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Greetings, ladies and gentlemen, and welcome to Energy Transfer First Quarter 2019 Earnings Conference Call. [Operator Instructions].
It is now my pleasure to turn it over to your host, Mr. Tom Long. Thank you, sir, you may begin.
Thank you, operator, and good morning, everyone. And welcome to the Energy Transfer First Quarter 2019 Earnings Call, and thank you for joining us today. I'm also joined today by Kelcy Warren, Mackie McCrea and other members of the senior management team who are here to help answer your questions after our prepared remarks.
As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These are based on our beliefs as well as certain assumptions and information currently available to us. I will also refer to adjusted EBITDA, distributable cash flow, or DCF, and distribution coverage ratio, all of which are non-GAAP financial measures. You will find a reconciliation of our non-GAAP measures on our website.
Let's start with a brief summary of the quarter. In addition to delivering another strong quarter with record adjusted EBITDA of $2.8 billion for the first quarter, we successfully executed on several key initiatives, including the startup of the second phase of Bayou Bridge, the opening of our first office in China and we are benefiting from the completion of multiple major growth projects.
As for our first quarter performance, consolidated adjusted EBITDA was up 40% over the first quarter of last year and pro forma for the merger of ETE and ETP, DCF attributable to the partners of ET as adjusted, also increased almost 40%.
We continue to see strong performance in all of our major businesses and reported record operating results in the NGL and refined products and crude oil segments. Distribution coverage for the quarter was 2.07x which resulted in excess cash flow after distributions of more than $850 million for the quarter. For 2019, we continue to expect to generate between $10.6 billion and $10.8 billion in adjusted EBITDA and we also still expect to spend approximately $5 billion of organic growth projects.
We have been conservative in our assumptions for commodity prices and spreads in our 2019 forecast. If spreads and pricing stay at current levels for the balance of the year, and our growth projects ramp up as budgeted, we expect adjusted EBITDA to trend towards the higher end of our guidance range.
Before going into a more detailed discussion around first quarter earnings, growth CapEx, guidance and liquidity update, I'll start with the latest developments on our growth projects. In March, we announced that we had signed a project framework agreement with Shell that provides the foundation to further develop the Lake Charles LNG export facility toward a potential Final Investment Decision, or FID.
In addition, the parties have been actively engaged with LNG engineering procurement and contracting or EPC companies, over the last several months. [End of] [ph] last week, Lake Charles issued an invitation to tender to U.S. and international consortia to bid for the EPC contract. The project, if sanctioned through an affirmative FID, would convert Energy Transfer's existing Lake Charles LNG import and regasification terminal to an LNG export facility with a liquefaction capacity of 16.45 million tons per annum.
The project is fully permitted, uses existing infrastructure and benefits from the abundant natural gas supply and proximity to major pipeline infrastructure, including Energy Transfer's vast pipeline network.
On Orbit, which is our joint venture with Satellite Petrochemical U.S.A. Corp. for which we are constructing a new ethane export terminal on the U.S. Gulf Coast to provide ethane to satellite. We continue to make progress on the construction of the project in both the U.S. and China and we continue to expect the export terminal to be ready for commercial service in the fourth quarter of 2020.
And last month, we were excited to open a new office in Beijing to continue to expand into new markets and add to our export capabilities to Asia. This strategic move allows us to better leverage the increasing business opportunities in the export of much needed energy products to China and other Asian markets and to facilitate growth projects across our diverse platform of assets, like the Lake Charles LNG export facility, the Orbit ethane export facility and the Nederland and Marcus Hook terminals.
Next on Bayou Bridge, the 24-inch segment from Lake Charles to St. James began commercial operations at the end of March. And in April, we announced a nonbinding open season to solicit shipper interest for expanded joint tariff transportation service received from certain connecting carriers on to Bayou Bridge pipeline system. This would provide shippers with a cost effective alternative to access the St. James market from multiple basins.
Now looking at Mariner East System. On April 23, we resumed operations on ME1. As a reminder, we placed the initial capacity of ME2 into service on December 29 of 2018, and volumes have continued to ramp up. With ME1 back online, the combined Mariner East System is expected to move approximately 230,000 barrels per day of NGLs through Marcus Hook, with additional inbound transportation modes, including trucking and rail.
Total NGL volumes moved through Marcus Hook is expected to be approximately 300,000 barrels per day for June. This demonstrates the strength of the facility in efficiently reaching the best local and regional markets for our customers. All modes of inbound transportation are essentially at capacity which explains why we are expanding further. We continue to make progress on additional local area connections for ethane, propane and butane distribution.
We will be connected to a new power plant in Cambria County for ethane feed for Mariner East as well as 2 local area propane, butane distribution terminals along the system. Some of the truck volumes are from areas not directly connected to the Mariner East pipeline, thus further demonstrating the strength of the netbacks through Marcus Hook.
As to ME2X, 99% of the mainland construction is complete and at this time we continue to target having the pipeline in-service by late 2019. Looking at our Lone Star assets, the 150,000-barrel per day Frac VI went into service in mid-February and has been full since March. On Frac VII, we continue to expect it to be in-service in the first quarter of 2020 and we expect it to ramp up very quickly.
And on our 24-inch 352-mile Lone Star Express expansion, we will add over 400,000 barrels per day of NGL pipeline capacity from the Permian basin to the Lone Star Express 30-inch pipeline south of Fort Worth, Texas. It is still expected to be in-service in the fourth quarter of 2020. On the Bakken pipeline, in January 2019, we completed a successful open season to bring the current system capacity to 570,000 barrels per day. The new shipper commitments from the recent open season became effective on or before March 1. In addition, Bakken pipeline receives sufficient market interest during the open season such that the partners are also progressing with plans to further increase the system capacity by late 2020 in order to meet growing demands for additional takeaway out of the basin.
Looking at the crude projects in the Permian, we are no longer pursuing the Permian Gulf Coast pipeline as it was initially announced. However, we will continue to evaluate participation in other projects and we continue to do everything we can to maximize the capacity on all of our Permian crude pipelines as demand remains very strong. On PE1, 2 and 3 pipelines, which are part of our Permian Express joint venture with ExxonMobil, all continue to operate at full capacity. And we are almost complete with an expansion of our Permian Express System. The PE4 expansion will add an additional 120,000 barrels per day of capacity to our Permian Express Pipeline system from Colorado City to Nederland, Texas. And the full capacity of the project is expected to be in-service by the end of third quarter of this year. We have already secured sufficient commitments to make this project accretive.
Now turning to our processing plants in West Texas. The 200 million cubic foot per day Arrowhead II cryogenic processing facility went into service at the end of October and is running full today. During the fourth quarter, we approved Arrowhead III, another 200 million cubic foot per day processing plant, in the Delaware Basin. Arrowhead III is expected to be in-service in the third quarter of 2019 and is projected to be full by year-end, bringing our total processing capacity in the Permian basin to approximately 2.5 Bcf per day.
To meet growing producer demand, we continue to expect to announce another processing plant in the Permian basin shortly. We anticipate this plant being in-service in 2020 and is already fully subscribed. As we grow our gathering and processing assets in the Permian, we are also adding new takeaway capacity. The Red Bluff Express pipeline went into service in May 2018 and the second phase of the pipe is expected to be online in the second half of the year.
Volumes during the first quarter averaged approximately 350,000 MMBtus per day and we expect those volumes to increase significantly by the end of the year. The majority of these volumes are also flowing through our Waha Oasis Header, thereby generating additional revenues downstream.
As we have previously mentioned, our anchor shipper is Anadarko and their affiliate Western Gas exercised their option to buy a 30% interest in Red Bluff Express pipeline effective January 2019. From the products side, we previously announced the J.C. Nolan Diesel Pipeline, which will have an initial capacity of 30,000 barrels per day and will transport diesel fuel from Texas to a newly constructed terminal in the Midland Texas area.
We are in the process of completing a joint venture agreement with Sunoco LP, or SUN, for this project to be a 50-50 joint venture with SUN. The pipeline will utilize existing ET pipes, which it will contribute to the joint venture. Construction is progressing well and we expect the project to be in-service before the end of this year.
Now let's look at the first quarter results in more detail. Today, I will discuss ET's results pro forma for the merger. Then I will also walk you through ETO's segment results for the quarter. As a reminder, due to the merger of ETE and ETP last October, we have reevaluated our segment reporting and now report our investments in SUN and USAC as their own respective segments. In addition, Lake Charles is now reported in the Interstate segment. Additional disclosure regarding quarterly results can be found in the ET press release issued yesterday or in the ETE or ETO 10-Qs, which are expected to be filed later today.
ET's consolidated adjusted EBITDA was up 40% to $2.8 billion compared to $2 billion for the first quarter 2018. This growth is due to increase in all of our core operating segments with record operating performances in the NGL and refined products and crude oil businesses.
On a pro forma basis for the merger, ET's DCF attributable to the partners as adjusted was $1.66 billion for the first quarter, up approximately $460 million or nearly 40% compared to the same period last year, primarily due to the increase in adjusted EBITDA. The pro forma for the merger, coverage for the first quarter was 2.07x. In April, Energy Transfer announced a distribution of $0.0305 per common unit for the first quarter or $1.22 per common unit annualized basis. This distribution is flat compared to the fourth quarter of 2018 and will be paid on May 20 to unitholders of record as of the close of business on May 7.
Turning to our results by segment and starting with the NGL refined product segment. Adjusted EBITDA increased to $612 million compared to $451 million for the same period last year. The increase was due to record transport in frac volumes as well as increased refined products terminal volumes, which was partially offset by a $19 million impact from ME1 system downtime. NGL transportation volumes on our wholly owned and joint venture pipelines were 1.2 million barrels per day compared to 936,000 barrels per day for the same period last year.
The increase was mainly due to higher volumes on our pipelines out of the Permian Basin and North Texas regions as well as increased volumes on our Northeast asset due to the startup of the ME2 pipeline in the fourth quarter of 2018. First quarter average daily fractionated volumes increased to 678,000 barrels per day compared to 472,000 barrels per day last year, primarily due to the commissioning of our fifth and sixth fractionators in Mont Belvieu, which came online in July 2018 and February 2019, respectively. As to our crude oil segment, adjusted EBITDA increased $806 million compared to $464 million for the same period last year. The increase between the first quarter of 2018 and the first quarter of 2019 were primarily due to increased throughput in the Permian on existing pipelines, growth on our Bakken pipeline as well as an increase of $124 million in margin, excluding unrealized gains and losses from the crude oil acquisition and marketing business due to improved basis differentials between the Permian and Bakken producing regions.
Crude transportation volumes increased to a record 4.5 million barrels per day compared to approximately 3.8 million barrels per day for the same period last year, primarily due to an increase in barrels through our existing Texas pipelines and volume growth in the Bakken. During the first quarter, volumes on our Bakken pipeline averaged approximately 540,000 barrels per day and demand for space on both our Bakken pipeline and Permian Express pipes remains strong.
For midstream, adjusted EBITDA was $382 million compared to $377 million for the first quarter of 2018, primarily due to the higher throughput volumes, partially offset by lower NGL and gas prices, which negatively impacted results by $45 million. Gathered gas volumes were 12.7 million MMBtus per day compared to 11.3 million MMBtus per day for the same period last year. This increase was primarily due to higher volumes in the Permian, growth on the Ohio River System in the Northeast as well as growth in the North Texas region.
In our interstate segment, adjusted EBITDA was $456 million compared to $366 million for the first quarter of 2018. This increase was primarily due to additional EBITDA from the commissioning of Rover and capacity sold at higher rates on Transwestern, Panhandle and Trunkline.
Interstate transportation volumes were 11.5 million MMBtus per day compared to 8.2 million MMBtus per day for the same period last year. Due to an increase of 1.6 million MMBtus per day from the Rover pipeline as well as increases on Tiger due to production growth in the Haynesville Shale, higher utilization on Panhandle and Trunkline and an increase on Transwestern as a result of favorable market opportunities in the West.
In our intrastate segment, adjusted EBITDA increased to $252 million compared to $192 million in the first quarter of last year. This was primarily due to a $29 million increase from commercial optimization activities as a result of wider basis differentials from West Texas to the Houston Ship Channel. An increase of $13 million in transportation fees, primarily due to the Red Bluff Express coming online as well as the acquisition of the remaining interest in the RIGS pipeline in April of 2018.
Our reported intrastate transportation volumes increased primarily due to the Red Bluff Express coming online, increased utilization of our Texas pipelines as well as RIGS now being treated as consolidated subsidiary.
Moving on to Sunoco and U.S.A. compression, which are now both reported as their own segments. For investment in SUN, adjusted EBITDA was $153 million compared to $109 million a year ago, primarily due to decreased operating expenses from SUN's conversion of 207 retail sites in West Texas to commission agent sites in April 2018 as well as increased fuel volumes. And for investment in U.S.A. compression, we had a very strong quarter. Adjusted EBITDA was $101 million, driven by a positive market environment as a result of continued strong domestic natural gas production and the resulting midstream infrastructure investment.
Now moving onto a CapEx update. For 3 months ended March 31, 2019, Energy Transfer spent approximately $650 million in organic growth projects, primarily in the NGL and refined products and midstream segment, excluding SUN and USAC CapEx. And for the full year 2019, we still expect to spend approximately $5 billion on organic growth projects, primarily in the NGL and refined product segments.
Looking briefly at our liquidity position. As of March 31, 2019, total liquidity under our revolving credit facilities was approximately $4.15 billion and our leverage ratio was 3.82x per the credit facility. In March, ETE and ETO, our primary operating entity, completed an exchange offer whereby $4.21 billion of senior notes were issued in exchange for approximately 97% of ET's outstanding senior notes.
And in April 2019, we opportunistically issued $32 million of 7.6% Series E preferred units for gross proceeds of $800 million and used the net proceeds to repay amounts outstanding under our revolving credit facility and for general partnership purposes. As a reminder, these securities received 50% equity credit from all 3 rating agencies and represent an additional step in our plan to decrease our leverage ratio to 4x to 4.5x.
Before opening the call up to your questions, I just want to say that -- how pleased we are to have reported another record quarter. This demonstrates our ability to consistently generate fee-based earnings as well as a significant amount of excess cash flow, which you can fund our excellent backlog of growth projects in a credit friendly and accretive manner and allow us to further organically strengthen our balance sheet. We have built this business to benefit from our diverse asset footprint and predominantly fee-based cash flows, which are enhanced by strategic expansion projects. We continue to see growth from fee-based projects like our recent Bakken expansion, Permian Express 3 and 4, Frac VI, ME2, Bayou Bridge, Red Bluff Express and others.
Our strong outlook for the year is primarily driven by our core businesses. We have leading footprints across the midstream value chain in nearly all the major producing basins in the U.S., and we continue to find a significant number of accretive growth capital opportunities. We will continue to exercise discipline when it comes to evaluating new projects, and we remain very focused on safety and project execution.
Operator, please open the line up for questions.
[Operator Instructions]. Our first question comes from the line of Christine Cho with Barclays.
If we could start with the crude segment. It was a pretty sizable increase on a quarter-over-quarter basis even though spreads were lower and I don’t think any incremental capacity was added. I think there were also some inventory adjustments last quarter that reversed this quarter. Was most of that in NGL or was there some in crude? And I'm just trying to get a sense of what drove the higher numbers on a sequential basis. And how should we also think about like your hedging strategy that your marketing subsidiary might put on for your asset?
Christine, this is Mackie. On our crude segment, of course, we continue to load up our capacity, fill up our pipes, but we have created additional capacity. We did a deal with Plains. We are now able to fully utilize our Mariner I capacity out the Wichita Falls area. So there are other areas where we have added capacity. And I think you mentioned the spreads weren't wide. They were really wide and they were one of the widest quarters since the last couple of quarters, including the first quarter. As far as inventory, Tom do you want to address that?
Yes, I'll take that. Christine, you're right. As you recall in the fourth quarter, we had a negative inventory adjustment and remember that inventory was probably about 9 million barrels and it's operating inventory. I need to make sure I clarify that. And so you saw about $150 million negative in the fourth quarter. We did recapture about $98 million of that in the first quarter of 2019, but also recall in the first quarter of 2018 we had about $64 million-or-so of positive on that piece of it. So you can see kind of the movement from that standpoint. But yes, we did recapture a little bit of the fourth quarter negative.
And Christine, I'll add one point too. We also brought on and fully loaded PE3, which we didn't have in the first quarter of '18 and that was fully loaded and moving in the first quarter of '19.
Okay. And just to clarify the 9 million barrels of operating inventory that you just referred to. That was all in the crude, there was nothing in NGLs for that?
That is correct. That is correct.
Okay. Great. And then if I can just move on to the DAPL, the Bakkan optimization that you guys are talking about. Is -- I'm assuming this is going to include ETCOP too, but -- as well as DAPL, but is it -- should we think that any optimization is just going to be pumping or is there potential for looping here? And can you remind us if there are any regulatory approvals you need for increasing capacity?
Christine, this is Mackie again. After our open season went so incredibly well, the market demand, as everybody knows how the Bakken's growing on a daily basis, we are excited that we are really the only pipeline that can really offer multiple markets and some of the better markets on the Gulf Coast. So we certainly are diligently moving forward. We're going through a process of both local, state and regulatory to check all those boxes. We hope in the next several months to move forward on open season and we do believe that we can materially increase the capacity without any major modifications without any line looping, just adding horsepower on existing capacity. Keep in mind, we are not adding pipes on an expansion, potentially we will just be adding horsepower to increase our throughput.
Okay. Great. And then last one from me. On the Mariner I System. If I'm not mistaken, I think even though you guys have put it into service, you guys still have to do some testing for salvage value because the pipe is so old. What exactly is going on there? And is there still a chance that the pipeline will have to be shut down and if that's the case is that something you can fill for with ME2X?
No, this is Mackie again. No, we're not aware of them. There's all kind of rumblings around the country from different groups, but we're not aware of anything. We've brought Mariner I back on. We worked very closely with the PUC to do everything that they've asked. The integrity is 100% in shape and we're excited that system's back up and running.
Our next question comes from the line of Shneur Gershuni with UBS.
Maybe if we can go back to Christine's question about DAPL. In terms of adding pumps and horsepower, I think you'd mentioned in response to her question that you can materially increase. Are we talking about getting the system up to 700,000 or 800,000 barrels a day with just pumps? And then secondly, if the open season is strong enough, is there any small looping projects that could be done on the Southern end that can increase the capacity further to say 1 million and so forth? I was just wondering if you can sort of give us a runway of how this can be expanded?
Yes, this is Mackie again. It's probably a little premature to give the exact volumes, but as we -- as I mentioned, as we walk through the steps that are necessary to move forward on increasing our capacity, we are very optimistic that, as I mentioned earlier, we have tremendous amount of interest, we will respond to that interest. So the open season will dictate kind of where we go, but we can add material volumes certainly at the levels that you mentioned with just adding horsepower.
Great.
And, Mackie, just go back to the question. I mean this is not part of what our expansion is today, but if our open season goes extremely well, then a small section of, it's should have been referred to as looping, I think it will be a replacement because the MLP could in fact take us to even larger volumes.
That is correct.
Great. That is extremely helpful. And maybe as another follow-up. Just, you were talking about exports, but I was wondering if you can talk about Nederland a little bit. Is there a potential for a VLCC-type of a loading capacity out of Nederland? Any way to use kind of existing infrastructure to sort of keep cost down? I was just wondering if that's something that you're considering?
Absolutely. We -- Nederland is such an incredible asset for us. We can move -- we move so much volume through Nederland. It's growing daily both -- all commodities, not just crude, but we are looking very hard and hopefully be able to announce in the not-too-distant future a VLCC project that is kind of in high demand with a lot of our customers and we hope to get to the finish line very soon.
Great. And just one final question. Tom, in your prepared remarks you talked about if conditions continue you could potentially get to higher end of your guidance range. It would seem that there is even potential to exceed that. How does that impact your leverage targets of getting below 4.5x? Is that something that you see occurring during the first or second half of 2019?
Yes. I'm always a little bit cautious about the calculations. As you know, all the agencies look at this a little bit differently, specially when you've got the number of joint ventures we have, et cetera, that, that kind of sits into. So always a little bit cautious. But actually a very, very good question. Even when you look at this first quarter and if you were to annualize that, you can get down to some numbers that are pretty low. In other words, in that 4.6x, 4.7x, 4.8x type range. So we're in a band there. And as we continue look out through the year and we can -- and you started off the question right. In other words, spreads, commodity prices, et cetera, stay where they are. It's one of those that -- I'm going to be a little cautious here, but we're pretty excited about how quick we're deleveraging the balance sheet here.
Our next question comes from the line of Spiro Dounis with Crédit Suisse.
Starting with getting out of PGC at this point and evaluating other crude pipelines. Can you provide a little bit more color there on maybe the types of projects you would be interested in and how critical Nederland or Nederland connection would be for you to join another pipeline. And maybe just to be clear, it sounds like you are not pursuing a new development beyond maybe what's already been announced?
This is Mackie again. What we're pursuing is what's best for our unitholders and for our customers. And right now, we're focused on the existing capacity we have. We're looking at expanding that capacity on our existing system by looping or adding horsepower. But in addition to that, we stay in dialogue with other companies where it might make sense to partner and to move barrels from the fastest-growing area in the world probably.
And then to your point on Nederland, I said it earlier, it's just an -- it's such an incredible asset as you have -- it's probably one of the bigger hubs around when you look at the -- all the 36-inch pipes coming in and out of that area, the connectivity to all the refineries and all the markets along the Gulf Coast. And then of course, our increasing the capability to export products out of that area. So we will continue to look at every opportunity and every way we can to move more volumes out of the Permian Basin to our assets along the Gulf Coast.
Understood. Okay. And then just on the asset portfolio in general. Is there any appetite here opportunistically to capture some of the premium pricing? We're seeing in the private market by selling some assets. I know you guys value optionality, but alternatively can you also provide a little -- maybe your latest views on the M&A market from an acquirer standpoint?
Are you asking what's our appetite for acquisitions?
Yes. I guess, the part is would you be looking at to high-grade your portfolio or sell anything noncore here just to capture some of those higher prices? And then just stepping back more broadly how you sort of view valuations in general?
Yes. We pretty much have done what you've said here. If you look at USA compression and some of the other moves that we've made to kind of move out of noncore. We will continue to look at any assets that we believe are noncore and that are worth more to someone else than they are to us. So we're not ruling that out. But we've done so much of that already, but we will continue to review it.
Okay. Last cleanup one from me. Just on PE4 and [indiscernible] you mentioned it, we're a little surprised at how quickly that's able to come online. Could you just speak to the timing around that and then what's underwriting that project?
You bet. Yes, we've been working on this for a while similar to Bakken where we're not looping any pipe. All we are doing is adding horsepower. We are adding 120,000 barrels a day in the third quarter, we already have a material amount of that sold under a term agreement. And we're excited about that project coming on especially at this time providing customers and producers in West Texas more outlets for their production.
Our next question comes from the line of Jean Salisbury with AllianceBernstein.
CapEx, the last few years has no doubt been elevated by Mariner East cost overrun. Can you guys kind of arrange a go forward growth CapEx once you've finished with that franchise?
Yes. Really, when you look out and you -- I mean, like I said, you stated that properly, with a lot of these large projects they're starting to roll through. So as you kind of look out, and we'll give guidance at least for 2020 later this year. But when you look out, I think you're probably at a run rate of that 3 -- maybe $3 billion to $4 billion, just because of this sheer scale and size of the company is probably a good run rate. But we'll update those and it could be a little bit lumpy. As you know, we've been talking about LNG and stuff. So keep all that in mind as we look out. But I think that $3 billion to $4 billion range is probably a good number.
That's helpful. And then what would it take to increase LPG export capacity from Mariner South. Is that something that you're actively looking at or marketing?
Well, in fact, we are increasing the capacity as we speak. We have an LPG expansion project that will come online in the third quarter of 2020, which is much needed for our customers and for ourselves. So we're moving forward on that. As well as that we've just brought on a gasoline export -- created gasoline export capability, and so we're pretty excited about everything that's going on at Nederland increasing our capability of exporting all of our products.
Our next question comes from the line of Colton Bean with Tudor, Pickering, Holt.
Mackie, just to follow-up on the discussion there of Dakota access. I think you mentioned shipper interest and how that would impact your thoughts around incremental CapEx investment maybe on ETCOP. So if you just lay the options there in terms of maybe looping some of the pipeline versus looking at a joint tariff structure with third-party pipes out there?
Sure. We'll look at anything. But let me emphasize one thing; one, we couldn't move material volumes, probably 800,000 or 900,000 a day without any added loop on ETCOP. And as Kelcy [ph] mentioned a moment ago, however, if the market interest and the demand is there and it very likely will -- could be, then we'll look at looping pipe on ETCOP. But right now, we'll wait and see, and we'll kickoff an open season hopefully in the coming months and they will react to how the market responds.
That's helpful. And then just on the interstate segment. So it looks like there is a bit of a sequential uptick there in operating costs. Can you guys just provide a little bit of color there in terms of whether we should expect that to repeat or not?
Yes. And I'll tell you it's really tied to one item and that's [indiscernible] and tax that we're seeing. And so as you look forward I would say that, that is something that will continue. We're going to be looking at ways obviously to always try to optimize the best we can, but that's what occurred and that is a go-forward kind of quarter-by-quarter.
Our next question comes from the line of Jeremy Tonet with JPMorgan.
Just wanted to start off with Waha and touch a little bit more on this here. It seems like even just in the past few weeks 2020 widened out by another $0.50, I guess, in the past few months here. And just wondering if you could refresh us on your thoughts as far as how you think about terming out that capacity, looking to flip that opportunity into long-term contracts versus holding it back, the open capacity, and enjoying the spreads there. Any color on kind of how you're approaching that?
You bet. This is Mackie again. As with all of our pipelines, we always are trying to look to the future and rollover contracts that are terminating and certainly our latest NTP cross-haul capacity. It does come open from time to time. And we -- what our strategy is now is that we have the ability to start selling capacity later -- latter part of 2020 and early part of 2021 [indiscernible] benefit for the next year, 1.5 years from wider spreads. And then about the time the second 42-inch is built when more likely than not the basis will collapse, they will have a lot of that already locked up. We, in fact, in the last several weeks have locked up fairly significant volumes in Oasis beginning the latter part of 2020, first part of 2021 for 10 years at healthy rates.
Great. And then I suppose on the crude oil side. Midland spreads have really widened out again, I guess, kind of more than expected. With the second quarter here shaping up to at least be as good as the first quarter, so just wondering your thoughts on coming out the crude oil side? And again, I'm trying to reconcile with these favorable market conditions as well as the growth in fee-based earnings, what would prevent you guys from hitting the top end of your guide or exceeding it?
This is Tom Long again. And yes, that's the reason why when we look at the numbers and we look at the spreads as well as those commodity prices we say that we could be on the high-end of that range. And listen, there is nothing more we would love to, be able to get back on the next call and be walking that up. But let's see how the commodity prices and spreads play out as well as the ramp-up of the projects and then we'll be obviously talking to you each quarter about that.
Got you. And then just the last one, I guess. Wink to Webster, was there any interest in potentially working with that project there or is PE4 kind of get you where you want to be. And if PGC's no longer in the fold, could that lead to kind of CapEx being a little bit lighter than what you guys anticipated before?
As far as the CapEx, we're not changing it, Tom said it. We are around the $5 billion and that really had a long impact. Certainly, we've taken some money out of -- on that, but we're filling in with other projects. But yes, we were very interested in looking at all projects that we could potentially bring value to our customers and our unitholders. We did have discussions. At the end of the day, it just didn't make sense for us to participate in that project. And so as I mentioned earlier, we're looking at other projects and other ways of looping and maximizing the capacity on our existing systems.
Our next question comes from the line of Keith Stanley with Wolfe Research.
Couple of questions on Lake Charles. Are you still thinking you could potentially be ready for an FID decision in the first half of 2020 with the new Shell agreement and, I guess, also the China situation? And would you look to build this all 3 trains at once or is it more likely you proceed in stages on the project?
Great questions. We plan to build all 3 trains concurrently with a kind of sequencing of LNG offtake coming from first train and then 6 months later offtake with a second train, and so forth for the third train. But it's cost effective to build all 3 trains at the same time. We're confident that the market is there for all 3 trains with our arrangement with Shell as 50-50 partners in the project. Shell will take 50% of the offtake and Energy Transfer would market 50% of the offtake. And so we're confident that we'll be able to do that.
The China trade talks have, of course, created some issues with the China market. We have an incredible amount of interest from major Chinese LNG buyers, and so I think that's gone very well. But there's a certain amount of reluctance to go -- to get to the goal line or go past kind of certain stages based on kind of the instructions I think from the Chinese government. But the interest level is very high. The -- our project is very price competitive. The partnership with Shell provides an incredible amount of credibility to the project. It's a Brownfield project with all the existing permits and infrastructure in place to launch the projects.
So the reception from the Chinese market has been very good as it has been in Europe as well. So we're confident in the marketing. As far as the timing goes, as you probably saw the announcement of our launching of the EPC bidding process last week, and that's a very significant milestone in terms of getting to FID. The bidding process takes quite a while. It's a big project and we want the bidders to have enough time to fully evaluate and provide the most competitive -- cost competitive bids that they can come up with. It will be a very interactive process. And so we expect that the bidding process will end up with a EPC bidder being selected sometime in the early part of 2020. And so the FID would logically come some time after that after evaluating the cost competitiveness of the bids and obviously seeing that we've been able to place our 50% of the offtake under long-term contracts. So we're confident that we will get there, but there is some major work to be done between here and there.
That's very helpful. And then as far as the import contract and just the structure of the JV. What would happen with that contract as part of moving forward if you do so?
Yes. That contract will remain in place. So we'll continue to receive the payments under the regas contracts through the duration of the contract, which I think expires late 2029 or early 2030. So that stays in place. We've worked out under the project framework agreement with Shell that all the issues with accommodating the export project with the import project -- or the import facility today. So that's a lot of clarity with Shell as they were the logical partner because of their contract with us on the regas side. So all that's been worked out and we're very pleased with where we are today.
That's great. And one quick one on Mariner. You said ME2X you're still targeting the end of the year. When do you expect to expand capacity on ME2 closer to what you initially planned for that pipeline?
On ME2?
Yes.
Yes, [indiscernible] where we are at right now of course, we've got Mariner I going, Mariner II going, we'll have 2X we hope by the end of this year. We are kind of stair-stepping the -- or we have stair-stepped our commitments up as we go through the next couple of years. We aren't specifically sharing with how high those commitments are going. But as we have expressed in the past, there is significant upside to capacity that we have built in that we are building and we will continue to see that as a huge growth vehicle at Marcus Hook and moving out of the Northeast.
Our next question comes from the line of Michael Blum with Wells Fargo Securities.
Tom, I want to ask you in your prepared remarks there at the end you referenced a leverage target, I don't want to put words in your mouth, of 4 to 4.5. I think in the past you really just talked about 4.5. So I just wanted to see if there is a subtle shift there in messaging and are you sort of now targeting a slightly lower leverage?
Absolutely, Michael. We are -- I think the way that we look at is, is the 4.5 that we realized that if you use a 4 to 4.5 range with the sheer size of our company now that gives you a lot of dry powder, flexibility, et cetera. So we're going to continue to charge toward that. And of course, I can't emphasize enough that the ratings and our focus right now on really moving up to the -- kind of that mid -- the mid-BBB type range. So a true focus of ours, but yes, 4 to 4.5 and that was obviously well thought out before we put that in, but that is our target.
Great. And then earlier in the call I think, Mackie, you talked about the fact that you have an LPG export expansion underway that would come in, in the third quarter of 2020. How big is that?
It's 150,000 barrels. Hey, Michael, I meant 200,000 barrels, sorry.
Our next question comes from the line of Dennis Coleman with Bank of America Merrill Lynch.
A lot of good questions asked. What's the -- in Pennsylvania, the progress on Mariner East 2 and X [ph] that you talked about and the expandability. Could you talk a little bit more about sort of the scale of the opportunity at the Marcus Hook facility in terms of would it be tanks, docks, what the capital might be?
This is Mackie again. Yes, as we keep saying we -- it's such an incredible asset that sits in such a great part of the country and it just doesn't compare with our competition and what we can offer both in the Gulf Coast and in the Northeast. But we have -- as with our pipes where we have the ability to move, we'll have the ability to move up to 400,000 barrels or more a day into Marcus Hook. We also have the capability of adding chilling and tankage to handle at least that much volume. We have four large docks that can handle significant volumes on a daily basis from an export standpoint. And we have such a footprint there, there is also other things we can do at Marcus Hook. So we wouldn't say we're unlimited, but we have enormous potential of adding assets and adding throughput through Marcus Hook.
Okay. And then, I guess, just a little bit more. It sounds like the China office is certainly at least in part geared toward the LNG in the offtake sales there. But are there other initiatives that you're working on? Is that the VLCC offtake as well or dock -- potential for a dock at Nederland? What's was the focus there in that office?
Yes, all of the above. It's -- that office will focus on increasing our business with China across all commodities. We had a team over there last week on the crude side to grow our business there. We have -- as Tom mentioned, our LNG team that will be working out of that office. And then there's a big focus on our ethane and propane and butane sales out of China.
As Tom mentioned, there is so much potential in China and it's going to happen. It's just -- but with the tariffs kind of slowing things down, it's not moving as quickly as we all would like, both us and the Chinese companies. But we are moving forward on negotiating deals that hopefully will be in an executable form once the tariffs are cleared up and we -- they will be -- at some point they will be, whether it's weeks or months we don’t know. But yes, we'll have an office very active in all commodities.
Okay. And then maybe just one detail on the LNG potential of Lake Charles. In terms of where that -- where your offtake might go, there was a mention of China, which we just discussed, but also I think Europe was mentioned. Would you expect it to be a balance or is it a 75% to the -- to Asia, 25% Europe, any mix you can sort of guide to?
Great question. I think obviously with the increase in Chinese demand, I think it's grown 35% to 40% each, in the last 3 years. So China will be a significant part of the demand equation. We have interests in Japan. We have interests in Korea. Europe is also interested. So it's probably -- I mean, it's -- we're in discussions with a lot of companies, but I would suggest probably 2/3 in Asia and 1/3 in Europe at this point.
Our next question is from the line of Michael Lapides with Goldman Sachs.
Capital allocation, so if I take -- if I assume EBITDA in the $11-billion-ish range, $10.5 million, $11 billion, take whatever consensus is for next year. The midpoint of the growth CapEx you kind of talked about, let's just say, $3.5 billion, interest a little over $2 billion. It implies you've got a decent chunk of free cash flow next year even after the distribution. How are you thinking about capital allocation in terms of the options of either increasing dividends or purchasing back -- repurchasing equity or retiring even more debt, maybe even getting to a lower net debt-to-EBITDA level? How are you thinking about the options and what the market will reward you for? And then how are you thinking about the time line of making decisions around those options?
This is Kelcy. And that's -- we're thinking a lot about this. We've -- and me particularly, I've been on the road with some of these guys and listening to the market just try and understand what the market would like to see us do, what causes our unit price to perform better, in other words. And really we don't know.
We do know this. So we'll start with this. We made a commitment to the rating agencies to get to a certain number that we'd been very vocal about that and that we're going to honor that commitment. So we're not going to see any distribution increases or unit buybacks or anything like that until we achieve that commitment. We're -- a previous question suggested that we're a chip shot away from that. I think that is probably true. We're doing very well.
Now when I ask people, when I go out and -- on these strips, if we were to increase distributions do you think our unit price would go up? And the answer is no, it will go down. Well shoot. If that's the case, then we can check that box. We're not doing that.
Secondly, would buying back units, not -- no one even loves that. And thirdly, what we're hearing is from most people is just keep paying down debt and that's the best solution. Here is the problem. The problem is that is not a very long-term view of an MLP and we run this thing with a view of 30 years at least when we think about the way we are managing it. And so I think some of these are short-term things that the market will shift, it always does. And we will listen to the market and conduct ourselves appropriately.
Kelcy, just a quick follow-up. When you think about the lumpiness in CapEx and inherently CapEx in this business is extraordinarily lumpy. And you think about 2020 or 2021, do you think you're potentially spending significant capital laterally on either Lake Charles or VLCC or is there a third potential project out there outside of those two that is really sizable relative to kind of normal growth projects like processing plants?
Yes, listen, this is Tom Long. When you really kind of look out at the -- the LNG is the, I think the first one you brought up, and just for the sake of discussion here. I know Tom Mason was earlier talking about getting to FID and, et cetera, but when you really look at the CapEx spend on that it's a pretty even CapEx spend. So for the sake of discussion, if you are around $1 billion a year over 4 to 5 years or something like that it would be pretty evenly spent. So I don't -- I wouldn't look at that as a lump, I guess I was saying.
Now, as far as the other type projects, the reason I answered that question earlier is you kind of look out and you say 3 to 4. If you looked at really kind of the approved projects right now that are out there that we're moving forward. Sure, you look at 2020, we're going to continue with these great projects. But as of right now, there is not really a big item that makes a big lump in those spend as you look out. But I don't want to chime in, in front of Mackie here or whatever, his team's always got great projects out there, but I would say I wouldn't look at it as real lumpy.
Okay. And then last one and I apologize for hogging a little time here. On a potential VLCC, are you all in the MARAD permitting process already with the project?
No, we're not.
Congrats on a good quarter.
Our final question comes from the line of Chris Sighinolfi with Jefferies.
I also appreciate all the time and color today. Tom, just real quickly, if I could piggyback on Jeremy's earlier guidance calibration question, you guys had noted about $124 million increase year-on-year in the crude acquisition in marketing results last quarter. I'm just curious if we could have a sense of the total absolute contribution from that activity last quarter. Might be able to ferret it out from your 10-Q when that's out, but just would be helpful as we calibrate to the second half of the year?
All right. So let me make sure I understand your question. You're trying -- I think is it more focused on -- mainly what we talked about earlier was is the -- is that 9 million barrels of that operating inventory.
I think you had noted in the release that excluding any of the unrealized gains and losses, about $124 million step-up from -- sequentially from last year for crude acquisition and marketing. So I'm just trying to understand what the absolute contribution would be?
Yes, we don't split that out in the business. I know we put the 124 in there, but we really don't try to separate that marketing business inside of the over crude oil business. That's not something that even in the Q when it comes out, you'll see us break out.
Okay. All right. Then my quick follow-up is just the rationale for the -- you mentioned the $800 million preferred offering. I guess, the decision to do pref to replace maturing debt instead of replacing like with like, [indiscernible] and Michael both had questions about your leverage. I'm wondering if that was the primary motivation given the partial equity treatment. And if so, is this something where we're likely to see you do with future refinancings?
Yes, I guess the best way to probably really describe those is they're just one funding source. Clearly, we don't have any intention to do the pure equity piece of it. So it's a way to, as you look out and you see this, like you say, the $5 billion of growth CapEx. It's just a way to fund the portion that's not being funded by the retained cash flow that continues to look at opportunities to get the leverage to a lower level. That's the way I'd best describe it. And as far as looking forward, yes, it is a tool, if you will, or let's say it's a source of funding that we will continue to evaluate.
Ladies and gentlemen, I would now like to turn the conference back to Tom Long for closing comments.
Well once again, thanks all of you for joining us. We -- it's always great to be able to talk to you about these record quarters as they keep stacking up here. And we look forward to talking to you with any follow-up questions you might have.
Thank you. Ladies and gentlemen, this concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.