NuStar Energy LP (NS) 2014 Q4 法說會逐字稿

Good morning. My name is Kelly, 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 fourth-quarter 2014 earnings 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) Chris Russell, Treasurer and Vice President of Investor Relations, you may begin your conference.

Thank you, Kelly. Good morning, everyone, and welcome to today's call. On the call today are Brad Barron, NuStar Energy LP and NuStar GP Holdings LLC's President and CEO; and Tom Shoaf, Executive Vice President and CFO; along with 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 of NuStar 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 financials page of the investors section of our website.

Now let me turn the call over to Brad Barron.

Good morning. Thanks for joining us today. This morning I'm happy to report that during 2014 we were able to achieve our primary goal of returning NuStar to a one-to-one distribution coverage, with 1.04 times cover for the year, our highest annual distribution coverage since 2011. For the year, we also generated the highest annual EBITDA and DCF in the partnership's history.

At the beginning of the year, I laid out a series of goals that we needed to accomplish to get NuStar back to a one-to-one distribution coverage. With the dedication of our employees and the execution from our new management team, we were able to achieve each and every one of these goals during the year.

Early in 2014, we divested our remaining 50% in asphalt joint venture. This sale significantly reduced our exposure to margin-based operations and allowed us to renew our focus on growing our fee-based storage and pipeline operations. In February, we signed a long-term agreement with Occidental Petroleum to ship NGLs on NuStar's currently idled 200-mile 12-inch pipeline between Mont Belvieu and Corpus Christi, Texas. This pipeline is expected to go into NGL service early in the second quarter of 2015 and should meet full-capacity requirements late in the second quarter or early in the third quarter of 2015.

Also in February, we completed construction of our state-of-the-art dock at our Corpus Christi North Beach terminal, which more than doubled our capacity. Completing this project has allowed us to handle all the new volume associated with our South Texas crude oil pipeline expansion with room to spare. Just this past December, we loaded the 50 millionth barrel across our docs.

In March, we leased up 5 million barrels of deviously idled tankage at our St. Eustatius terminal, and in August we renewed leases on 3 million barrels of storage at our Point Tupper terminal.

In May 2014, we completed phase 1 of our South Texas crude oil pipeline expansion, which added 35,000 barrels per day to the system and approximately $20 million in annual EBITDA. This pipeline expansion, as well as the construction of the new dock at Corpus Christi, contributed to record throughput volumes in both our pipeline and storage segments during the year.

As you can see, we accomplished a great deal in 2014 in our effort to return to a 1-times distribution coverage and to also position ourselves for future distribution growth.

In fact, 2015 is already off to a great start as we recently purchased the remaining 50% interest in our Linden terminal joint venture. Owning this terminal outright provides synergies with our adjacent wholly owned terminal and provides opportunities for future expansion. This transaction was immediately accretive.

In addition, phase 2 of the South Texas crude oil pipeline expansion remains on schedule to come online and start generating incremental EBITDA late in the first quarter of 2015. This project is expected to generate annual EBITDA up to approximately 40 million on throughput volumes from the expansion ramp-up to 65,000 barrels per day.

As I mentioned earlier, our currently idled 12-inch pipeline between Mont Belvieu and Corpus Christi, Texas, should we in NGL service early in the second quarter of 2015. Once the line reaches full capacity, requirements for Occidental Petroleum is expected to generate an incremental $23 million in annual EBITDA based only on committed volumes.

With a strong 2014, recent acquisition of the Linden terminal and completion of these two internal growth projects we expect our 2015 coverage ratio to continue to exceed one times. We continue to remain focused on identifying the next wave of internal growth projects and synergistic acquisitions that will provide the catalyst for future distribution growth.

One of these potential internal growth projects was announced last fall after we signed a non-binding letter of intent with PMI, an affiliate of Pemex, for a proposed joint venture in which the two companies will develop new pipeline infrastructure to transport liquefied petroleum gases -- LPGs -- and refined products from the US into northern Mexico to meet the region's growing demand for these products. Both companies are working diligently to finalize the agreements associated with the joint venture transaction in the first quarter of 2015. If the agreements are finalized in the first quarter, we expect the assets in the joint venture to be completed and placed into service in the second half of 2016.

Now 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 our fourth-quarter results and 2015 projections. Tom?

Thanks, Brad, and good morning, everyone. As Brad just mentioned, 2014 DCF from continuing operations available to limited partners covered the distributions to the limited partners by 1.04 times, our highest annual distribution coverage since 2011. To obtain this coverage ratio, we increased our 2014 DCF from continuing operations by $97 million, or 31%, compared to 2013, which led to our highest DCF in the partnership's history.

During the fourth quarter, DCF from continuing operations available to limited partners covered the distributions to the limited partners by 1.12 times, our third consecutive quarter above one times covered and our highest quarterly distribution coverage since the third quarter of 2011.

EPU for the fourth quarter of 2014 improved 157% over the fourth-quarter 2013 adjusted EPU to $0.54 per unit from $0.21 per unit last year, and exceeded our guidance range of $0.40 to $0.50 per unit.

DCF from continuing operations available to limited partners for the quarter was $1.23 per unit, 27% higher than the $0.97 per unit generated in the fourth quarter of 2013, which again exceeded our guidance range of $1.05 to $1.15 per unit.

EBITDA in our pipeline segment increased to $86 million, which is $8 million higher than the fourth quarter of 2013. Within the segment, we experienced a 15% increase in total throughput and 19% increase in total revenue. Throughputs on our crude oil pipeline system increased 30% to a record 491,000 barrels per day as the segment continued to benefit from increased Eagle Ford throughputs, which increased 60% from about 168,000 barrels per day in the fourth quarter of 2013 to around 270,000 barrels per day in the fourth quarter of 2014.

Throughputs on our refined product pipelines increased 4% to 534,000 barrels per day, primarily due to increased production at one of our customers' refineries and a lighter overall turnaround schedule compared to 2013.

For the fourth quarter, the storage segment generated $68 million of EBITDA, up $6 million from last year's adjusted EBITDA. Throughput volumes increased 14%, while throughput revenues were up 15% due to increased activity at our Corpus Christi North Beach terminal, which continues to benefit from the increased Eagle Ford crude volumes shipped on our pipeline system. The segment also benefited from the second unit train at our St. James Terminal that came online in mid fourth quarter of 2013 as well as an increased vessel activity at our St. Eustatius terminal.

The fuels marketing segment earned $3 million of EBITDA during the quarter, down $4 million from the fourth quarter of 2013. Higher gross margins in our bunkering business during the quarter were offset by lower margins in our other fuels marketing operation and an increase in our accounts receivable bad debt allowance.

NuStar's G&A expenses were $27 million, $2 million higher than the fourth quarter of 2013, primarily due to the expiration of the asphalt JV) services agreement on June 30, 2014. Our interest expense net of interest income was $32 million, down $1 million from last year's fourth quarter due to lower interest rates on our new revolving credit facility, which closed in October 2014, and higher capitalized interest due to an increase in internal growth capital spending.

Our December 31 debt balance was $2.8 billion, while our debt-to-EBITDA ratio was 4.0 times, our lowest year-end ratio since 2008.

On January 29, NuStar Energy's Board of Directors declared a fourth-quarter distribution of $1.095 per unit, which will be paid on February 13. NuStar GP Holdings' Board also declared a fourth-quarter distribution of $0.545 per unit, which will be paid on February 17.

Now let me spend a few minutes talking about our projections for the first quarter and full year 2015. Our first-quarter EBITDA results in the pipeline segment should be higher than the first quarter 2014 and comparable to the fourth quarter of 2014. Increased throughput volumes from phase 1 of our South Texas crude oil pipeline system, which came online in the second quarter of 2014, should continue to benefit the segment.

Storage segment EBITDA results in the first quarter should be higher than the first quarter of 2014 as well as the fourth quarter of 2014. Higher Corpus Christi North Beach storage throughput, as a result of phase 1 of the South Texas crude oil expansion and incremental EBITDA associated with our recent acquisition of the Linden terminal, should benefit this segment.

First-quarter EBITDA results in our fuels marketing segment should be comparable to the first quarter of 2014 but higher than the fourth quarter. During the first quarter of 2015, we expect G&A expenses to be in the range of $23 million to $25 million, depreciation and amortization expense to be around $51 million, and interest expense to come in at approximately $32 million. Based on these projections, first-quarter 2015 earnings per unit should be $0.50 to $0.60 per unit, while distributable cash flow from continuing operations per limited partner unit should be in the range of $1.15 to $1.25 per unit.

(technical difficulty) of the segment EBITDA guidance for the full year 2015, we continue to expect our pipeline segment EBITDA to be $25 million to $45 million higher than 2014 and our storage segment EBITDA to be $10 million to $30 million higher in 2014, mainly due to incremental EBITDA associated with the Linden terminal acquisition.

We expect 2015 EBITDA results in our fuels marketing segment to be in the range of $20 million to $30 million. We project our 2015 strategic capital spending, which includes internal growth and acquisition spending, to be in the range of $400 million to $420 million and our reliability capital spending to be in the range of $40 million to $50 million.

And now let me turn it back over to Brad for any final remarks.

Thanks, Tom. As you heard today, 2014 was a very good year for NuStar. The year ended with a very strong fourth quarter and full-year coverage ratio in excess of one times.

In 2015, we will continue to focus on growing our core fee-based storage and pipeline operations through executing our internal growth capital program and identifying synergistic acquisitions. This positions us to cover our distribution again in 2015 and also continue building a foundation for distribution growth in the future.

At this time, I will turn it over to the operator so we can open it up to Q&A.

(Operator Instructions) Mark Reichman.

Just a few questions -- first, is the joint venture on the project to Mexico -- is that in your -- that is currently in your capital expenditure budget for 2015?

Yes, a piece of it is. Some of that $420 million guidance that we gave you does include what we expect to spend in 2015 on PMI, at least our estimate right now. We are still continuing to churn those numbers. We don't have a final number yet on what we think the CapEx is going to be on that, but we have put some in there for that project.

Okay. And then in the storage segment, it looks like maybe the rates were down just a tad bit, but the expenses were up in the fourth quarter. I think it was $75 million, and they had been running in the mid-$60 million for the first three quarters. I was just curious; what's behind that? Is $75 million in operating expenses somewhat unusual, or is there a way to bring that number down if you might expect rates to continue to erode a little bit?

I think the operating expenses number in the fourth quarter, Mark, is a little bit higher than normal. We mentioned on the third-quarter call that we were going to push some maintenance costs out of the third quarter into the fourth quarter. It's a little bit higher than usual. The run rate going forward is probably somewhere between that $65 million to $75 million number.

As far as the rates go, we're not seeing any deterioration in rates. In fact, we are starting to see just the opposite. With the collapse of the Brent spreads and some contango coming back in the markets, we are starting to see some rates improve across our system.

But the throughput revenues compared to third quarter were down a little bit, yet the throughput was up. So just looking at it revenue per unit, it looks like it was down and storage lease revenues were somewhat flat, just compared to the third quarter.

I think that's a function of just where those throughputs occurred at maybe some lower-rate terminals. I think the rates from terminal to terminal are not deteriorating any.

Okay, great. Well, that's helpful information. And then on the distributable cash flow calculation, I was just wondering if we could talk a little bit about the other items somewhat. I understand what that is, right, the deferred revenue. So it's not getting recognized in your revenue, so it's not falling through. But you are getting the payment. So you are highlighting the cash flow associated with that. Right? I was just wondering if you could just talk a little bit about how much of it was related to the efficiency payments and which assets that is and how we should maybe track those ins and outs on a going-forward basis.

Yes, I think a lot of that was the deficiency payments. We have several of those that impact that other number. And so from a run rate perspective, it's probably in the neighborhood of that. Now, there were some other things that were in there as well that are one-time deals. But I think for the most part, it's a pretty good run rate for that.

How much of the $11.7 million would you consider one-time?

Well, I think very little, really. I'm looking at this, and probably about, I'd say, $3.7 million, $3.8 million of it is a one-time and the rest of it is a run rate.

Okay. And a very strong quarter in your crude oil transportation segment with the contributions from expansions. I was just wondering on the outlook for capital spending, I think it was $900 million to $1.1 billion over the next several years. I was just wondering where you're focused. I think you had talked about expanding your South Texas crude oil pipeline system and acquiring crude oil gathering assets that might feed into that. But with the current environment, have you narrowed your focus maybe to not really looking outside to new shale plays? And then the last question would be if you could just comment on where you stand on liquidity and financing needs.

This is Danny Oliver. Let me just first talk about what we are focusing on in terms of development projects. We continue to work development projects and other shale plays outside of the Eagle Ford and continue some expansion projects, discussing with our customers in the Eagle Ford as well. We are certainly not limiting our discussions at all. I think we are realistic about the current price set in crude and how that may delay some of these developments. But we continue to work those diligently, and it remains to be seen just how -- certainly, some of the growth in the shale plays is slowing down. But it remains to be seen exactly how slow. But all I can tell you is that in our current business we continue to set records on volumes every month.

Yes, and on the financing plans for 2015, we indicated we have a capital program that's around $420 million. And right now we don't have an immediate need to go out to the capital markets either on the debt or the equity side to finance that. We have plenty of liquidity under our revolver. We plan on utilizing that to the best of our ability to fund that capital program. So as long as we don't pop through that, we don't anticipate really being in the capital markets anytime soon. There could be maybe a need towards the back end of the year, but right now it's 50-50 if we actually go in with any equity. And we don't see any debt out there this year, based on our current projection.

That's very helpful. Thank you for your comments.

Steve Sherowski.

Apologies if I missed this, but your new storage segment guidance -- does that just reflect your Linden facility acquisition? Or is there anything else baked into that?

That's the bulk of it. Most of it is related to the Linden acquisition.

Got you. And I would suspect, though, that since roughly 25% of your storage portfolio, I think if I'm not mistaken, is rolling over in the next 12 months. And given the structure of the forward curve that you should get some pricing power as these contracts reprice. Is that the right way to think about it?

I think so. But that's a slow -- we have a lot of contracts that are further dated than just one year. But it's going to be slow, I think, rolling through there. Plus, when you look at the total storage segment, that roughly 25% is going to renew in the next year. That's just our leased revenues. So we have another 25% or so of our storage-based revenue that's really mostly exclusive throughput. In other words, it's storage throughput that is related to refineries where we are the only way in or out of the refinery. Those contracts are -- we just rolled most of those out about 10 years. So they would sit way out there in the long-term side of that aging.

Got you, got you.

We are starting to see some -- we did just renew some -- or just signed some storage up at Point Tupper. Really, our last bit of available crude storage, we just signed in Point Tupper for higher rates than what the prevailing rates were just a quarter ago.

Got you, okay. So you currently don't have any idle storage capacity?

Really, the only -- we are about 97% to 98% utilized if we back Piney Point out of that number because Piney Point has been -- it's a contango facility. It's been idle. With that in our utilization, we are down to about 93%. That's the one place we have opportunity to lease some tanks that aren't currently drawing any revenue. And we are starting to build a lot of conversations about that storage.

Got you. And is there any CapEx associated with bringing that storage back online? And if you signed it at current market rates, what do you think the EBITDA contribution would be for that facility?

Well, there would be very little OpEx related to getting that up and going again. But that terminal is primarily a products terminal. It's about half heavy fuel oil; we have got heated storage for that. It's about a quarter distillate and about 25% gasoline. There's certainly some carry on the crude side of the business, but on the products distillate is still a backwardation. We are starting to see some carry and some desire to support some summer gasoline components like alkylate. So for the gasoline side of that terminal, I think if we get someone in there for that you could be looking at $1 million or $2 million maybe uplift. But we are not seeing a lot of interest in the rest of the terminal yet.

Got you, okay. And how easy would it be to convert it to store WTI, for example?

It's not -- the fuel tanks and the distillate tanks don't have floating roofs within them, so that would be a major capital undertaking to convert those to crude. Technically, I guess you could store crude in the gasoline tanks. But we have gasoline interests right now, and it's really not really suited for crude oil storage. They are small tanks that are suited for gasoline.

Got you. No, understood. And I'm sorry -- then just jumping back to the Linden facility acquisition. So the $10 million to $30 million uplift is really driven by that 50% interest. Does that include any synergies at all?

Yes, there were a few synergies associated with that. I wouldn't say it's a big number, but there are some. Yes.

Okay. All right. Can you -- are we talking about like $1 million, or $1 million or $2 million, or $5 million to $10 million or two?

Yes. It's $1 million or two.

$1 million or two? Okay. That's it for me. Thank you.

Brian Zarahn.

I appreciate the commentary on the low commodity price environment on your organic projects. Can you talk a bit about the puts and takes on your base business? And do you see any headwinds from low oil prices on your pipes and terminals? And then conversely, any uplift on your refined product assets from low prices?

I think with the lower crude prices there are some negatives and some positives. While it makes sense that growth rates in the shale plays might slow, we haven't really seen exactly how that's going to affect us. But as I mentioned earlier, we are setting records every month. In our South Texas crude system, we averaged just under 180,000 barrels a day in the fourth quarter of 2014. We're doing right at 185,000 barrels a day in January, and we were nominated just over 200,000 barrels a day for February. So we continue to see the crude come to us in the market here and now.

On the negative side, at St. James we have a couple of unit train facilities there. The collapse of the LLS and WTI spread recently has cut the unit trains that were coming to St. James quite significantly. So we've actually adjusted our 2015 forecast and removed anything above any kind of T&D committed volume from our forecast. Of course, now we are in a position where you can view that as upside because if the diff flows out then we will have some trains come back. And that's actually been happening just in the last week. We've seen the LLS spreads get back out to near $3.

Again on the plus side, what has hurt us with the Brent and LLS collapse and low prices has helped us on the storage side and also the contango market structure. We just in the last couple of weeks signed 1 million barrels of crude storage up at Point Tupper. And definitely I think the narrow Brent spreads and the contango in the market helped us get that done. And as I mentioned earlier, at higher rates than what the prevailing rates were just a quarter ago.

Right, and all the pluses and minuses that Danny just mentioned are included in our guidance number that we just gave you.

And on the refined products side, the refineries that we serve continue to run very well. In fact, we've got one in particular that's looking at an expansion this year. So we're not seeing any slowdown on the refined products side.

In terms of potential upside on the higher end market demand, do you see any potential uplift there on your refined product types?

I don't think so, other than the expansion. Valero has announced an expansion at their Maquis refinery. And outside of that, I think it will be pretty steady.

And then on some housekeeping, can you provide fourth-quarter expansion CapEx and your cash balance?

Fourth-quarter expansion capital was $117 million, and our cash balance was around $90 million.

$90 million?

$90 million, yes.

Okay. Then last one, Brad. I know you haven't gotten this question before, but what's your thought process now on distribution growth, given the 2014 coverage is under your belt now at over one times?

I've been waiting for that question all day. So nothing really changes there. I've told everyone we've got to walk for we run, so our primary goal is to return to one-to-one distribution coverage. The next step is we absolutely are focused on that and we secure our distribution for years to come. And then as our distribution coverage ratio continues to improve and we get up in the 1.05-1.1 range, and we have continued visibility into large trains of DCF coming our way, that's when we will look at increasing the distribution.

Thank you.

Gabe Moreen.

Given, I guess, the flux in a lot of producer budgets out there, I'm just wondering if you can talk in more detail -- I know there's a volumetric component to the South Texas assets, but there's also a take-or-pay component. Can you just talk a bit more about the puts and takes on that?

Yes. We've got -- on the current contracts that we have, they are basically all -- they have a firm committed volume that the deficiencies kick in at 85% of that volume. Of course, they are all shipping well over those -- their minimums today. But I think the type of customers that we have in our Eagle Ford system -- they are really, really the blue-chip-listed customers in the business, majors that we really haven't seen slowing down.

And in fact, in the Eagle Ford, obviously we hear a lot about CapEx cuts. And depending on which producer you talk to, it's slightly different stories. But from a macro level, most are cutting CapEx overall but tend to focus the money that they have left on the Eagle Ford because it's cheaper to drill, it's cheaper to get to market. So it's actually, in a way, sort of benefiting us since that's where our current business is focused.

Got it. As a follow-up to that, can you just talk about how long those minimums run through? I realize obviously if you have got those blue-chip customers and all that -- but how long are those minimums for?

They are all five-year contracts. Some of the early ones that we signed up have 2 1/2 or so years left on them. Some of our expansion projects still have four or five years left.

Got it, got it. And then switching gears to PMI -- pending, hopefully, PMI deal, can you just talk about what the negotiations are like? Are you guys talking size, contract length? And then also are there any special permits you would need to get that project executed, given the cross-border nature of the product being shipped?

Right. Well, we have -- there are a couple of border crossings that are pre-existing crossings. We have pipelines already crossing the border near Ruidoso and also near Nuevo Laredo. So we are working through some permits there, but it's nothing outstanding we need to do that we don't already have in place.

In terms of the negotiations of that contract, size and commitments and things like that have for the most been worked out. We have been working through narrowing our project costs down and improving the reliability of those numbers. So that's really what we have been working on over the past three months. And now that we're getting that narrowed down, we are both to the point that we are feeling pretty good about signing things up. So as Brad mentioned, we should have that done some time in the first quarter.

Thanks. And then I know everyone has asked about contango. Maybe I'm beating a dead horse or it was already answered. But is fuels and marketing itself contemplating engaging in contango trades itself? And if so, is that reflected in the guidance?

No, they are really not. I think it helps our business out, but we are not looking at going out and taking out a bunch of storage. And we would rather lease that storage to third-party customers. I think if we, for some reason, had a hard time finding a third-party customer we might look at that, but that hasn't in the case so far.

Great. Thanks, everyone.

Your next --

There's a very slim possibility of that.

Cory Garcia.

Quick housekeeping item -- I guess that $3.8 million one-time write-down that you guys talked about, is there a particular segment that it was flowing through so we can at least true up our operating model, whether it be pipeline storage or the fuels marketing?

Yes, that was a lower cost-of-market adjustment we made, and all of it hit our fuels marketing segment. It was a write-down of inventory to market. However, that would have been basically -- if we had been receiving 100% hedge accounting during the quarter, we would have been at that point anyway with our market value. So really the way to look at that, it was categorized as a lower cost of market adjustment. But for the segment for the year, it really didn't negatively impact it any more than it would have had we been getting hedge accounting all the way on that 100% hedge accounting.

Got you. Okay, that makes sense.

Got you to the same spot you would have been anyway.

Right, on a full-year basis. That makes perfect sense.

It was an incremental to anything else.

Right. That's helpful. And I guess I come back to the contango storage question again. I know you guys did some pre-contracting last spring at St. Eustatius. I'm just curious if there is any open or available capacity that would be looking to switch into crude, just given the broader macro crude backdrop, or is that contract more operational focus and less trading contango-centric?

Yes, at station in particular, all of our crude oil storage is leased up. We've got another two years left on that contract. The rest of our storage, like our fuel storage there, we do have some interest, certainly, from customers in more crude storage there. But that's a big capital program, converting fuel oil storage to crude. So we are not really there yet.

And again, really all of our crude storage in our entire system is completely leased out. So we will have to wait for renewals to see where the market is at the time.

All right. Thanks for the color, guys.

Shneur Gershuni.

I guess a lot of my questions have been asked and answered. But maybe I wanted to address the guidance a little bit. Kind of a two-part question. I think in your response to Brian, I just wanted to clarify with your puts and takes. When you think about 2015 EBITDA guidance, excluding the growth projects that you are currently working on, would you classify it as, like, your current new baseline, given the current commodity environment? You sort of talked about negatives offsetting positives and so forth. Is that the way we should think about 2015 guidance right now?

I think you've got in 2015 -- I was about to say yes, but you've got some of our expansions in the Eagle Ford that are going to come online middle of the year. So certainly those, beyond 2015, you will have full-year benefits. Same with our 12-inch line from Mont Belvieu, the propane line. That's going to come into service in the second quarter. So you won't yet see a full year of those two projects until 2016.

Okay. So if we think about them on a run-rate basis, that's how you are thinking your baseline is right now?

I think so.

Okay. And then when we think directionally about 2016 outside of what you just pointed out, we will be round-tripping some projects coming into place, anything else that you are looking for as potential upside drivers from your current levels? I think you had talked about Piney Point before as a potential driver. Is there anything else that you are focused on, CapEx and so forth, that could drive it incrementally higher?

Definitely. We've got several significant projects that we continue to develop in the shale plays and in other areas. And so, like I said, they are in the early stages of development, plus the PMI JV that we mentioned. But we will continue working those and developing those. But we are trying to keep that funnel of projects full.

Right, that $420 million of capital we're spending this year on growth, that will kick in at some point. The majority of that will probably kick in in 2016. So you will get a lift from that plus any other projects that are currently in development that aren't included in that $420 million.

And to the extent storage rates recover, you've also got about 25% of our storage leases coming off each year.

Right, so positive trend even on the recontracting. That makes sense. And then I think we spent quite a bit of time on the contango market. Is there any opportunity, should the global condensate market pick up a little bit, that you can take advantage of that as well, too? And could that present some additional upside?

I think the processed condensate issue here in the US, we are certainly working some projects with customers to segregate and keep the quality of processed condensate good all the way to a ship. We are working that with them. But right now, if we had -- any ability we have to segregate and ship processed condensate would just come out of our common stream.

I think the processed condensate from a more macro perspective really starts to pay off when you have no other market to go to in the US. And right now all of that crude, all the crude coming out of the shale plays, is finding a home.

Right, okay. That makes sense and wraps up my questions. Thank you.

Jeremy Tonet.

Thanks for all the color today in the Q&A. It's been really helpful. I was just wondering, and apologies if I missed it, as far as the 2015 CapEx spend, would you guys be able to identify what some of the chunkier elements of that spend is?

Yes, Jeremy. This is Chris Russell. It's finishing up Phase 2 in the Eagle Ford, finishing up the Houston 12-inch project. Also included in that number is the acquisition we just made of the other 50% of Linden. Those are the three biggest pieces. And then you'll have a little bit in there for PMI and several other projects we have going on.

Okay, great. And then looking at Linden, that was a really nice tuck-in acquisition on good terms there. I'm just wondering around your footprint, do you see other opportunities for nice little tuck-in acquisitions like that, or any thoughts that you have on the broader M&A market right now, given all the changes in the current environment?

The M&A market remains hypercompetitive. At least that's what we're seeing, with what I would consider extreme multiples being paid for assets. So the company that buys them has to have a particular desire for that asset. And for us, it needs to tie into something that we are doing, somehow further our strategy.

So Linden obviously did that. And so we are always looking for other things like Linden. Are there some others out there? Yes, there's probably a few. We are looking around diligently for those.

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

Selman Akyol.

Most of my questions have been answered, but just one quick thing. On the maintenance capital, you're up slightly for 2015 from the prior quarter. And I was wondering, is that just deferral from 2014 into 2015? Or was there just incremental dollars being spent on maintenance?

No, not really a deferral. I think we've got -- I know we've got some pipeline integrity work that just timing-wise is popping up in 2015. But nothing deferred from 2014.

I think we had indicated earlier in the year that we thought that our reliability could be up in 2015. And so we just found some integrity pipeline work that we needed to do there. So like Danny said, that's what's really driving that.

Got it. Thank you.

John Edwards.

Thanks for all the commentary here. Just if I could come back to -- I think Mark was asking the earlier question on the deficiency payments. So as I understood your comment, is it about $8 million a quarter that you expect to be recurring? Or maybe you could clarify that.

Yes, we are looking at the schedule now. I don't know that we have -- we might need to get back with you on that to give you the specifics on it. But at least $8 million of it was -- we had about $4 million of it, $3.7 million, that is clearly a one-time deal. And then the rest of it are deficiency payment amounts that could go forward.

So it's probably about, I'd say about $8 million or so. I think there's about another $7 million -- I'm sorry, about $6 million that is not a roll-forward either, so that was kind of a one-time hit as well.

It's probably going to be in the $2 million to $3 million number on a go-forward basis, John.

Okay, so excluding the one-time items, your coverage would have been more or less in line with your original expectations, correct?

Excluding the one-time items?

Yes. In other words, your opening remarks were indicative you were above your guidance. So I'm just thinking excluding these one-offs, more or less, you would have been about what you were expecting guidancewise, correct?

I think that's about right. Just remember that the LCM we took that's a one-time item, that was really part of the overall business margin process. So it was a one-time deal, but it was really part of our operational issues.

I think, though, what you are going to see -- what he's talking about, some of these that won't be repeated as a one-time item were associated with some capital reimbursements that certain -- some projects that we are working on, and customers were reimbursing development capital. And so it's sliding into this one-time kind of DCF adjustment. But going forward, that will be replaced with a contract that's kicking off revenue. So it will be in a different pocket, but you will see that money continue to come through the door.

Okay. And then maybe you could comment -- so you are guiding about $400 million-ish to $420 million CapEx. Is that a pretty good run rate, you think, going forward? Or is it just too hard to tell, given the sloppy commodity price environment we're in?

We hope that's low.

Yes, we hope it's on the low end of the range. But yes, I think it's too early to tell what you're going to do. We haven't finalized the budget for 2016 or 2017. I would certainly like it to be at that level or higher.

And then maybe you could also comment a bit -- are you seeing, given the environment we are in, how are you seeing it impact your backlog of projects? I guess you don't really talk too much about backlog, but can you give us any insight in that regard?

Quite frankly, it has not affected the projects that we are working on. If anything, there's a couple of things that may push out the timeline a little bit. But the projects remain viable, and we're going to continue to pursue them.

I don't have the list in front of me but I know the projects that we are -- specific projects that we are working on developing are over $1 billion of capital. But again, as Brad mentioned, you know how fast do those come to fruition, we don't know yet.

Okay, all right. And then have you given out -- I apologize if you've given this out already -- the range of investment you are expecting from your project with PMX?

No, we haven't given that out yet.

Okay. And then just to follow up Brian's question on your distribution growth, so is the current plan still to try to raise this year? Or is it really too early to comment on that?

I don't think that we said that the plan is to raise this year. I think we've said in the back half there's a possibility. But right now, I think what we are saying is we need to get some of these projects that are in development into a project and actually become a project and have visibility into growth in the future before we start putting any distribution increase guidance out there for you. But I don't think I've said that I think we're going to raise the distribution in 2015.

Okay. No, I'm not trying to put words in your mouth. I just wanted to clarify that. But yes, that's helpful. And then what's the actual liquidity number? Where do you guys stand on that? Or maybe you said it and I missed.

We've got $850 million available under our revolver today for end of the year.

Okay, that's really helpful. Thank you. That's all I had.

James Jampel.

Thanks for taking the question. I'm wondering, in your 2015 forecast, what is the average daily unit trains expected from the Bakken to St. James?

In our adjusted forecast, again, we took out pretty much everything over and above minimum commitments. I think we are in the neighborhood of 15 trains a month, about a train every other day.

That's the minimum commitment?

Yes.

And when do the minimum commitments expire?

We've got, I think, about two years left on those.

I see. And about what's the EBITDA associated with the minimum commitment?

$25 million, $30 million, somewhere in that neighborhood.

Okay, thank you.

(Operator Instructions) Brett Reilly.

It's actually Louis Shamie. Just to follow up on James's question, what's the current rate -- your customers have the sunk cost on that train every other day at the unit train facility in St. James. What's the current utilization, say, for December or January?

Danny Oliver

Well, December and January, it's well above those minimums. We are taking out -- it's just been there in the last month, right, that the LLS-TI spreads came into near parity. So we received information from some of our customers that through the month of February we would start to see declines down to minimums. So March is really the first month that we are going to have all the way down to those minimums.

I'm sorry, did you have a second part to that question?

Well, I actually wanted to ask something about Linden. So just thinking about the impact of Linden on the guidance, so prior to buying the other 50% of the facility, did that show up in your storage segment, or was that unconsolidated and flowed through equity earnings?

It was consolidated, flowing through equity and earnings. Once we bought the whole thing, then we own 100%, so it's consolidated and it pushes it up to the storage segment.

Okay, I see. So the change in the storage segment is not just the part that you bought, but the entire asset's cash flows are showing up?

Spot on, yes.

Okay, that explains a lot. Thank you very much, guys.

Brian Lasky.

Just one quick follow-up. On the recent contract that you signed there, Danny, can you just tell us what the tenor on that was? When you said it was higher, is there any way to quantify that in terms of order of magnitude?

I really don't want to get into the specifics on that. It's a one-year contract. But it was a good bit higher than the prevailing rates.

Okay, thank you very much.

There are no further questions at this time. I turn the call back over to the presenters.

Thank you, Nancy. We would once again like to thank everybody for joining us on the call today. If you have any further questions, please call NuStar's Investor Relations group. Thanks, and have a good day.

This concludes today's conference call. You may now disconnect.