, we will also make reference to certain non-GAAP financial measures. Our non-GAAP financial measures should not be considered as alternatives to GAAP measures. Reconciliations of these non-GAAP financial measures to US GAAP may be found either in our earnings press release or our website.

Now let me turn the call over to Curt.

Good morning and thank you for joining us. As expected, our Pipeline segment performed well in the second quarter as throughputs continued to increase on our crude oil pipeline systems located in the Eagle Ford Shale region. Earnings performance in our Fuels Marketing segment improved during the quarter, while results in the Storage segment were lower than last year's second quarter. EBITDA in our pipeline segment increased to $68 million, $23 million higher than the second quarter of 2012. Higher volumes on our Eagle Ford pipeline assets and higher tariff producing pipelines, plus higher pipeline tariffs from the 2012 FERC tariff adjustment, contributed to the improved results.

In addition, the segment results include a $7 million benefit to operating expenses associated with the reduction of a liability recorded in conjunction with an acquisition.

Total Pipeline segment throughputs of around 810,000 barrels per day were 8% higher than last year's second quarter. Crude oil pipeline throughputs were 20%, or 59,000 barrels per day, higher than the second quarter of 2012, due to the 2012 completion of two Eagle Ford Shale projects and the December 2012 crude oil asset acquisition from TexStar Midstream.

Throughputs on our Eagle Ford crude oil pipeline systems were 175,000 barrels per day during the quarter, about 90% higher, or 85,000 barrels per day higher, than the second quarter of 2012. Those increased Eagle Ford throughputs were partially offset by a change in the tariff structure for the throughputs on our Ardmore, Oklahoma crude oil pipeline system. That change reduced second-quarter 2013 throughputs by almost 29,000 barrels per day when compared to the same quarter last year even though it did not affect revenues in the Ardmore system. Effective January 1, 2013, there is a new higher joint tariff that combines two NuStar pipeline segments that were previously reported separately.

Second-quarter throughputs on our Refined Products pipeline system were essentially unchanged compared to last year.

Storage segment EBITDA for the quarter of $69 million was $8 million lower than the $77 million earned last year. Increased earnings associated with the internal growth projects completed at our St. James and St. Eustatius terminals and 2012 and during the first quarter of 2013 were more than offset by reduced demand for storage and terminal services at several of our domestic and international locations.

We have been successful in renegotiating some of our storage contracts in the last few months as our contract renewals do, within three years or less, have dropped from 66% to 59%. However, reduced demand for storage in some of these markets is putting downward pressure on storage rates as the contracts come up for renewal.

Throughput volumes in the Storage segment for the second quarter were actually up 9%, or about 65,000 barrels, compared to the second quarter of 2012. This throughput increase is primarily a result of changing our Corpus Christi North Beach crude oil terminal from a storage fee-based terminal to a throughput-based terminal effective July 1, 2012. The terminal is now used to store Eagle Ford crude oil production shipped down on our Three Rivers to Corpus 16-inch pipeline.

Our Fuels Marketing segment generated $3 million of EBITDA during the quarter, higher than last year's second quarter amount of a negative $6 million of EBITDA. Heavy fuel oil operations generated most of the EBITDA for this segment during the quarter. However, heavy fuel oil margins are lower than margin levels we've seen in the last several years.

Reduced worldwide demand for bunker fuels, plus increased supply in the US Gulf Coast and the Caribbean, caused our bunker operations to continue generate negative EBITDA during the quarter. As a result of profit improvement initiatives we are in the process of implementing, bunker operations should break even in the third quarter and start generating positive EBITDA in the fourth quarter of this year.

In the second quarter, our G&A expenses were $20 million, $3 million less than the G&A incurred during the second quarter of 2012. The reduction in our expenses is primarily due to our sale of 50% of the asphalt business while we continue to provide some of the same administrative services in that business as we did pre-sale. Now instead of incurring expense for those services, we're paid a fee under the service agreement with the joint venture.

Interest expense for the quarter was $30 million, up $7 million from last year. Higher borrowing costs associated with the January 2013 issuance of about $400 million of junior subordinated notes, increased borrowing costs associated with the May 2012 renewal of our credit facility, and the impact of downgrades by the rating agencies were the main reasons for the increased interest expense.

NuStar's June 30, 2013 debt balance was $2.5 billion, approximately $100 million lower than June 30, 2012. In June, we paid off $250 million of senior notes with a borrowing under our $1.5 million revolving credit agreement. As of June 30, 2013, our debt-to-EBITDA ratio was 4.3 times.

Our equity earnings and joint ventures for the quarter were a $10 million loss. The majority of those losses related to the asphalt joint venture. As you will recall, as a result of selling 50% of the asphalt business to Lindsay Goldberg in September of 2012, the financial results of the asphalt joint venture are now deconsolidated from NuStar's financial and no longer impact our distributable cash flow or our bank covenant.

With regard to first-quarter distribution, NuStar Energy's Board of Directors declared a distribution of $1.095 per unit. The distribution will be paid on August 9. The board of NuStar GP Holdings declared a fourth-quarter distribution of -- quarterly distribution of $0.545 per unit. The GP Holdings distribution will be paid on August 14.

Taking a look at projections for the balance of 2013, the Pipeline segment should continue to benefit from additional crude oil throughput in the Eagle Ford as a result of the completion of the construction of additional crude oil gathering lines that will supply crude to the 12-inch line acquired from TexStar and then on to our 16-inch Three Rivers to Corpus Christi pipeline. In addition, the segment will see increased throughputs and EBITDA from the third quarter of 2013 completion of a 100,000 barrel terminal facility and associated pipeline connection to our existing 12-inch Pettus, Texas line for Conoco Phillips. After flowing through the 12-inch Pettus line, those barrels will also connect to our 16-inch Three Rivers to Corpus Christi line.

After these 2013 projects are completed, we expect total throughputs on our Eagle Ford pipeline assets to increase from second-quarter levels of about 175,000 barrels per day to about 200,000 barrels per day by the end of 2013. As a result, third- and fourth-quarter EBITDA results for the Pipeline segment will continue to increase. Full-year EBITDA for the Pipeline segment is expected to be $50 million to $70 million higher than last year.

On July 17, we launched an open season to assess shipper interest in committed space to transport Eagle Ford Shale region crude oil from several terminal locations on our South Texas crude oil pipeline system to our Corpus Christi North Beach terminal facility. This proposed project would include pipeline capacity upgrades to segments of the system and would be constructed in two phases.

The first phase will add incremental throughput capacity of approximately 35,000 barrels per day, and the second phase will add incremental throughput capacity of around 65,000 barrels per day for a total aggregate incremental capacity of 100,000 barrels per day, of which 90,000 will be available to committed shippers. The first phase should be available for service to committed shippers in the third quarter of 2014 while the second phase should be available during the first quarter of 2015. The open season for this project is scheduled to continue until noon Central time on August 30 of this year. If we go forward with these projects, they will not impact 2013 EBITDA but would positively impact 2014 and 2015 results.

With regard to the Storage segment, as I mentioned earlier, the segment's results continue to be impacted by reduced demand for storage at certain of our domestic and international terminals, which is also putting downward pressure on rates in certain markets as some of our Storage contracts come up for renewal. This should cause third-quarter results to be lower than both the second quarter of 2013 and the third quarter of 2012.

As we move into the fourth quarter, the completion of a second 70,000 barrel per day railcar offloading facility at St. James, Louisiana and seasonally reduced maintenance expenses should more than offset the impacts of reduced demand at some of the terminals. As a result, fourth-quarter EBITDA should recover to levels we saw in the Storage segment in the first quarter of this year.

For the full year, we expect the Storage segment EBITDA to be comparable to last year's. Improved performance in our bunker operations in the last half of this year, combined with improved results in our heavy fuel oil operations and other operations within the Fuels Marketing segment, should allow the segment to generate $20 million to $40 million of EBITDA in 2013.

Taking a look at corporate expense guidance for the third quarter, we expect G&A expenses to be in the range of $29 million to $30 million, depreciation and amortization expense around $46 million to $47 million, and interest expense in the range of $32 million to $33 million. Based on these projections, third-quarter earnings per unit should be $0.20 to $0.30 per unit.

Distributable cash flow from continuing operations per limited partner should be in the range of $0.55 to $0.65 per unit, largely impacted by projected third-quarter reliability capital spending of around $20 million. 2013 full-year reliability capital spending should total $35 million to $45 million while our strategic capital is now projected to be in the range of $350 million to $400 million with around $165 million related to internal growth projects in the Eagle Ford Shale.

We plan to communicate updated earnings expectations for 2014 an initial expectations for 2015 once we complete our Eagle Ford open season and our 2014 to 2018 planning process later in this year.

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

(Operator Instructions). Steve Sherowski, Goldman Sachs.

Good morning. I was wondering. Do you have any update for your Houston 12-inch line?

We do. We've been working on agreements there. We expect to go into an open season on that line soon, probably here in the month of August.

Okay. And that's going to be for products?

We are contemplating NGLs on that line.

Okay. And I was just wondering on the timing of your storage re-contracting, does that 40% over a 12-month period still hold?

It's a little bit less now. I think 35%, 36%.

Okay. 35%, 36%. And what's the timing over the next 12 months? Is it back-end loaded or front-end loaded? How should I think about that? And is there any particular concentration in the geographies of the Storage that are going to be -- that are up for recontracting?

I don't have a lot more breakdown than just the one year. But I would tell you some of -- while we have seen some pressure in certain locations on renewal rates, our bigger issue I think on the Storage side is just a few locations in the US really in fuel storage where we've had some difficulty re-renting some tanks that have come off revenue, that were canceled.

Don't forget, Steve, we are marketing ourselves in a number of locations. So Danny was given back those tanks to market, and it's just going to be a transition phase. We are still happy we're exited the business of marketing ourselves given the reduction in inventory that we've achieved.

Okay, no, understood. On your South Texas pipeline, the proposal, do you have any sense of cost yet?

We went out into phases. The first phase for 35,000 barrels a day would cost between $10 million and $20 million. The second phase for 65,000 barrels a day would cost $125 million to $150 million.

$125 million to $150 million?

Right. Depending upon the success of the open season, we could do one or both of those phases, but we remain confident we will be successful in getting into both phases.

Okay. I know it's a little bit early, but I would imagine that you're targeting returns within your historical range?

Yes.

The first phase is well above the historical range because it's very low capital and you get like 25,000 barrels. The second phase, yes, that statement would be true. It would be in that --

Overall, that is right.

Four to five times.

I'm sorry. You said four to five times?

Four to five times.

Okay, great. That's it for me. Thank you.

Brian Zarahn, Barclays.

Good morning. On the Storage segment, can you maybe elaborate a little more on the weakness you are seeing in certain markets? You commented some that steel and oil related in terms of geography. Is there anything in Europe that is not performing as well as you hoped?

Domestically, in our refined products terminals and our refinery crude terminal, they are really unaffected by this. It's some of our coastal facilities here in the US and abroad that some of these three to five-year contracts that are coming up for renewal were signed in a period of contango. And the market is backwardated now, and for the most part, other than the fuel comment I made earlier in the US, we've been successful in re-signing those contracts just at some slightly lower rates.

Is there, since the market has changed and some of your marketing outlook has changed, any possibility of divesting some of these terminals?

We don't have any plans today to do that, but we are open to alternatives. But really I think what Steve said is right. A lot of this is really -- Danny is sort of paying some of the price of the benefit of reducing our working capital at some of these locations. And in time, they'll get leased. The question is at what rates? But we are very focused on that.

And then there are one or two problem terminals that we really have to take a hard look at, but we don't have any planned sales at this time of anything, other than very small ones that we do here and there.

And on the troubled terminals that Curt is referencing are really contango facilities, so when the market was backwardated we lost the customers. There's just a couple of those.

Okay, I appreciate the color on the terminal side. Switching to pipelines, can you give -- you're seeing nice growth obviously in the crude oil side of things, but on refined products, where do you see volumes heading relative to the second half of last year?

Our refined product lines are comparable to last year.

So as you progress through the second half of the year, you think it will be similar?

The same. We are not seeing a lot of growth on refined product, but it's been very, very steady.

So the same relative to last year, relative the first half of this year?

I think the answer is probably the same for both. Unless we had -- I don't have that broken out between products and crude. Call me back later today and I'll get you.

Okay. We'll talk offline on that.

It should be comparable to both though is what I would expect.

Okay. And then any impact from the narrowing crude differentials on your rail terminal?

No. We predominately deal with producers in the existing rail terminal, and also the new one that we are in the process of building right now. And the producers have obviously a different set of economics. I think St. James, Louisiana is still a preferred location.

Well, also both projects are backed by long-term contracts.

Absolutely.

Yes, the current market doesn't affect those deals.

In terms of the -- I understand that they are leased, but I thought there was some type of profit-sharing arrangement.

Yes. Now, on that, that is affected. We benefited from that on the EOG unit train project. And right now, that benefit is much lower going forward, and that's factored into the guidance and the numbers that we have indicated here today.

Okay. Last one from me. I know it depends on the outcome of these open seasons. But any preliminary thoughts on 2014 CapEx relative to this year?

Probably going to be a little bit lower. That being said, that's based on the projects we've identified to date, so -- and as we identify more projects, that number could grow let's say maybe slightly lower.

Let me just make a comment on it though. We really haven't gotten very far into the planning process, but given that, we are going to be very judicious on capital. We're going to be staying very, very focused on Eagle Ford. We are so well positioned there, and we have such strong opportunities to invest further there. Expect -- we continue to see most of our growth capital going into the pipelines, and in particular in the Eagle Ford region. And we have selected other projects at core assets, things we can do it St. Eustatius and St. James, for example, to improve things in a few other projects. But we are really -- I would not -- given the position we are in and the financial metrics we expect to hit going forward from here, we're going to be very focused on where this capital goes into high returns, things that have the best outlook for us like the Eagle Ford.

Okay, thanks Curt.

Mark Reichman, Simmons.

I just wanted to clarify a few things. I think, in the past, you had said that you expected total throughputs on the Eagle Ford pipeline to increase to 225,000 barrels per day by year-end 2013. That would be up from 155,000 barrels per day during the first quarter. Is that still your expectation?

I think we are expecting, by the end of this year, to be between 175,000 and 200,000. Right now our bottleneck -- we will have the pipeline capacity. Our bottleneck right now is the completion of our second dock facility in Corpus, which should be completed about April 1 of next year. We expect, by then, we can start filling up this expansion, and by the end of next year, we expect to be up near 325,000 --

375,000.

I'm sorry, 375,000 a day on Eagle Ford.

Okay. Because I think in the past you kind of expected the Pipeline Transportation segment to generate an additional $60 million to $80 million of EBITDA relative to 2012. And more recently, that number was adjusted to $50 million to $70 million. Is that part of the reason for the delta?

That's part of it.

Part of it. And we had a little bit of a slower ramp up on the Eagle Ford pipeline system than we anticipated when we first guided, so it's a little bit of a timing affect in 2013. The total benefit eventually gets there by year-end, but you do have some timing. Some things went a little slower on the ramp up than we wanted them to. (multiple speakers) 2013.

And so 2014, your expectations there would probably be unchanged. Just looking at the second quarter, quite frankly, really the results came in higher than the top end of your guidance, and it looks like partly better-than-expected Fuels Marketing results, and some I think from the contributions from the asset acquisitions. But just relative to your guidance, where did you perceive kind of the big surprise?

The biggest surprise was I think the $7 million adjustment Curt alluded to. Plus I think, to your point, we did make a little bit of money in the Fuels Marketing segment. That was probably guided to initially. And then --

Reliability was down.

Reliability was down.

You notice like when I talked about third quarter, I said we're going to spend upwards of $20 million on reliability -- that's not on a total budget -- of we've guided to $35 million to $45 million. So you really have reliability spending concentrated in the third quarter. That unduly -- it's just a timing thing. The total amount for the year is the same as we always thought, but it concentrates the spending in the third quarter and their the second quarter kind of results from that. It wasn't as evenly spread on reliability as we thought.

Okay. I appreciate that. I think that's all I had, appreciate it.

Cory Garcia, Raymond James.

I've got a couple of quick questions here. First off, related to your CapEx reduction, it looks like you guys shaved about $50 million off of the budget. Was that primarily just removal of some of the TexStar NGL type spending, or are there some other moving parts in that?

Go ahead Steve. You got it.

It's mostly just push back into next year because of the timing issues --

Like on the Houston line, as Danny just mentioned.

Okay, okay, that's perfect. And switching focus back to sort of the crude by rail, clearly you guys built up quite a bit of exposure in St. James. Any thoughts on maybe expanding out or sort of branching into the East or West Coast, which seem to be obviously a little different markets than what we are seeing today?

We've got a project at our Vancouver, Washington terminal to move crude by rail there. There seems to be customer demand backed by commitment, and so we are working on that. So yes, I think there will. I think there is still scope for crude by rail to the West and the East Coast, and that will help our West Coast terminal operation. Frankly, that's one of the areas that's been struggling on these renewal rates. West Coast terminal renewal rates are down from what we've seen historically.

To give it a little perspective, like Danny said, history is water under the bridge so I hate to revisit it. But we are about -- our Storage profit is about double what it was in 2006. And from 2006 to 2011, through 2011 and 2012, those five, six years, that is when that happened.

We have the shift starting in 2011 to putting more of our growth capital into the Pipeline segment, mainly because of the shale. So that's -- it's true. The storage has leveled off, flattened out some, but we had a tremendous run-up the previous five, six years. And now it's the pipeline that's starting to carry that freight. but anyway, I got a little off track there just to say. Danny, you want to chime in on the (multiple speakers)?

I was just going to say, in addition to the Vancouver project, we are working a project up in Point Tupper. We've got a lot of interest to bring Canadian crude into Point Tupper where we have access to VLCC dock, and we are working that project right now as well. There's lots of opportunities.

Okay. Any idea on maybe the scope of those, light focus, heavy focus or should I just sort of wait for the analyst day here?

Yes. We are still working through that. I mean the Point Tupper project could be both if we have interest in both light and heavy crude. And at the West Coast right now, we are looking at a lighter -- well, it may be heavy Canadian, but dill bit.

It's one of the advantages of rail, you can be a little more flexible on that.

That's Right.

-- in your (multiple speakers) pipeline. Absolutely.

Last one from me on the Corpus dock. I appreciate the update there. I realize it's primarily crude focused, but is there anything that you guys have been looking at for opportunities to handle even lighter projects, whether it would be NGLs or field-level condensate or even at the refinery gate level in terms of getting LPGs on the water?

Our Houston 12-inch project that we expect to go into an open season pretty soon, that will be involved in the NGLs, but nothing from the Storage side.

All right. Perfect. Appreciate the color guys.

Connie Hsu, Morningstar.

Good morning guys. I just had a question on the balance sheet, just keeping in mind your covenant requirements. Will the remaining CapEx for this year, and I guess next year to, will it be financed from debt in the revolver, or do you anticipate having to do another hybrid type subordinated security?

We don't anticipate doing another hybrid security this year. And of course, money is fungible, but you could pretty simply draw the conclusion that the hybrid we did in January for $400 million could go to finance all the strategic capital of about $350 million to $400 million that we will spend this year. Okay? We did sell the refinery in San Antonio for $115 million in January, which provided some unusual source of funding too.

All right, thanks.

Lin Shen, HITE Hedge.

Good morning. Two questions. The first one is to follow up your Storage asset. You figure now is challenging to renew the contract. Could you talk about which area you see the most challenging to attract clients?

Danny Oliver; Right now, it's the fuel oil storage, and we've got two locations on the West Coast, one location on the Gulf Coast and one on the East Coast. It was primarily fuel oil storage. That was a very challenging business last year for everyone in that business. That's been our biggest challenge.

Good. The second question is in your previous guidance you issued before, you said Q2 probably is -- you'll always liable for you coverage ratio you should see substantially improving in the second half of this year. I'm just wondering. Can you talk about now your full-year 2013 guidance should be about the same versus your previous guidance or a little bit lower? And also what's the difference between amount (inaudible)?

Are you talking on just on the coverage ratio?

No, no, just EBITDA guidance and also coverage.

Okay.

EBITDA guidance is basically the same we've given, we gave at the end of June for the full year. So that hasn't changed. As far as coverage ratio goes, I think we said the last conference we wouldn't cover the distribution in the fourth quarter but we should be fairly close. I think that's still -- basically says I think we are at 0.65 covenant (multiple speakers)

It gets a lot better.

(inaudible)

-- in the first quarter a lot by the fourth quarter.

The [0.65] in the second quarter is right on our budget. The third may be just a little weaker. I'm not sure. I don't have it in front of me -- just because of that heavier reliability spend, but that could shift as well. I think, candidly, we may not spend $20 million in the third quarter. That's half of the annual spend. So some of that could slip into the fourth quarter.

We are very confident distributable cash on the back half of the year is going to be quite a bit higher than the first half.

So you think their weakness in your Storage segment should be more than offset by their other segments?

I'm sorry, I didn't -- say that again?

You think the weakness of your Storage segment should be offset by the other pipeline segment, other segments should be stronger?

Oh, yes.

Definitely.

The Pipeline segment is going to be quite a bit stronger.

Yes.

Okay. Thank you very much, appreciate it.

(Operator Instructions). Selman Akyol, Stifel.

Good morning. Just one real quick question. What's your availability on your credit facility right now?

It's about --

I'd say at the end of the quarter, it was about $730 million.

Yes.

Okay, thanks.

At this time, there are no further questions. I'd now like to turn the conference back over to management for closing remarks.

Thank you Holly. Once again, I'd like to thank everybody for joining us on the call today. If anybody has any questions, please feel free to call NuStar's Investor Relations. Thank you.

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