NuStar Energy LP (NS) 2018 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Third Quarter 2018 NuStar Energy L.P. 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, Mr. Chris Russell, Vice President and Treasurer. Sir, you may begin.

Thank you, Shenell. Good morning, everyone, and thanks for joining us on the call today.

Before we get started, I want to take a moment to introduce Pam Schmidt, our new Vice President of Investor Relations. Pam has more than 25 years' experience in key financial positions at NuStar, including leadership positions in risk compliance, accounting and internal audit. So she has a thorough understanding of the company and will be a great fit for running the Investor Relations department going forward. I'll be working with Pam over the coming months to help make the transition a smooth one, so I'll still be talking with some of you during this transition period.

With that, let me turn the call over to Pam.

Thanks, Chris, and good morning, everyone. To kick off the call, Brad Barron, NuStar's President and CEO; and Tom Shoaf, Executive Vice President and CFO, will go through their repair -- prepared remarks. Upon completion of their remarks, Brad, Tom and other members of management in attendance will take your questions.

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 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 investor website on -- of our website at nustarenergy.com.

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

Good morning. Thank you all for joining us. We have a lot of great news to report today. Before I turn it over to Tom to provide you the details on our strong financial results for the third quarter, I'll go over some good news and give you some positive updates on our business.

When we embarked earlier this year on our stepped plan to achieve the characteristics demanded by the changing MLP sector, we did so because we believe that recovery will bring opportunities for strong growth for healthy MLPs with great assets. By executing on our plan to simplify our governance, eliminate the IDRs, strengthen our coverage, minimize our equity capital needs and lower our leverage, NuStar is now solidly positioned to participate in these growth opportunities, while maintaining a healthy financial position in a strong coverage ratio.

And now as 2018 is drawing to a close, we're definitely seeing many more opportunities than the MLP sector's seen in several years. By far, the majority of the current significant opportunities for midstream MLPs are capital projects to solve the logistical dislocations in or emanating from the Permian Basin, and NuStar has assets uniquely situated to benefit from these Permian-driven opportunities. Of course, we expected to grow along with the Permian Basin in our crude gathering system, which is located in the heart of the Midland Basin. But we are now also seeing the positive spillover as far as 300 miles of the Northeast on our crude oil system in Wichita Falls, 500 miles southeast at our state-of-the-art storage and dock facility in Corpus Christi and 800 miles away at our world-class terminal in St. James, Louisiana.

The breadth of the Permian's impact shouldn't be surprising, given that it comprises the lion's share of production growth that has catapulted the U.S. to be the #1 crude producer in the world this year, ahead of both Saudi Arabia and Russia, and the Permian is expected to continue to be the dominant play for the foreseeable future. By 2023, the Permian Basin is expected to constitute over half of our U.S. shale production.

In short, the Permian Basin's production growth has made it the dominant shale play on the planet. Thanks to the quality of our dedicated acreage in the core of the core of the Midland Basin and the top-tier producers and shippers that acreage attracts, we've been benefiting and expect to continue to benefit from that growth.

During the third quarter, our throughputs continued to ramp up, even given the historic rainfalls. And for those of you outside of Texas, historic is no exaggeration. We saw around 20 inches of rain in 60 days. In fact, this September and October were the 2 wettest months in Texas history.

Our November nominations are 355,000 barrels per day, and we continue to expect to exit 2018 between approximately 360,000 to 380,000 barrels per day. That's nearly 2x our 2017 exit rate of 200,000 barrels per day.

The Permian Basin's growth has in fact been so positive in 2018 that it has inspired concerns that production may temporarily outstrip the long-haul takeaway capacity out of the basin.

Worries about impending takeaway constraints of widened differentials incentivize shippers and producers to find ways to get price advantaged WTI Midland barrels to the water before the differential narrows.

I want to say a few things about those concerns. Number way -- number one, by way of reassurance, on our system, we work closely with our producers, and they do not seem to be pumping the brakes. In fact, we're hearing them affirm, or in some cases, even raise their production plans. We have solid shippers with firm commitments for at least 85% of their planned production, and the Midland Basin is advantaged in connectivity and in location.

Number two, we need to keep the constraint origin perspective, as problems go, growing too fast is a pretty good problem to have.

In fact, what's been characterized as a Permian's constraint problem can also create opportunities for midstream MLPs with the right assets and creative solutions. For example, we completed a construction on a 10-bay, 30,000 barrel per day truck-loading rack at a terminal within our Permian Crude System, which is backed by customer commitments. Last week, we loaded an extraordinary 215 trucks in a single day out of that terminal.

To put that in perspective, you assume the track -- the rack is loading 24 hours a day, that's about 9 trucks an hour, which is pretty impressive. While this isn't a high-cost project, it's generating great return and epitomizes just one more positive spillover from Permian growth.

Our South Texas Crude System in Eagle Ford has also benefited in the recent months from WTI volumes arriving by truck. We're seeing about 15,000 barrels a day, over and above our throughput minimums for the system. Also, we mentioned in August that we have restarted our St. James terminal unit train offloading facilities, storage tanks and docks to serve customer commitments for 5 to 10 trains a month. These trains are currently bringing Permian, as well as Western Canadian barrels, but we're also pursuing commitments for Bakken barrels at the terminal.

Based on our conversations with customers and the wide differentials, we could see the number of trains as much as double over the coming months. In addition, we're working to expand our Wichita Falls crude pipeline to accommodate additional barrels from the Sunrise pipeline expansion from Colorado City to Wichita Falls. The Sunrise connection and our related expansion project provides our customers additional access to Permian crude, which we expect to increase our throughput and produce a healthy return for a relatively small capital outlay.

As the Permian Basin's production of light sweet crude exceeds U.S. refiners' demand, those incremental barrels are likely bound for export, which projected to mean that the U.S. will be exporting as much as 5 million barrels a day by 2023, largely from Gulf Coast export facilities, like our world-class terminals in Corpus Christi and St. James, Louisiana.

Back in August, we talked about the preliminary development of projects to connect our South Texas system with long-haul pipeline projects from the Permian to bring barrels to our Corpus Christi North Beach export terminal, both for early service to allow customers to benefit from WTI and Midland discounts in addition of -- in advance of long-haul expansions coming into full service and long-term service for customers capitalizing on growth in U.S. exports. We're very happy to announce that we have since reached agreement with Trafigura for a 4-year commitment to 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 terminal. We will also construct a new 8-mile, 30-inch pipeline from a new connection in Taft, Texas to our Corpus Christi terminal, and we will construct 600,000 barrels of storage at the terminal, bringing our total capacity from 3.3 million to 3.9 million barrels, 1.6 million barrels of which will be dedicated to Trafigura.

We expect to begin providing service of Trafigura on the 16-inch pipeline as soon as next summer, and we're very excited about this mutually beneficial opportunity to benefit from the Permian Basin's growth. We're also exploring additional connections of our existing South Texas system to other large pipeline projects as well as other ways to expand NuStar's role in the projected growth in exports, both in Corpus Christi and in St. James.

Over the past few months, based on the projected significant growth in U.S. exports, there've been upwards of 8 announcements of projects to construct offshore platforms capable of loading VLCCs, the preferred mode of transport for barrels bound for distant destinations like Asia.

While we were skeptical of the liability of several of these projects, we're excited about the Port of Corpus Christi's recent announcement that the port is developing a crude oil export terminal project, which will include VLCC loading capability on Harbour Island. Over the years, we've had the opportunity to work closely with the port on many occasions and appreciate their practical approach to finding commercial solutions. Because of our long-standing relationship, we've initiated discussions with the port -- or port representatives to connect our facilities with this terminal to provide additional flexibility for our customers.

While we see incremental Permian barrels as largely bound to the Texas Coast, and Corpus Christi in particular, we also expect our St. James facility to benefit from the ripple effect of the Permian's growth. As Permian barrels continue to find their way to water in major refining complexes, we are working to make sure we participate in that opportunity at St. James as well.

Also, I want to update you on several projects beyond the extended reach of the Permian. Earlier this year, we announced project to facilitate the export of refined products in Northern Mexico, backed by several long-term T&D contracts with strong creditworthy customers, including Bolero. These projects are progressing on schedule, and we are forecasting incremental EBITDA from some of these projects as soon as next month.

Over the past year or so, we've also been investing in our West Coast assets through a number of low-cost, high-return biofuel projects to meet emerging demand in the region for biofuel storage, which commands a premium over other storage rates. While the total investment is only approximately $70 million, we expect these projects to deliver EBITDA multiple of around 6x. As you can see, we have a lot of good projects in progress. In fact, we're excited about the fact that NuStar now has a deeper backlog of high-return capital projects to choose from than we've ever had in our history. Having too many low multiple projects with high returns, much like the Permian's production growth, is another good problem to have. At the same time, we're committed to maintaining our strong fundamentals and living within our means, so we can continue to lower our leverage and ensure a strong coverage. In order to make sure we balance these competing needs properly, Tom and his team are high grading and scrubbing every project to ensure we are efficient, strategic and judicious with every dollar.

We've also been working on identifying and divesting a package of noncore assets to improve our debt metrics. And last week, we announced we signed an agreement to sell our U.K. and European assets for $270 million, which is a multiple that well exceeds our 10x multiple target. It is important to note that while the sale of these assets will significantly reduce our debt-to-EBITDA ratio, it will have almost no impact on our DCF coverage. We expect to close on that sale this quarter. Using these sales proceeds to pay down debt will improve our projected year-end 2018 leverage metric from the 4.7x we projected to around 4.2x. It will also allow us to utilize the proceeds from the sale of a 10-plus -- 10x-plus asset to invest in high-return projects in many cases at less than a 5x multiple.

Before I turn it over to Tom, let me say that I'm very pleased that the steps we have taken have positioned us to participate in exciting opportunities, reemerging in midstream logistics, and we're truly excited about our 2018, 2019 capital projects and the growth we anticipate those will generate in 2019 and beyond.

With that, I'll turn the call over to Tom.

Thanks, Brad, and good morning, everyone. Starting with our third quarter 2018 results, we generated net income of $48 million, up $10 million or 25% from the third quarter of 2017 and $172 million of EBITDA, up $16 million or 10% from the third quarter of 2017.

EPU for the third quarter came in at a negative $3.49 per unit due to a onetime noncash charge of $377 million related to our simplification transaction, which merged NuStar GP Holdings, LLC and NuStar Energy. This noncash charge only hit EPU and did not impact our net income or EBITDA or DCF. If we exclude this charge from the calculation of EPU, our third quarter adjusted EPU was $0.13.

Third quarter 2018 DCF available to common limited partners was $88 million, up $22 million or 32% from the third quarter of 2017, and our distribution coverage ratio to our common limited partners was 1.38x for the third quarter and 1.42x for the 9 months ended September 30, 2018.

Third quarter 2018 EBITDA in our pipeline segment was $116 million, up $20 million or 21% from the third quarter of 2017, largely due to continued throughput volume ramp on our Permian Crude System, as well as increased throughput volumes on our East Pipeline System associated with our CHS Council Bluffs, Iowa acquisition earlier this year.

Third quarter 2018 EBITDA in our storage segment was $81 million, down $10 million from the third quarter of 2017, due to a combination of factors, including the impact of decreased storage rates in certain locations due to contract renewals in a backwardated market, which was offset in part by increased revenues from our West Coast region.

Our September 30 debt balance was $3.4 billion, while our debt-to-EBITDA ratio was 4.5x, down from 4.7x at the end of the second quarter and below our credit agreement covenant threshold of 5.25x.

Now let me spend a few minutes talking about our projections for the remainder of 2018 as well as 2019 and 2020. During the second quarter, it was widely reported that ConocoPhillips served our St. Eustatius terminal with an order purporting to attach the oil owned by PDVSA that was stored there. During the third quarter, we entered into a settlement agreement with PDVSA and ConocoPhillips regarding oil stored at the terminal in which the parties agreed PDVSA would transfer ownership of 600,000 barrels of crude oil to us. We would then sell the oil and apply the proceeds as a nonrefundable onetime payment of fee. PDVSA has also reduced its storage position at the facility by about half, opening that storage capacity for lease to third parties. In October, we completed the sale received proceeds, which will cover PDVSA's storage fees through August 2019.

We now expect NuStar's 2018 EBITDA to be in the range of $670 million to $720 million, which includes the first quarter's gain associated with cash receipts of hurricane-related insurance proceeds discussed on last quarter's call, offset by a noncash charge of approximately $45 million related to the upcoming sale of our European assets. If you exclude these items, we expect our 2018 adjusted EBITDA to be in the range of $635 million to $685 million. This range is higher than our previously -- previous guidance, primarily due to the settlement we reached with PDVSA.

With regard to capital spending, we now plan to spend $400 million to $430 million on strategic capital in 2018, the majority of which relates to the Permian Crude System in the Northern Mexico projects. Our revised 2018 spending represents a $40 million increase, primarily for the Corpus Christi North Beach export project and our Sunrise pipeline connection.

Regarding our reliability capital spending for 2018, we plan to spend $80 million to $90 million, including approximately $36 million for hurricane repairs at St. Eustatius paid for with insurance proceeds.

Based on these projections, we now expect our common unit distribution coverage ratio for 2018 to be in the range of 1.3 to 1.4x, an improvement over our projections earlier this year. And given the effect of the divestiture of our European assets, we expect our debt-to-EBITDA ratio to be around 4.2x by the end of 2018, also better than what we projected earlier in this year.

Looking further out to 2019 full year guidance, we expect NuStar's 2019 total EBITDA to be $665 million to $715 million, which takes into account the European sale. This estimate assumes approximately $105 million to $115 million of general and administrative expenses in 2019 that are not allocated to our segments EBITDA results.

With regard to 2019 capital spending estimates, we plan to spend $450 million to $500 million on strategic and other capital, of which approximately $180 million relates to the Permian Crude System, $135 million is for the Northern Mexico refined products supply projects and about $75 million will be spent for our Corpus Christi North Beach terminal export project.

In 2019, we plan to spend $70 million to $90 million, that's $70 million to $90 million, on reliability capital, including $30 million of hurricane repairs that will be paid with insurance proceeds.

Net of the insurance -- I'm sorry, net of the hurricane proceeds, reliability spending is slightly higher than our historically reliability capital run rate due to our Ammonia System replacement project that we began work on this year. Based on these projections, we expect our common unit distribution coverage ratio for 2019 to be in a range of 1.2 to 1.3x, and our debt-to-EBITDA ratio to be around 4.3x by the end of 2019.

In 2020, we expect our -- to see our benefits from incremental EBITDA from our 2018 and 2019 capital projects spending, as well as the continued ramp in our Permian Crude System volumes. And as a result, NuStar's 2020 total distribution and debt coverage metrics should improve compared to 2019 and be consistent with the guidance we've provided back in February, when we laid out our step plan to reposition NuStar.

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

Thanks, Tom. You've heard this morning, it's a good time for NuStar. We've executed on our plan for 2018, and we are repositioned for strength. We've achieved strong third quarter results, and we expect to meet or exceed our projections for the full year. We have great assets in the right places to take full advantage of some of the most significant midstream opportunities the sector has ever seen, and we're executing on growth projects to do just that. And of course, all this means that we expect to maintain a strong coverage ratio going forward. I speak for myself, my whole management team and all of our employees when I say that NuStar's future looks bright and the best is yet to come.

With that, we'll open up the call for the Q&A.

(Operator Instructions) Our first question comes from the line of Jeremy Tonet of JPMorgan.

Just want to start off with the 2018 guidance. I was hoping you could help me understand that a little bit better versus what was provided in September 20. It seems like the -- some of the reconciliation items are a little bit different. The other income, kind of, came down a bunch there. And Tom, I think you touched on a few of the pieces, but I was just hoping that you might be able to reconcile that a little bit more the $635 million to $695 million before versus the $635 million to $685 million now?

Yes, as I said, our guidance, when you look at that $635 million to $685 million, I mean, that actually came up about $15 million, and that's primarily due to the impact of the PDVSA settlement that I talked about earlier. And I mean, as far as that goes, that's kind of what we did. I think we had a little bit different results on PDVSA than we had anticipated, but that's the main driver for that increase.

Okay, great. And then with PDVSA, how much did they add to this quarter? I guess, in -- the way you -- we should think about this kind of a 1-year contract August-to-August and that's kind of how we should be thinking about that?

For the quarter, I'm not sure -- I don't know how much they added to the quarter, but I don't know that we're going to disclose that, but it definitely was a big benefit compared to the guidance we had out there before. And it's not a 1-year contract. The contract actually runs through March 1, 2020. Just so happened that, that cargo we sold just covered us for the next -- covered us through August of 2019. We still have another, what is that, 6 months after that. We expect 6 more months for the revenue from PDVSA after that August 2019 time frame.

Okay. And last one, with Sunrise, the opportunities it presents to you there, how much you currently pulling of the line at Wichita Falls and how big could that be? How -- and we're trying to frame the opportunity set for you guys here.

Yes, so we're currently -- we'll be taking in November and December about 150,000, 160,000 barrels a day off of that line into our Wichita Falls system. It's important to note not -- that's not going to be significant incremental barrels, but it will be incremental tariff because it's on a longer-haul tariff. But there's a second part of this, which we're working on an expansion, which would bring an incremental 50,000 to 60,000 barrels a day into the system, but that won't be ready until about April or so of next year.

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

I guess -- sorry to go back to this guidance thing again. Tom, maybe you can walk us through what you're comparing your guidance to. Because when I look at the guidance table that was put out in September, this looks like a $5 million reduction because it looks like you took down the top end by $10 million. So which one are we comparing it to? And is it the one at the beginning of the year where there was supposed to be no PDVSA in it whatsoever?

Well, yes. I mean, I think, like we said, we've increased the guidance by about $15 million for 2018. So that's over what we had out there previously that we reiterated on the last call.

On the last call, yes. I think, we're comparing that to the guidance we gave on our last call, Shneur, which was $620 million to $670 million.

Kind of comparing midpoint to midpoint. That's what you get.

Okay, that makes sense. Next, you'd made a comment about the sale of the European business that it would be DCF neutral, I guess, is the term you said. You put out in your press release greater than 10x, and I think that was in your prepared remarks as well. The company you sold it to, said it was 8.9x. I gather that part of it is looking forward versus trailing. Can you give us what the trailing 4 quarter number was for that segment? Or should we think of it as the DCF given up is equal to the interest savings benefit? I'm trying to understand how we end up being neutral.

Yes.

Yes, Shneur, this is Chris Russell. How we get to be neutral, it's EBITDA. We do have some taxes we pay over there, we're saving those, and we have quite a better liability capital, we're saving as well. So it's not DCF accretive, but it's diluted to a very, very, very immaterial amount.

Got it, okay. That makes sense. And then finally, just this project with Trafigura. You -- when I think about everybody keeps talking about bringing barrels to Corpus and so forth. Are you guys effectively in the leadership position because of the positions that you have there? I mean, there was a conference call on Friday, where somebody basically, basically said the exact same thing. Are you going to be able to do more projects like this or take more barrels and so forth? I was just wondering if you can sort of talk about the color around the whole idea of bringing barrels to Corpus and on to Cactus so forth.

Yes, Shneur, this is Danny Oliver. I do think we're in an advantaged position because our facility exists. I know there's some talk of building some new facilities in the Corpus area, but ours is available for use now. So we are pursuing other connections to the other pipelines above and beyond this Trafigura commitment. And I think I've said before, I think we'll certainly end up with our fair share of those barrels that are coming to Corpus.

Our next question comes from the line of Theresa Chen of Barclays.

First, related to the new Trafi projects announced. I understand that you are expecting to spend about $70 million next year and $40 million in conjunction with some other projects of -- on Sunrise this year, can you talk about what's your total CapEx estimate for bringing these new additions online and what time frame? And also, what, kind of, EBITDA uplift you're looking from these projects?

Yes. I mean, so if you're looking at the -- so I think we reiterated some of that stuff when we had our remarks. But we've got the Permian where I think we expect to spend about $190 million this year. I think we said $180 million...

Sorry, I'm asking specifically about the Trafi-related projects.

Okay. The Trafi-related projects, I think we expect to spend about $15 million in 2018. And in 2019, we expect to spend about $75 million in 2019 on that.

And nothing beyond 2019?

It's entire -- no, because the entire project is just shy of about $100 million.

Got it. And what kind of EBITDA return do you look for that?

It's all of 5 multiple or better. It's Sunrise and Trafi.

Okay, great. So on the storage front, given that PDVSA has reduced its exposure by half, can you talk about the current environment for recontracting that other half that they've left empty and what you're seeing in raising utilization in near term?

We've got a specific customer we're working with on coming in for the crude oil storage, someone who's active in that region now. We don't have them coming in until about midyear, I think, next year, but we're making headway.

Okay. And can you just clarify that $15 million earlier in the comments about PDVSA's impact? Was that for the quarter? Or how should we think about that?

That's full year.

Got it. And lastly, could you just remind us how the insurance proceeds and reliability CapEx related to the hurricane repairs for St. Eustatius are accounted for in EBITDA in DCF?

Well, we recognized the insurance proceeds. We -- well we received the insurance proceeds earlier this year, I think it was in the first quarter. And what we do is, we don't recognize those in DCF, we do it as we spend the money. And that spend -- there was some spend this year, there's going to be some next year. In fact, there'll probably be some for the next couple of years on that. And so we're recognizing those proceeds as we go forward. So that which you end up seeing is no impact to DCF related to hurricane repairs.

Our next question comes from the line of Ryan Levine of Citi.

Would you be able to clarify in terms of the Sunrise projects, are they all included in your revised guidance? Or is that to be sanctioned so they are further executed?

Yes, these projects are in our guidance that we just provided.

Okay. And then secondly, what's the status of discussions around reengaging customer conversations for the historically disputed Oxy pipeline?

We have several conversations going on regarding that pipeline and nothing is firm yet to bring out, but we've got multiple conversations going on, on that line.

Okay. And then lastly, what's the current status of the Valley Pipeline open season?

The Valley Pipeline open season...

Yes, we're not in an open season yet. We may go into an open season, we may not.

What is the -- I mean, will you be able to provide some color as to the dynamics associated with that project?

Well, we've got commitments that cover that project. We just don't know if we really need to go out for an open season.

Our next question comes from the line of Sunil Sibal of Seaport Global Securities.

A couple of questions for me. I think you'd talked about opening the rail facility at St. James for unloading crude. Could you talk about what are the, kind of, contract terms, if you have any for that facility?

In St. James?

Yes.

Well, we have a lot of storage contracts. There, obviously, everything is other -- under contract. We've renewed a couple of contracts there recently in a backwardated market. We've tried to keep those pretty short in term, so another bite of the apple in a better market and most of those have been done at 2 years. But I think what Brad mentioned is some of the new contracts we've added recently are commitments to bring unit trains to the facility. We've got about half a dozen trains a month contracted to take-or-pay now, and we see that, that number of trains probably doubling, maybe even more than that, as we get more interest out of Western Canada.

Okay, got it. And then these contracts which you've signed so far how far they run out?

The unit trains are mostly -- they're pretty short term, about a year, 9 months to a year. Certainly in the Permian, I think that's about the extent of term that you'll see people interested in. But we're hearing some interest on the Western Canadian side that may go out 2 or 3 years.

Okay, got it. And then I think on the volumes you're taking of Sunrise at Wichita Falls. You said incremental volumes that you're pulling out currently, could you talk about how much is that?

Yes. Currently, the volumes that we're shipping are not really incremental volumes. We're already shipping those barrels on our system but from different pipelines. But there will be incremental tariff. So to think of it now we're bringing barrels in on Sunrise and they're moving on the longer-haul segments of that line, so we get incremental tariff.

Okay, got it. And then this one last one for me. Seems like next year you will have a fair bit of outspend. Is that -- could you talk a little bit about the funding plans? Seems like you will rely on the debt market, any preference between the normal debt or the pref?

Yes. I mean, the plan that we outlined, we've taken care of most of our refinancing needs going forward. We did the pref, we did the series D. We don't think we need to do anymore prefs. We don't need any equity to fund our growth for the next couple of years. So really the only thing of any significance we have out there is just that we still need to refinance our bonds that matured back in April of 20 -- of this year. So we plan to do that and that's really about it as far as what we need to do.

(Operator Instructions) Our next question comes from the -- follow-up from the line of Jeremy Tonet of JPMorgan.

Just want to go over to Navigator. And sorry if I missed it, but what was the contribution during the quarter? How is EBITDA per barrel trending in -- during the quarter and where do you see that going?

EBITDA for the quarter -- third quarter was about $27 million for the Permian. Danny, you want to talk about...

It was on an average of about 314,000 barrels a day. I think, it's pretty consistent with the volumes and related EBITDA we've reported in the past.

Our next session comes from the line of [Spencer Brennan] of HSBC.

I'm just curious after the European asset sales and applying those to delevering, are you still thinking you're going to come with senior unsecured bonds this year? Or is that something you're going to wait to do until you are further along next year?

Yes. The sale of the European assets does a whole lot to delever us. It brings our leverage down, like I said. We think we can exit this year at about 4.2x debt to EBITDA and that was the main focus on why we wanted to do the sale of the European assets. As far as the bonds go, the refinancing of the bonds, as I said earlier, we still plan on refinancing those bonds in terming up -- terming out some of our revolver debt. After we refinance the bonds and if you take into account the European sale, that will give us around $1 billion of liquidity available on our revolver at year-end. So all of that kind of works towards freeing up liquidity and getting our debt-to-EBITDA metric down.

And I'm showing no further questions at this time. I would now like to turn the call over to Pam Schmidt, Vice President of Investor Relations, for closing remarks.

Thank you, Shenell. We would, once again, like to thank everyone for joining us on the call today. If anyone has any 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 on today's conference. This concludes today's program. You may all disconnect. Everyone, have a great day.