NuStar Energy LP (NS) 2018 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the NuStar Energy L.P. Fourth Quarter 2018 Earnings Conference Call. (Operator Instructions) As a reminder, this conference call is being recorded.

I would now like to introduce your host for today's conference, Pam Schmidt, Vice President of Investor Relations. You may begin.

Good morning, and welcome to today's call. On the call today are Brad Barron, NuStar Energy L.P. 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 refer to certain non-GAAP financial measures. These non-GAAP financial measures should not be considered as alternative to GAAP measures. Reconciliations of certain of these non-GAAP financial measures to U.S. GAAP may be found in our earnings press release with additional reconciliations located on the Financials page of the Investors section of our website at nustarenergy.com.

With that, I will turn the call over to Brad.

Good morning. Thank you all for joining us today. We have a lot of positive news to report today about our strong financial results for fourth quarter and full year 2018. Before I turn it over to Tom to provide you with the details on our results, I'll take a few minutes to provide some context of those results and review what we achieved in 2018 and how those achievements have positioned us for strong stable growth.

This time last year, we presented our comprehensive plan to reposition NuStar during 2018 to meet the changed MLP landscape. A paradigm shift had taken place in the MLP sector. And we recognize that in order to continue to build on the strength of our superior asset base, we would need to take the steps necessary for NuStar to achieve the hallmarks of what some refer to as MLP 2.0, strong distribution coverage and low leverage, while at the same time, simplifying our corporate structure, eliminating our Incentive Distribution Rights or IDRs and minimizing our need to access the equity capital markets.

Over the course of this past year, we executed on our plan step-by-step and achieved the goals we set for NuStar. Number one, strong coverage. Last March, when we first filed our Form S-4 for the simplification transaction we projected, we finished 2018 with a coverage ratio in the range of 1.1 to 1.2x. Thanks to the hard work of our employees and solid performance of our strong asset base, we finished 2018 with a 1.42x cover.

Number two, low leverage. In part, due to successful divestiture of our U.K. and European assets, we lowered our debt to EBITDA ratio to 4.05x, which allowed us to achieve our 3-year deleveraging target in a single year. Number three, simplified corporate structure and governance. Thanks to our simplification transaction, we are now a single publicly traded company with no IDRs.

Number four, minimal equity capital needs. Because of the combined impact of all the self-help measures we took in 2018, we do not anticipate needing to access the equity markets before 2022. Last March, we told you our plan was designed to ensure NuStar had the healthy balance sheet needed to execute on our organic growth opportunities as economic conditions improved. And here we are 1 year later, we've implemented our plan as we told we would, our metrics have surpassed our own projections, and provide NuStar with the financial flexibility required to produce strong stable growth. We now have more opportunities for higher-return organic growth projects than in any time in our history. And the future truly looks even brighter than we anticipated at the beginning of 2018.

As I mentioned on our last call, by far, the most attractive opportunities for midstream MLPs for capital projects to solve the logistical dislocations in or emanating from the Permian Basin. It's not surprising, Permian Basin's production has grown with more strength, speed and consistency than any other U.S. shale play through high and low crude price cycles and is expected to continue to be the dominant U.S. shale play far into the future.

NuStar's uniquely situated to benefit from a number of Permian-driven opportunities inside the basin and beyond. Inside the basin itself, we continue to expand our Permian Crude System as planned. As we've told you on past calls, we acquired our crude system not only because it's a great pipeline system but also because of the quality of the rock underlying our acreage dedications. The system sits atop some of the highest quality acreage in the Permian. And that geological superiority has attracted some of the most effective and efficient drillers in the country to drill in this portion of the basin. Given these key advantages, we acquired the system with confidence that the production growth from our dedicated acreage would far outpace the Permian Basin as a whole. And that's exactly what is done.

Since we acquired the system in May of 2017, the Permian Basin volumes have increased by 60%, which is impressive by any measure. However, during the same period, our Permian Crude System throughputs have increased by 190%, which is jaw-dropping. Numbers like these speak for themselves. So suffice to say, we are very happy with our system's performance and outlook.

But we're also reaping the rewards of the Permian Basin's production growth outside the basin, from our South Texas system to our pipelines in northeast Texas to our world-class export facilities in Corpus Christi and St. James.

In recent months, we've seen ripple effects from the Permian Basin production on our South Texas Crude System in Eagle Ford, which has been benefiting from WTI volumes arriving by truck. We're currently seeing throughput volumes averaging 192,000 barrels per day, significantly above our minimum volume commitment of 116,000 barrels per day for the system. We are also expanding our Wichita Falls crude oil pipeline to accommodate additional barrels from the Sunrise pipeline expansion from Colorado City to Wichita Falls. The Sunrise connection and our related expansion project brought our customers additional access to Permian crudes, as we expect to increase our throughput. It brings a healthy return for a relatively small capital outlay. And we'll further afield in Louisiana. As we told you on our last call, we restarted our unit train offloading facilities at our St. James terminal for customer commitments for 5 to 10 trains per month bringing WTI, Bakken and WCS barrels.

Among the many in Permian -- among the many Permian ripple effects, the most promising of all for NuStar may be Gulf Coast crude export growth. Over the course of the next 12 months or so, approximately 2.1 million additional barrels of long-haul crude pipeline capacity from the Permian to Corpus Christi will be placed into service, bringing a total capacity of Permian Crude appointed at the port of Corpus Christi to about 2.6 million barrels. And if predictions prove correct, propelling the port to be the #1 crude export outlet in the United States. Don't forget, these Permian volumes are in addition to the existing pipeline capacity from the Eagle Ford. NuStar is uniquely positioned to take advantage of this growth. We have a world-class storage terminal with 3 docks and related export infrastructure. And we are poised to benefit from what some have characterized as the oncoming tidal wave of outbound life barrels.

On our last call, we announced we had signed long-term contracts with Trafigura to support projects to initially connect our South Texas system with the Cactus II Pipeline near Oakville to transport WTI barrels on our existing 16-inch pipeline to our Corpus Christi, North Beach export terminal and interconnect or construct a new 8-mile, 30-inch pipeline from a new connection in Taft, Texas to our Corpus Christi terminal as well as 600,000 barrels of additional storage. Those projects are underway and on schedule. And we expect to begin providing service to Trafigura on the 16-inch pipeline as soon as this summer.

We are also exploring connecting our existing South Texas system to other long-haul pipeline projects from the Permian to Corpus Christi. At the same time, we're working to ensure our Corpus Christi terminal has the connections and services to provide the optionality that our customers may need in the future, including continuing discussions to connect our facilities with proposed crude oil export terminal projects with VLCC loading capability.

Beyond Corpus Christi, we also expect to see benefits of export pressure from U.S. shale plays at our St. James facility as well. Our St. James facility offers optionality and critical connectivity along with export services with room for expansion. And we are looking to ensure our facility is prepared to take advantage of promising, evolving regional opportunities. We are near completion of our connection to the Bayou Bridge, which will bring volumes of Bakken and Permian crude to St. James. And we expect to begin receiving barrels through that connection as early as the second quarter, increasing demand for storage and export services we offer there.

In addition to the proposed reversal of -- in addition, the proposed reversal of cap line would bring large volumes of heavy Canadian and Bakken crudes to St. James for use in regional refineries as well as for export.

Moving on, we also have updates on what we are accomplishing outside the Permian's extended reach. One great example of our successful optimization of our legacy asset base is our Central East system. Thanks, in large part, to the synergies and positive contribution of our Council Bluffs acquisition last year, we've increased our capacity and enhanced our market reach, which in turn has expanded our platform for butane blending. The combination of these improvements helped us generate nearly 25% more EBITDA on the system in 2018 than 2017.

Last year, we announced projects to facilitate the export of refined products in northern Mexico. These are progressing well and are backed by several long-term T&D contracts with strong creditworthy customers, including Bolero and Howard Energy. As we have discussed in prior calls, we've been investing in our West Coast assets through a number of low-cost, high-return biofuels projects to meet emerging demand in the region for biofuel storage, which commands a premium over other storage rates.

While the total investment for all these projects is only about $70 million, we expect these projects, which are going to service this year and next, to deliver EBITDA multiple of around 6x. The projects for Trafigura, the northern Mexico projects and the West Coast biofuel projects offer a great illustration of why we decided to sell the U.K., Europe assets back in November. We sold those noncore assets for proceeds of about $270 million at a multiple well in excess for our targeted 10x multiple, so that we can redeploy that capital for these very low multiple projects that grow our core business.

Now I'll turn it over to Tom to provide the details of our strong fourth quarter and full year 2018 results.

Thanks, Brad, and good morning, everyone. As Brad mentioned earlier, 2018 was a transformative year. We executed on our comprehensive plan to improve our key metrics, reduce our need for future equity and to reposition NuStar to execute on organic growth opportunities. As a result, our 2018 EBITDA, net income and EPU includes the effects of a $79 million hurricane insurance gain in the first quarter, a simplification charge of $377 million in the third quarter that affects EPU only, and a noncash charge of $43 million from the sale of the European operations in the fourth quarter.

As a result, those amounts are not comparable to the corresponding periods of the prior year. DCF excludes the effects of those transactions and is therefore comparable between the periods. In the earnings press release, we have included a table showing fourth quarter and full year 2018 EBITDA, net income and EPU as adjusted to be comparable to the amounts from prior year. And today, I will be referring to those adjusted numbers.

As you can see, in all cases, our results improved over the prior comparable period. For the fourth quarter of 2018, we generated adjusted EBITDA of $165 million, up 15% compared to the fourth quarter 2017 EBITDA of $144 million.

Adjusted net income for the fourth quarter 2018 was $45 million, up 81% from the fourth quarter of 2017 net income of $25 million. Fourth quarter 2018 DCF available to common limited partners was $91 million, up $50 million or 119% for the fourth quarter of 2017. And as Brad mentioned earlier, our distribution coverage ratio to the common limited partners was approximately 1.42x.

For the full year 2018, our adjusted EBITDA was $666 million at the high end of the guidance range we provided on last quarter's call, with adjusted EBITDA being up 12% compared to 2017 EBITDA of $595 million.

Full year 2018 DCF available to common limited partners was $354 million, up $96 million or 37% from 2017, and our distribution coverage ratio to the common limited partners was also approximately 1.42x for the full year.

Fourth quarter 2018 EBITDA in our pipeline segment was $115 million, up $26 million or 29% from the fourth quarter of 2017, largely due to continued throughput volume ramp on our Permian Crude System, as well as increased throughput volumes on our McKee System due to the large turnaround at one of our customers' refineries in the fourth quarter of last year. We also saw increased volumes on our East Pipeline System, driven by our CHS, Council Bluffs, Iowa acquisition.

Fourth quarter 2018 EBITDA in our storage segment was $67 million, down $16 million from the fourth quarter of 2017 due to a variety of factors, including decreased revenue associated with our sale of the European assets in the fourth quarter and the impact of decreased storage rates at certain locations due to contract renewals in a backwardated market. As we mentioned in November, PDVSA also agreed to reduce its footprint at our St. Eustatius terminal to allow us to diversify our customer base there as we are recontracting that storage over this year and next.

Our Fuels Marketing segment generated $13 million for the fourth quarter of 2018, up $11 million from the fourth quarter of 2017, mainly as a result of higher butane volumes and margins. And on -- I'm sorry, higher butane volumes and margins on our East Pipeline systems, as well as improved margins on our bunkering operations.

Our December 31 debt balance was $3.1 billion, while our debt to EBITDA ratio was 4.05x, down significantly from 4.5x at the end of the third quarter and below our 2018 credit agreement covenant threshold of 5.25x.

Now let me spend a few minutes talking about our projections for 2019. We continue to expect NuStar's 2019 EBITDA to be in the range of $665 million to $715 million. With regard to 2019 capital spending estimates, we deferred certain 2018 spending into 2019, and as a result, we now plan to spend $500 million to $550 million on strategic and other capital in 2019. So expected strategic capital spending for 2018 and 2019 combined has not changed.

Based on our revised spending forecast, we now expect to spend approximately $185 million on the Permian Crude System, $155 million on the northern Mexico refined products supply projects and about $85 million on our Corpus Christi North Beach terminal export project. So once again, our combined 2018, 2019 capital spend will be the same as reported on our third quarter earnings call, resulting in no change to EBITDA or our leverage guidance for 2019.

Regarding our reliability capital spending for 2019, we continue to expect to spend $70 million to $90 million, which includes about $35 million of hurricane repairs that will be paid with insurance proceeds and $11 million to complete work on our Ammonia System replacement project.

Based on these projections, we continue to expect our common unit distribution coverage ratio for 2019 to be in the range of 1.2 to 1.3x. Because we are executing in 2019 on high-return growth projects that Brad mentioned, we expect our debt to EBITDA ratio to be around 4.3x at year-end. However, as those projects are completed and begin generating EBITDA, the bar plan shows steady improvement in our debt metric thereafter.

And with that, I'll turn the call back over to Brad for his closing remarks.

Thanks, Tom. As Tom said, we produced strong results for the fourth quarter and for the full year, meeting or exceeding all of our projections. We also made dramatic strides in 2018. Not only did we reposition the company for long-term success but we delivered significantly higher quarter-over-quarter and year-over-year financial results with higher adjusted net income, EPU and EBITDA, while significantly improving our debt metrics and distribution coverage. We also achieved all the hallmarks of MLP health. We're now at strong coverage, lower leverage, simplified governance and minimal equity and capital needs through 2021. Now 2018 in a rear view mirror, we are focused on executing on high-return growth projects to take advantage of some of the best midstream opportunities the MLP sector has ever seen, while continuing to lower our leverage and maintaining strong coverage ratio. Before I close and turn to Q&A, I want to address the recent expansion of the U.S. sanctions on Venezuela and PDVSA. Since the announcement late on Monday, we've been reviewing those changes. As you recall, last November, we told you we'd entered into a settlement agreement with PDVSA that accomplished 2 key things for NuStar.

First, we reduced PDVSA's footprint at the terminal by about half, allowing us to diversify to a broader customer base. Second, we received a onetime nonrefundable payment for PDVSA's financial obligations to NuStar through the end of August this year. As you heard, Tom mentioned, we're maintaining our guidance for 2019, which means we remain confident in our outlook for strong performance this year. And thanks to the settlement that I mentioned, our exposure to PDVSA has been reduced substantially.

So thank you for listening in today. I'll now open it up for Q&A.

(Operator Instructions) And your first question comes from the line of Theresa Chen with Barclays.

Brad, I want to follow up on your comments about the Venezuelan sanctions. Understand that you reiterated your guidance, but previously, I believe, you had expected a cash payments from the counter party from September through March of 2020. Just looking at 2019, September to December, at this point, should we read the reiteration of guidance such that you don't expect the cash payments anymore but the other pockets of strength in other parts of your business should account for that?

I think it's one way of looking at it. The way we look at it is that what we have in the forecast for the remainder of the year is not substantial. And so whether we get it or not, then it's not enough to move the needle outside of our guidance range.

Understood. And also related to your guidance range, clearly, the trucked volumes to your South Texas system is helping a lot right now. What's your expectation for those volumes moving forward and general expectations of any business that is exposed to the Midland to Gulf Coast's spread just given recent volatility, which, I imagine, would include the crude by-rail movements to same chains as well?

Right. Theresa, this is Danny Oliver. We are continuing to see -- even with those mid-cush diffs coming in, we're continuing to see about 30,000 barrels a day of trucked volumes into our South Texas Crude System. We have not forecasted that out any further than a month or 2 to out, just because it is so volatile. The Permian unit trains that we have in the forecast are committed to. But really, it's a -- it flows between Permian or Western Canadian barrels coming in by unit train. And the arbs from Western Canada are still wide open.

Great. And can you just talk about the financing plans for this year? Given your leverage guidance, it looks like you're going to use your balance sheet again. Are you also reserving the optionality to go for another press or potentially asset sales of other, I guess, discrete noncore assets, maybe Point Tupper, West Coast terminals or the Ammonia System?

Yes, as far as financing plan goes, we don't have any plans to do any more press. We don't have any need to do any common equity in the markets for several years. I think we said that we think we're good likely through 2021, at least that's what our plan is showing today. And so no equity, equity like issuance are planned during that period. In terms of financing plans, the only thing we really have on the table is to refinance the bonds that matured earlier in 2018. We still have that on the table. We need to get that done. The timing on that could be first quarter, it could be a little bit after that. We think our liquidity is fine. We're managing that. And we're going to be opportunistic in terms of timing of when we reissue those bonds and go into the market with those. Asset sales, I mean, we're always -- we're looking at things that we can potentially do there to help the delevering part. I'll tell you nothing is imminent. We're looking at a few things, but nothing really to report now on that.

Got it. And lastly, just given your presence in Corpus and the many projects in competition for a fully loaded [V] solution, do you have an opinion on either which project or what type of project will go forward either onshore or offshore?

I don't think we have real opinion on which one might get done or might not. I think they're all going to be challenged. But I think we think that Corpus Christi port project in Harbour Island seems most likely in our view. But we continue to work with those involved in those projects to have a connection if those projects go through.

And your next question comes from the line of Jeremy Tonet with JPMorgan.

Just wanted to turn to navigator here. And just wondering, if you can let us know, in the quarter, where the volumes came out and what the EBITDA was? And as you look into 1Q '19 so far, do you see these trends kind of continuing? Or are there any impacts from freeze-offs or anything else that you could share with us?

Any impacts from what? What was the last part? I've missed it.

Freeze-offs?

Freeze-offs. What's a freeze-off?

Just cold temperatures adversely...

Yes, yes, yes. Got it. All right. Okay, sorry. Yes, we're in Texas, we don't see the cold like you guys are experiencing, but yes, there has been some impact from cold weather. There were several impacts in the fourth quarter. What I can tell you is we reached -- we had always talked about a goal of 360 on that system. We did hit 360 in December. And then we saw a slight pullback based on weather, based on a gas line being down, weather being both freezing weather and wet weather. And so we ended the year in the mid-360s. We're seeing that continue into January. And so this is same thing we saw last year. It was a little bit below in January on through February and then it began taking off again during the rest of the year. So...

Yes. It added -- in fact that we have seen that. But in terms of volumes, there has been about, like you said, about 360 or so. In terms of EBITDA, fourth quarter EBITDA was about $28 million on the Permian system. So that's where we ended up there. We definitely have talked to producers. We don't see them tapping the brakes in terms of $50 oil or anything like that. They seem to be on spot with their projections and what they expect. If you remember, last year, we went through kind of this same thing weather-related in terms of volumetric with cold weather and all that. But certainly, we think our guidance is intact. We think that the Permian is going to ramp up. The volumes are going to be there. The acreage is dedicated. These guys really aren't tapping their brakes in terms of price of crude oil right now in the mid-50s. So...

Yes. I'll add on to what Tom said. I mean, and I also want to clarify. So I might have just said, somebody here point out to me, I may have misspoken. We did hit 360 in December. But it came off a little bit due to weather. So we're in the mid-300, somewhere between 330 and 350 through December and on in January. But based on everything that we've heard -- and these are -- our forecasts or based on our actual conversations with producers. So we've taken into consideration, the data that you get from Rystad and EIA and other things like that. But when we actually look at what we expect for the year, it's based on actual conversations with producers on the ground. And all of those are unrelentingly positive.

Okay. It seems like maybe a little bit of noise here with the weather. But how did volumes enter the quarter, I guess, in October? What was the average for 4Q? Just trying to get a feel for what that ramp could look like when things are kind of normalized?

It was in the -- I think mid-330s was the average. Tom, do you have...

For the fourth quarter?

Fourth quarter. Yes, mid-330s for the average.

That's helpful. And then just want to touch base on storage as well. I was just wondering overall utilization, how that ended the quarter? Where you see kind of rates shaking out? Just getting a feel for where the storage market is? And how do you see that going over the course of the year? Any updated thoughts on IMO?

Yes. So we're proud of our utilization rates. We're still in the mid-90s in terms of utilization. Some of the setbacks in terms of the EBITDA for 2018 had to do with really a couple of locations. I think we've talked about on these calls before in the Northeast and in St. James, some renewals in early 2018 when the markets were backwardated. And we saw some lower rates. We've got about a year left on most of those contracts. And now we're starting to see some contango creep back into the market. Brad talked about the Bayou Bridge pipeline coming in. Now there's talk about a reversal of cap line. All those things, I think, when we get another bite at the apple, will help us get those rates back up.

That's helpful. And in the DCF rack, I was just hoping you could help me out a bit as far as the add-back. I think there was an add-back of $55 million. And I believe $43 million of that relates to the kind of noncash part of the sale there. But the other $12 million, could you give us some color on what drove that in the add-back?

Yes, absolutely. So as you mentioned, the big portion of that was the U.K. loss on the sale. And that was $43 million. There was about another $7 million that was customer or capital reimbursements. And then there was about another $6 million that was a combination of revenue, timing, adjustments and some other things as well.

Got you. Great. And so just going back to storage real quick here. Is this kind of a good run rate as we start '19? Or are there any other kind of gives and takes we should think about? I think there was -- what there was -- there was still a partial contribution from the European storage assets in the quarter?

Yes, there was. I mean, yes, certainly, there was some that in there, yes. You just want to run the...

Minus the European contribution for part of the quarter, I think, it's probably a pretty good run rate.

Yes.

And our next question comes from the line of Shneur Gershuni with UBS.

I'll try and keep my questions to 3 or 4. But first off, can you talk about the maintenance CapEx run rate? It seemed pretty low in the quarter. Was it a seasonal factor? And how should we think about that on a go-forward basis?

Yes, I mean, also keep in mind that the reliability capital number itself has those hurricane numbers in it. For example, with the fourth quarter, the $77 million of reliability capital that we reported had about $35 million with the hurricane reliability in it as well. So the net of that was probably what about the mid-40s or so. When you take that out -- and looking at 2019, I gave guidance of $70 million to $90 million, I think it was for 2019. And so that again would include about $35 million with the hurricane in it. So the net of that is probably a pretty good run rate going forward.

I think there's also some natural seasonality to reliability spending. We tend to do more work in the summer months than in the winter.

All right. That makes perfect sense. Just looking over the storage and pipeline results, seemed a little bit lower than we would have thought. I was just wondering if you can expand a little bit, specifically on tariffs. Do you expect them to trend lower from here?

No, we don't see any tariffs. We made adjustments in mid-2018 on our South Texas tariffs. But that's not changing going forward. Nothing is changing in the Permian.

But you're not like ramping up something with the lower tariffs and the average blended rate comes down? Or that's completely played out compared to last year?

Yes. No, we're not ramping up something that new to lower rates.

Okay. Just looking at your revolver, you've got quite a bit drawn on it. I believe you answered an earlier question, you're looking to potentially term it out. Given the moves in the high-yield market and given the -- what you're paying on the revolver itself, would it negatively impact your DCF expectations for the year? Or have you already accounted for that?

In our guidance, we have already accounted for refinancing the bonds. So that's already built in. And we have seen rates climb up. There was some volatility in the market in the end of 2018 and moving into the early part of '19. Those markets have been improving. Right now, we -- the indicative pricing guidance that we're getting on a new issue would put us right spot on with what we've budgeted for the year in terms of a rate on those bonds. So I think all of our guidance is already built in. The fact that we're going to -- we want to refinance those bonds and it's indicative of today's rate. So I think we're in good shape there.

Great. And 1 final question. And I think you kind of touched on it before as well too. But a peer of yours is shutting down an ammonia pipeline. Is that an opportunity for you? I'm not sure if there's a major overlap. But at the same time, is it a possibility that you can consider pruning that asset to help pay down leverage as well also?

Yes, we do have some opportunities there with that event. We've been talking to customers. We have similar customers. And we've been talking to them over the last few months about that happening. And I do see that as some potential upside for our ammonia system.

So most likely you're continuing with it rather than looking to prune?

Yes.

Yes. yes. Yes.

We don't have any plans for sale.

No.

Okay. And do you have a regular process, ever since you've gone through the restructuring last year where you evaluate assets on an ongoing basis and looking to prune the bottom 10%, let's say, just sort of high grade your capital assets?

We don't have a hard line like you suggest there like 10%. But yes, we are always looking at our portfolio of assets to see if that makes sense.

And our next question comes from the line of Ryan Levine with Citi.

Can you provide your updated thoughts around the longer-term leverage targets?

Well, as we said, we finished the year at a debt covenant of 4.05x. We projected in 2019 that we'll likely be at 4.2x by the end of 2019. And that's the guidance that we put out there. I'm sorry, 4.3x. And so long-term target, I mean, obviously, we want to be lower than that. We want to be long term. I want to be sub-4x on debt to EBITDA. And we think we can get there. Certainly 2020 is a big year for us given what we are -- expectations in the Permian, increases in EBITDA, a lot of these projects, these very low-multiple projects that we're working on today would indicate a pretty good ramp-up in EBITDA along with any other potential levers that we pull to delever. So we are committed to delevering over the short term, the long term. And we're going to keep looking at that and finding other ways to continue to delever over the next couple of years.

Yes. Also a little bit different way, we kick up a little bit this next year just because we have some great projects that we need to do. So we go up from our 4.05 to around 4.3. But as those projects kick in, it brings us back down into this range or below, which -- it feels pretty good to be around 4.0. And so they are below, which is even better.

Okay. And then in terms of St. Eustatius additional customer conversations or opportunities to expand beyond PDVSA, what are the state of those conversations? Or is there any update that you can provide?

Yes. We have been successful in releasing some of that storage that we got back from PDVSA. As you may recall, we said that we never anticipated filling that all at once. It was going to come in over -- about half of it, maybe about the middle of this year and then the rest in 2020. And we're probably 25% or so of that storage we got back. We have released earlier than midyear. So -- and we're still working opportunities on the rest of it. So we feel pretty good about it, and we're on schedule.

And how did the rates of the new customer contracts compare to legacy rates? And any change in contract portfolio duration or other key terms that would be important to highlight?

Yes. The only thing, I think, would be important to highlight are the rates. And we mentioned this before, they're going to be lower than the PDVSA rates, which is just a different market than when we signed those up. But we're recontracting at the rates that we assumed in our guidance.

That's right. And all of our guidance reflects that recontracting, the lower rates, all of the stuff is filled in.

Does the recent Venezuela news change the cadence for future recontracting or challenge anything in those efforts?

Not yet. No, we haven't seen that changing any of our efforts to recontract what we have.

Okay. And then just to clarify on the trucking volumes in South Texas, I understand the corrected volume estimate that you provided, you're only assuming that out for 1 or 2 quarter -- 1 or 2 months. And you're not assuming that that's going to be in your full '19 guidance?

That's correct.

And our next question comes from the line of Dennis Coleman with Bank of America Merrill Lynch.

Just 1 or 2 for me, please. The Fuels Marketing business had a nice quarter. Anything there you might talk about? Or that -- or we can think about the run rate there?

Yes, the lion share of that improvement was in our butane blending business, which in our Fuels Marketing segment, that is the one piece that really is pretty core to our pipeline business. It supports our central East Pipeline System. And the improvements there on our butane blending business were in direct correlation to the CHS acquisition and some other improvements we've made on that pipeline system.

So is this seasonal there? Some seasonality? Or should we think about that as a good level going forward?

Well, no, the butane business is seasonal. And the fourth quarter is a big period for blending the butane. But that's normal. We normally see that. But I think we're expecting continued strong annual results out of that business.

Okay. And then, I guess, just any update on what your thought is for the Colorado City project status? And when that might be done?

Yes. So that's scheduled to come online May 1. And as you recall, that is backed by firm commitments.

(Operator Instructions) And our next question comes from the line of Michael Blum with Wells Fargo.

My questions are actually addressed.

And we do have a follow-up question from the line of Jeremy Tonet with JPMorgan.

Just had a follow-up as far as navigator, and what was the CapEx for 2019 that you guys were expecting to kind of do what you want to do there?

The CapEx for 2019 or 2018?

For 2019, as you disclosed like kind of how much more capital you're investing in the navigator system?

Yes, it's $185 million for Permian.

Got you. Great. And then just last one, trying to reconcile, I guess, the facilities leverage that you mentioned the 4.2, where the rating agencies would have you guys stacked up? What are some -- where do the agencies have you guys these days? And what are some of the bigger drivers to those adjustments?

Well, I mean, in terms of where there have us, I mean, every rating agency is different -- every rating agency is different on how they treat the prefs and all that. The feedback we've gotten is, I think that we really need to be around 4x, 4, the low 4s for most of the rating agencies. S&P doesn't give us as much credit for the prefs as the other 2 do. So they're probably more around 4x from a debt covenant standpoint.

You there? I think we lost Jeremy. Well, Jeremy, if you're listening, if that didn't answer your question, just give us a call later.

And ladies and gentlemen, this concludes today's Q&A session. I would now like to turn the call back over to Pam Schmidt for any closing remarks.

Thank you, Ashley. We once again like to thank everyone for joining us on the call today. If anyone has additional questions, please feel free to contact NuStar Investor Relations. Thanks again, and have a great day.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude today's program, and you may all disconnect. Everyone, have a wonderful day.