NuStar Energy LP (NS) 2013 Q4 法說會逐字稿

Good morning. My name is Amy, and I will be your conference operator today. At this time I would like to welcome everyone to NuStar Energy L.P. and NuStar GP Holdings, LLC fourth quarter 2013 earnings conference call. (Operator Instructions). Mr. Russell, you may begin your conference.

Thank you, Amy. Good morning and welcome to today's call. On the call today are NuStar Energy L.P. and NuStar GP Holdings, LLC President and CEO, Brad Barron; Executive Vice President and CFO, Tom Shoaf, 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 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 revised expectations.

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 these non-GAAP financial measures to U.S. GAAP maybe found either in our earnings press release or on our website.

Now let me turn the call over to Brad.

Good morning. Thank you for joining us today. I would like to begin by thanking Curt Anastasio and Steve Blank for the many years of valuable leadership and service they provided to NuStar. Over the past year Curt and Steve worked hard on the strategic redirection of the Company, and I am pleased to say that we have made a lot of progress in our efforts to significantly reduce the Company's exposure to margin based operations while continuing to invest in growing our fee based storage and pipeline operations.

Let me recap some of the steps we have taken to eliminate the margin risk from our business. In early 2013 we completed the sale of the San Antonio refinery. We used the proceeds from that sale to fund the growth of some of our fee based pipeline and storage operations. Then in the third quarter of 2013 we signed a supply agreement that allowed us to improve the profitability of our St. Eustatius bunkering operations by significantly reducing our working capital requirements.

2014 is off to a good start as well. It is only early February and we have already terminated the crude oil supply agreement with PDVSA. Terminating this contract ends our obligation to purchase 35,000 barrels per day of crude and it took over $1 billion of potential risk off the table for NuStar.

Then on Monday we announced that we signed an agreement with Lindsay Goldberg, our joint venture partner in the asphalt business, to divest our remaining 50% interest in that business. This will reduce our financial liability by $100 million within six months of close. We expect to close this transaction and fully exit the asphalt business by the end of February.

Let me say a few words about that deal. At closing NuStar's $250 million seven-year revolving credit facility to the JV will immediately convert to a $175 million term loan, dropping to $150 million six months after closing. The entire loan balance is expected to be paid in full no later than September 2019. While we will continue to provide up to $150 million of credit support in forms of guarantees and letters of credit, this support begins to decline two years after closing terminates in September 2019.

We also expect the asphalt JV to change its name at closing, which will eliminate potential confusion in the marketplace and among investors. When we close NuStar will no longer own any refining assets. This is a great outcome for us. Our future net income results will not be burdened by the volatility of asphalt refining, and we will be able to focus 100% on growing our fee based storage and pipeline operations.

Speaking of our fee based businesses, this morning we announced that we signed a long-term agreement with Occidental Petroleum. Under this agreement Oxy will ship NGLs on NuStar's currently idled 200 mile 12-inch pipeline between Mont Belvieu and Corpus Christi, Texas. While Oxy will use the majority of the line's 110,000 barrel per day capacity, we will continue to market any remaining capacity.

We expect to spend around $135 million to get this line into full service. It will begin generating distributable cash flow for us in the second quarter of 2014, and it is expected to be placed in full service in the second quarter of 2015. Once the line is in full service, it is expected to generate approximately $23 million per year of incremental EBITDA.

As we also mentioned in this morning's press release, we expect to complete NuStar's new private dock at Corpus Christi North Beach terminal by the end of this month. That is more than two months ahead of schedule. This new state of the art dock will more than double our current loading capacity in Corpus Christi, and it will allow us to load crude oil simultaneously on all three of our docks at or above the capacity of any competitor in Corpus.

This additional capacity will also allow NuStar to handle all the new crude volumes associated with Phase 1 and Phase 2 of the South Texas crude oil pipeline expansion project as well as any additional volumes shipped on our pipeline systems to Corpus. Phase 1 of the South Texas project is now scheduled to start up in May of 2014, and will allow for increase throughputs of up to 35,000 barrels per day. Phase 2 is still expected to come on line during the first quarter of 2015, and will allow for an additional 65,000 barrels per day.

Turning to other items, on Monday we announced approximately $400 million of non-cash charges we are taking for 2013. We discussed the impact this would have on our fourth quarter results. The vast majority of these charges are related to our St. Eustatius and Point Tupper terminals.

Due to the changing market conditions and the application of certain accounting rules, we were required to write-down the Goodwill associated with those facilities. At the same time, we wrote down the assets values of a few non-strategic terminals.

I want to emphasize that the write-downs associated with St. Eustatius and Point Tupper are related to Goodwill only. These facilities are very profitable for us, and we are planning to invest and grow our operations at these key locations. While these non-cash write-downs did affect our fourth quarter EBITDA and EPU, there was no affect on distributable cash flow, our debt-to-EBITDA ratio or our future segment earnings guidance.

Moving on to our fourth quarter results. EPU adjusted for the asset write-downs was $0.21 per unit, which was within our guidance range of $0.20 to $0.30. Our continuing operations produced DCF available to limited partners of $0.97 per unit, which is higher than our guidance range of $0.80 to $0.90 per unit. As a result our coverage ratio for the fourth quarter was 0.89 times; that is our highest coverage ratio since third quarter of 2011.

Turning to the fourth quarter segment results, each of our three business segments generated adjusted EBITDA higher than last year's fourth quarter. In our pipeline segment we continuously increased throughputs in our Eagle Ford pipeline system, and we are encouraged by customer interest in our pipeline and terminal loading facilities. EBITDA in our pipeline segment increased to $78 million or $16 million higher than the fourth quarter of 2012. Total pipeline revenues increased 15%, mainly due to increased throughputs on our Eagle Ford pipelines.

Excluding the non-cash charges we discussed earlier, storage segment adjusted EBITDA was $62 million for the quarter. This is $3 million higher than last year's fourth quarter and comes despite a decrease in segment revenues of $12 million as operating expenses were down by $15 million. In the fourth quarter our fuels marketing segment earned $7 million of EBITDA, which is slightly higher than the $6 million for the fourth quarter 2012.

NuStar's G&A expenses last quarter were $25 million; that is $4 million less than they were in the fourth quarter of 2012. Our interest expense was $34 million; that is up $12 million from fourth quarter of 2012. This increase was mainly due to higher borrowing costs associated with the January 2013 issuance of around $400 million of junior subordinated notes. NuStar's year-end debt balance was $2.7 billion, while our debt-to-EBITDA ratio was 4.4.

Equity earnings in joint ventures were negative $13 million for the quarter. Our remaining 50% share of the asphalt joint venture, which we expect to divest in February, generated losses of $18 million, while our 50% in the Linden, New Jersey storage terminal earned $5 million during the quarter. Last week NuStar Energy's Board of Directors declared a distribution of $1.095 per unit and the distribution will be paid on February 14. NuStar GP Holdings' Board declares a fourth quarter distribution of $0.545 per unit, which will be paid on February 18.

Now let's shift over to our projections for the first quarter of 2014. We expect first quarter EBITDA results for the pipeline segment to be higher than first quarter 2013 but lower than last quarter. We expect the pipeline segment to continue to benefit from the completion of our Eagle Ford Shale project; however, this will be tempered by some of our customers' refinery turnarounds during the quarter.

We project EBITDA in our storage segment to be lower than the first quarter 2013, primarily due to the reduced LLS to WTI profit sharing benefit at our St. James terminal. However, adjusted EBITDA for the first quarter of 2015 should improve over last quarter, primarily due to the benefit of our second St. James rail car off-loading facility which was completed in November of last year.

Results in our Fuels Marketing segment should continue to benefit from our improved bunker operations. In addition, the segment should benefit from refined products blending and our crude oil trading activities at the St. James terminal. Segment's first quarter EBITDA should be higher than the first quarter of last year and comparable to last quarter.

During the first quarter, we expect G&A to be in the range of $23 million to $24 million, depreciation and amortization expense around $47 million to $48 million and interest expense in the range of $33 million to $34 million. Based on these projections, first quarter earnings per unit should be $0.30 to $0.40 per unit while distributable cash flow from continuing operations per limited partner unit should be in the range of $0.85 to $0.95 per unit.

Based on the recent developments I mentioned in my opening remarks, we have updated our full year financial projections for 2014 as well. Let me walk you through those.

For the full year 2014 pipeline segment EBITDA is projected to be $40 million to $60 million higher when compared to 2013. 2014 EBITDA growth is expected to come from a full year's benefit from the Eagle Ford project we completed in August of last year, increased throughputs due to the February completion of our dock that I mentioned earlier, third quarter 2014 start up of Phase 1 of our South Texas crude oil pipeline system project and the July 1, 2014, FERC tariff adjustments.

Our 2014 storage segment EBITDA is projected to be comparable with 2013. EBITDA growth realized from the completion of our second unit train at St. James terminal in November of last year and from additional storage throughputs associated with the completion of some of our Eagle Ford Shale projects will likely be offset by reduced profit sharing proceeds on our first St. James unit train. This is a result of the narrowing of the LLS to WTI spread that I mentioned earlier.

2014 EBITDA results in our Fuels Marketing segment are expected to be in the range of $10 million to $30 million. Most of the projected increase in the segment's results is driven by recent improvements in our bunkering operations.

As we mentioned in the past, our Fuels Marketing segment expects to pay our storage segment around $25 million in annual storage fees for tankage utilized to support Fuels Marketing's operations. These fees provide our storage segment with EBITDA in locations that are otherwise challenged. So based on these projections, we expect to be covering our distribution in the second half of this year. We also expect to cover the distribution for all of 2014.

As you have heard this morning, we have made a lot of progress over the past couple of months with regard to our goal to reduce the Company's exposure to margin based operations while continuing to grow the fee based side of the business. We are currently pursuing a number of other exciting new business opportunities that should allow us to increase our distributable cash flows, improve our coverage ratios and restore distribution growth in both NuStar Energy and NuStar GP Holdings.

Our employees are focused on continuing to run our operations safely and reliably, executing our growth projects on time and on budget and identifying new opportunities to increase cash flows and DCF. We are very excited about the tremendous potential we see to our fee-based operations and improve our earnings in the months and years ahead.

Let me turn it over to the operator, and we will open it up for Q&A.

Thank you, sir. (Operator Instructions). Your first question comes from Brian Zarahn of Barclays.

Good morning.

Morning.

Just want to say first of all congratulations to Brad and Tom and best of luck in the new roles.

Thank You.

The Corpus Belvieu NGL pipeline -- can you provide a little more color as to the contract with Oxy, the duration, is it take or pay or volume based?

I am going to let Danny Oliver, our Senior Vice President of Business Development take that question.

It is five-year initial term. It is take or pay. As Brad mentioned, without giving too many specifics, they do have a take or pay on the majority of that 110,000 barrel per day line, and it is expected to go into full service in Q2 of 2015.

And then is the take or pay -- does that capacity ramp up or is it a fixed capacity from 2015 forward?

It is a fixed capacity from 2015 forward.

Okay. Any just general sense of how much other capacity remains available on the line that is not contracted?

We have close to a third of the line still available.

Okay. Is it there a general sense of expected maintenance CapEx or the NGL line once it is in service?

We already have spent a lot of money on maintenance and reliability issue prepping the existing line for the new service, and then there will be a brand new connection from where the line currently terminates in Houston to Mont Belvieu. So we should not have anything extraordinary on the horizon there.

Okay. And then any update on your expected financing plans for 2014 expansion CapEx?

Currently we are just planning right now to use our revolver -- revolving credit facility to do that. We do not have any real immediate plans to go into the capital markets at this time.

Last one from me. Any update on potential terminal asset sales?

No, we don't have any big sales planned any time soon.

Thank you.

Your next question is from Steve Sherowski of Goldman Sachs.

Hi, good morning. You mentioned your target for excess coverage in 2014. At what level would you become comfortable with considering distribution increases going forward?

What I talked about was covering our distribution in 2014, and once we return to full distribution coverage that is when we will start examining when and how to increase the distribution. We need to first get back to full cover and then we will take it under advisement.

Okay. On your credit extension for Lindsay Goldberg, are there any opportunities to terminate those agreements before between 2017 and 2019, or are you pretty much locked into or just limited to excess cash flows from that JV paying down your credit?

You described it correctly. Those agreements run to 2019, but they can be paid down by excess cash flows from the JV.

Okay. On Corpus Christi would you remind me what is the current loading capacity at that facility, and what is the utilization rate currently?

The existing dock last year was fully utilized because we split that dock with a competing terminal, but since then we are both -- as of February we will both have our own docks as well so the capacity increases quite significantly. We went from splitting one dock to now splitting one and we each have our own dock with similar capacities. But we can load at 30,000 barrel per hour rates at both docks, and it's clearly more capacity than what we currently need to clear all of the Eagle Ford out of the system.

Okay. Thank you. That is it for me.

Your next question is from Mark Reichman of Simmons.

Thank you. A lot of my questions have been asked, but what do you expect with your projection of 85% to 95% DCF in the first quarter? What does that assume on maintenance CapEx in the first quarter?

For the first quarter it would be about $8 million.

About $8 million, okay. You may have already stated and I missed it, what is the amount you have remaining under your revolver, and what is your actual borrowing capacity?

We have about $830 million available under the revolver as of year-end, and the revolver is a $1.5 billion revolver.

$1.5 billion, okay. Great. Also with regard to the write-downs, your guidance for incremental EBITDA is really pretty much unchanged from your December guidance by segment. The write-down it seems like you already had a pretty good handle on the earnings power of the storage segment going forward, pre write-down.

I wanted to ask also about asset divestitures. I think in prior calls you had mentioned the possibility that Piney Point could be a potential. Could you provide just a little color on your thinking around the Piney Point asset?

On the Piney Point asset we have reduced all of our operating expenses to a minimum. We believe that terminal is a contango terminal, and its best position is to wait until contango comes back. We have very little operating expenses, and we are just holding it.

Okay, great. Thank you very much.

Your next question comes from Cory Garcia of Raymond James.

Good morning, fellows. Going back to the storage segment, instead of thinking about the divestitures across your asset base, should we be thinking about the potential for any conversion from a refiner product tankage into crude service, particularly thinking about some of the coastal assets you have that are pretty well positioned for any potential there?

In some of our challenged terminals for instance, where we may have been in fuel oil service and there is just no demand for that, we are certainly looking at opportunities to change service and get into maybe a distillate blending mode and export mode. Yes. We absolutely look at that when we are trying to fill some of those blank spots in the storage segment.

It would still be a distillate or more refined product field versus anything outright to crude service, right?

I think as far as the Eagle Ford goes, those tanks were in crude service before, and as we built this Eagle Ford they are still in crude service. They are just pointed in a different direction; loading out instead of receiving in. But I think most of our other locations we are sticking with products. We are just considering changing product service.

Okay. That makes sense. Switching over to your St. James rail terminal, congrats on, obviously, bringing that second phase online. Would you remind us how much of the volumes across that facility are take or pay? I think it was 110 million if you look at the EOG and your second shipper on Phase 2; is that the right number to be thinking about?

That is in the ball park. It's right at it.

It's about right.

Okay. Have you been approached by anybody in terms of any back haul opportunities for condensate? I know that is sort of an off the wall question but every now and then that kind of works its way out there.

We have had some discussions about adding heavy crude from Western Canada into the St. James mix. Right now it is predominately Bakken light crude, so those trains are not going back to Western Canada. So they are not really looking at that back haul opportunity.

If we end up at some point in the future adding heat to that facility to bring in the heavy crudes or maybe even a dil-bit of diluted crude from Western Canada, then I think we could look at that. But right now all of our customers are in the Bakken play.

Okay. I appreciate the color, guys. Thank you.

Your next question comes from Paul Jacob of Credit Suisse.

Good morning, guys. Thanks for taking my question. The first one I had was with Corpus coming on line a little bit sooner than you had anticipated, do you expect that Eagle Ford volumes will ramp faster than what you outlined before?

We do think we are going to see some quicker ramp up. Now our contracts are really set up more in line with our expansion of the pipeline. This removes kind of a bottleneck that we have experienced at the dock. But our contracted volumes are expected to come up really with the completion of the Phase 1 project in the third quarter of this year, but I do think with the removal of that bottleneck we will see some volumes start to sneak in a little early.

Okay. That is helpful. And then could you describe a little bit more detail surrounding the bunkering fuel improvements that you talked about?

I will tell you in the bunkering operation at St. Eustatius we signed a supply agreement, and with that supply agreement the supplier of the fuel oil took over and began paying over $3 million in tank rental revenues to NuStar L.P. versus the bunkering operation paying that. So there is $3 million more external revenue coming in the door.

Going with the supplier we will not have backwardation cost on the inventory. That totals a little over $2 million worth of help on the backwardation. The fact that we have over $16 million worth of working inventory that will be off the books and will now be supplied by the third party supplier there is over $3 million worth of interest expense we won't have.

And we have optimized our operations, and with that we have been able to reduce a barge and one vessel and along with the fuel that is a little over $7 million. Even though the bunker calls this year haven't been lower, they have been about the same, the volume per call has been down. But we anticipate this to come back, and so we see that the bunker operation will have a very big improvement over 2013.

Okay. Thank you for the color on that. Last one from me is I am curious how the profit sharing is working on the CBR terminal. Is there any chance you could put it in terms if that spread were to drop by, say, $1, what the impact to your EBITDA might be?

You said CBR, you mean the St. James facility?

Yes.

I can't get into details really on that, but I would tell you there is no profit sharing when the WTI LLS spread is below $7. It has been below $7 since, I don't know, April or May of last year. We touched that level in January, but we are back down below that now. So we don't have anything in our forecast in regards to that profit sharing for this year. If it happens, that would be great, but we are not counting on it.

Okay. All right. Thanks guys.

Your next question comes from James Jampel of HITE.

Congratulations once again on your new roles. What business opportunities particularly excite you when you look at your footprint and your operations? Where will you be focusing? What levers will you be pulling? Where would you like NuStar to be, say in 2015?

In the short term our main focus is the Eagle Ford. That is where our biggest opportunities are. We also see opportunities around our St. Eustatius terminal. There is always opportunities around our St. James terminal. We will be looking at all of those, and probably be looking at our Point Tupper terminal as well. Those are my primary focuses for the next two years.

Are there any lines of businesses that you might be reviewing for de-emphasis or any prospects for cost cutting?

We have been so focused from moving away from margin based businesses. The announcement of getting out of the asphalt JV completes our exit from the refining business. As I said in the speaker notes, we are going to be 100% focused on growing on our fee-based pipeline and storage business. We would like to grow that in a balanced way, but whichever opportunity comes along that has the best return within our system that makes sense strategically for us, that is what we are going to pursue.

Okay. Thank you.

Your next question comes from Brett Reilly of Zimmer.

Morning, guys. Just had a question on the NGL pipeline with Oxy, could you remind us what the payments will be in starting in the second half of 2014?

What the payment will be?

Yes, the magnitude relative to the $23 million.

It's less than $23 million because we are -- quite a bit less than the $23 million because we are not in full service, but I don't think we have given any guidance. But something in the $5 million to $10 million range.

Okay. And with respect to the deficiency payments you had in the quarter, is that something we should expect to continue for the remainder of the year, and if you could break out how much was deficiency payment versus construction funding?

Brett, are you talking about the other items on the DCF schedule?

Exactly.

Most of that relates to settlement of a legal dispute, so it's not really deficiency payments.

So it was just mislabeled?

Part of it is a deficiency payment, but it's as not as much a deficiency payment as it is a T&D. We have basically received a payment in advance on some construction costs and some pipeline movements and we will recognize the revenue or amortize the revenue over the next 12 months to 18 months. But we took the benefit from the cash payment in our DCF statement for the fourth quarter.

Okay. And is that something we will see in 2Q and 3Q?

At this point in time we don't know for sure.

Okay. That is all for me. Thanks.

Your next question comes from Jeff (Inaudible).

Good morning and congratulations. Your G&A and your OpEx particularly on the storage side are still significantly wide of your peer group. What kind of opportunities are there to get the G&A down and same thing on your OpEx per barrel? What levels are you trying to reach, and what more can be done?

On the OpEx side of the business for the pipeline and storage business we have three primary focuses for OpEx reduction and a study into the OpEx for benchmarking, but the first one comes from looking at risk-based inspection on our APi 653 tanks. The second one comes from the energy optimization in our pipeline systems. The third one centers around maintenance planning and maintenance execution. And then like I said, in order to really take a look and begin benchmarking ourselves against competition, we are going to be looking at a study that we will complete in 2014 that will help us compare on a dollar per barrel basis and in the storage basis.

That is helpful. Any initial thoughts on the magnitude by which you could reduce that or is it too soon to tell?

It is too soon to tell. I could give you a range but I think it would be best if I just wait.

Okay. Are there unique factors affecting your business, because it seems like that would be an area where you could add significant value immediately? Are there things that factor into your OpEx per barrel calculation that wouldn't affect the peer group that makes you look so drastically different?

We do have a lot of very large marine terminals; St. Eustatius, Point Tupper, Corpus, and Amsterdam. Those typically run at a much higher OpEx level than a normal landlocked terminal because you are employing tugs and barges and assist vessels and what not. So, yes, I do think there are some unique circumstances because of the rather large footprint in the marine terminal business.

Okay. Then the G&A rate, the $23 million to $24 million, is that a good run rate going forward, or is there the opportunity to cut that down as well?

That is a pretty good run rate going forward.

Okay, great. That is all from me. Thank you, guys.

Your next question comes from Selman Akyol of Stifel.

Thank you. Good morning. I just wanted to follow up on the G&A question. You were down 15% from last year but up fairly sharply from the third quarter and a run rate around $19 million, so can you talk a little bit about that dynamic that is going on there?

For G&A we said we have a run rate of about $23 million, $24 million. And this year we have actually -- we did a lot of cutting in that area to the tune of $20 million to $30 million worth of cuts across the board that bled in from G&A and also went into OpEx and all that. We went through some pretty significant cuts this year to try and reduce that. That was our objective and we got there.

I want to add something too. Selman, you asked about the third quarter versus fourth quarter numbers. The G&A has been varying up and down a little just because as the unit price changes some of our compensation plans change too, so that expense can go down when unit price drops and it can go up when the unit price increases.

All right. Thanks.

Your next question comes from Jeff Birnbaum of UBS.

Good morning, everyone. I would also like to congratulate everyone on their new roles as well.

Thank you.

Sorry if I missed this earlier, but did you give an update on how recontracting is going on some of the storage terminals that you have really been discussing the most in the past few quarters?

I can give you a little update. In 2013 we think we realized the majority of some of the lower storage rates that we have seen prevalent really throughout the work. We think we have taken the brunt of most of that. We do have a few locations where we have some underutilized assets and still looking to fill some tanks.

It is a little early to talk about some of these, but we have some exciting things we think going on in some of those facilities and I think will be a real positive turn in our outlook for 2014. But we are still working on getting those contracts executed. But in all I am pretty positive about what is going on here for the rest of 2014 getting back to a more fully utilized system.

Okay. Thanks. And then one more following up on some of the Eagle Ford volume questions and the comments on some of the strength you have been seeing in that system. Do you know what the volumes actually were on that system in the fourth quarter, and what overall drove crude throughputs down quarter-over-quarter and year-over-year?

Eagle Ford throughputs in the fourth quarter were around 190,000 barrels a day (multiple speakers).

And we are at about that level today, and really as I mentioned earlier, while we may see some of those early volumes trickle for the expansion that is coming online in the third quarter of this year, I think our next real step up is when that expansion is complete in the third quarter.

Okay, great. Thanks a lot.

(Operator Instructions). There are no further questions at this time. Sir, do you have any closing remarks?

Thanks, Amy. I would just like to thank everybody for joining us on the call today. And if anybody has any additional follow-up questions, please feel free to call the Investor Relations Department at NuStar. Thank you very much.

Thank you for participating in today's teleconference. At this time you may all disconnect.