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Energy Transfer LP (NYSE:ET)
Q2 2019 Earnings Call
Aug 8, 2019, 9:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Greetings. Welcome to the Energy Transfer's Second Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instrucitons] Please note this conference is being recorded.

I will now turn the conference over to your host, Tom Long, Chief Financial Officer. Mr. Long, you may begin.

Thomas Long -- Chief Financial Officer

Thank you, operator. Good morning, everyone, and welcome to the Energy Transfer second quarter 2019 earnings call. We really do appreciate all of you 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'll 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 few key highlights for the quarter. Our adjusted EBITDA hit another record for the second quarter of 2019 coming in at $2.82 billion. This was up 25% compared to the second quarter of last year. DCF attributable to the partners of ET as adjusted also increased almost 25%. We continue to see very strong performances in all of our major businesses and very high utilization across all of our assets.

The NGL and Refined Products segment delivered another record quarter as a result of the ramp up of ME2 and record frac volumes that were driven by Frac VI coming online earlier than planned and filling up almost immediately. Pricing differentials between markets have also continued to remain strong for much of 2019, driving outperformance in our optimization businesses.

Distribution coverage for the quarter was 2 times, which resulted in excess cash flow after distributions of $800 million for the quarter. In addition, since the end of the quarter, we successfully brought on Arrowhead III processing plant online ahead of schedule. And the second phase of our Red Bluff Express pipeline is now operationally complete.

We are also pleased to say that at the end of July we loaded our first barge at Nederland with natural gasoline. As a result of this strong performance and the completion of several key growth initiatives, for 2019, we are revising our adjusted EBITDA guidance higher. We are also lowering our full year capex guidance. We expect our 2019 adjusted EBITDA to be approximately $10.8 billion to $11 billion, which is up $200 million from our previous guidance range.

As for capex, we now expect to spend approximately $4.6 billion to $4.8 billion on organic growth projects, which is down from our previous guidance of approximately $5 billion. This is as a result of a number of projects coming in at lower cost than expected as well as deferring some capital spend, which is not expected to have any impact on start dates.

Before going into more detailed discussion around second quarter earnings growth capex and a liquidity update, I want to provide an update regarding the latest developments on our growth projects. As a reminder, in late March, we announced that we have signed a project framework agreement with Shell that provides the foundation to further develop the Lake Charles LNG export facility for a final investment decision. In addition, in early May, Lake Charles issued an invitation to tender to US and international consortia to bid for engineering, procurement and construction contract.

Energy Transfer and Shell will each have a 50% equity interest in the project and each company will be entitled to 50% of the LNG off-take. Energy Transfer is actively marketing its 50% of the LNG off-take or 8.25 million tonnes per annum. The project 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 tonnes 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.

As for Orbit, which is our joint venture with Satellite Petrochemical for which we are constructing a new ethane export terminal on the US Gulf Coast to provide ethane to Satellite. Construction continues to progress as scheduled for the project in both the US and China, and we continue to expect the export terminal to be ready for commercial service in the fourth quarter of 2020.

Now looking at our Mariner East system, as a reminder, we placed the initial capacity of ME2 into service on December 29th, 2018 and volumes continue to ramp up in the second quarter. Since resuming operations on ME1 in late April, the combined Mariner East pipeline system has moved approximately 230,000 barrels per day of NGLs through Marcus Hook, and we expect that volume to continue to ramp up when ME2X comes online later this year. Additional inbound transportation modes, including trucking and rail, remain heavily utilized. This brings total NGL volumes to Marcus Hook to approximately 300,000 barrels per day.

International LPG arbitrage economics were strong in the second quarter, demonstrating the strength of this terminal in efficiently reaching the best markets for our customers. Our further expansion efforts at Marcus Hook are under way and progressing nicely with increased facility capacity expected for summer of 2020. We continue to make progress on additional local area connections for ethane, propane and butane distribution, including a new power plant at Cambria County in Western Pennsylvania, as well as additional off-take points in Central and Eastern Pennsylvania to serve the Harrisburg, Redding and Greater Philadelphia markets.

We also continue to evaluate and discuss the additional manufacturing opportunities at Marcus Hook domestically, including PDH technology and our collation [Phonetic]. However, we will remain disciplined on our capital approach and only target higher-returning projects with synergistic revenues. Now looking at ME2X, mainline construction is 99% complete. And at this time, we continue to target having the pipeline in service by late 2019.

Moving on to our Lone Star assets, as a reminder, the 150,000 barrel per day Frac VI went into service in mid-February and has been full since March. On Frac VII which will also be 150,000 barrels per day, we continue to expect it to be in service in the first quarter the 150,000 barrel per day, we continue to expect to be in service in the first quarter of 2020 and anticipate it would be at full capacity very quickly. We're also moving forward with another 150,000 barrels per day fractionator at Mont Belvieu. Frac VIII is expected to come online in the second quarter of 2021 and is also expected to ramp up quickly. This will bring our total frac capacity of Mont Belvieu to over 1 million barrels per day.

As to our 24-inch 352-mile Lone Star Express expansion, we'll 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 by or before our original estimates of the fourth quarter of 2020.

At our extremely strategic Nederland asset, we are expanding our suite of product offerings and started loading our first barge with natural gasoline. We're looking to further expand our natural gasoline export operations at this facility. In addition, we are excited to move forward with our 200,000 barrels per day LPG expansion project at Nederland, which further integrates our Mont Belvieu assets with our Nederland assets to expand our LPG export capabilities.

Another project we are very excited about is our Bakken pipeline capacity optimization. As mentioned on our previous earnings call, the Bakken pipeline received sufficient market interest during the December 2018 open season for us to move forward with plans to further optimize the system capacity. More recently, in July, we announced a binding supplemental open season to solicit additional shipper commitments for transportation service on the system. The initial expansion of the Bakken pipeline system above its current capacity of 570,000 barrels per day will be based on commitments made by shippers that we have already received, as well as commitments made during the current open season. As Bakken volumes grow in the future, we will be capable of expanding the system capacity up to 1.1 million barrels per day over time based upon customer demand.

Our PE1, PE2 and PE3 pipelines, which are part of our Permian Express joint venture with ExxonMobil, all continue to operate at full capacity. We're 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 the third quarter of this year. We're also advancing discussions on a VLCC project that would be connected to our Nederland terminal. As this project gets closer to FID, we will provide you with more specifics.

Now turning to our processing plants in West Texas, our 200,000 mm cubic feet per day Arrowhead III processing plant in the Delaware Basin went into service in early July and is projected to be full by year-end. In addition, we will be working on additional 200-million-cubic-foot-per-day processing plant in the Permian Basin ahead of schedule by the end of this year. This plan is already fully subscribed and once in service will bring our total processing capacity in the Permian Basin to more than 2.7 Bcf per day.

On our Red Bluff Express pipeline, Phase 1 went into service in May 2018. Volumes during the second quarter averaged approximately 385,000 MMBtus per day. A majority of these volumes are also flowing through our Waha Oasis Header, thereby generating additional revenues downstream. We are pleased to say the second phase of the Red Bluff Express is now operationally complete. We expect to begin collecting a portion of those revenues on August 15 ahead of schedule, and additional revenues on the system are expected to grow over the next couple of years as the contractual commitments step up.

We are also nearing completion of a debottlenecking project in Central Texas that consist of looping approximately 20 miles of existing pipe with 42-inch pipeline, and will provide an incremental 500,000 Mcf per day of capacity to Carthage [Phonetic] and Beaumont markets. It is expected to be in service in early September 2019 and is backed by fee-based commitments.

On the product side, the J.C. Nolan Diesel Pipeline has an initial capacity of 30,000 barrels per day and transports diesel fuel from Hebert, Texas, to a newly constructed terminal in Midland, Texas area. This is a 50/50 joint venture agreement with Sunoco LP or SUN. The project utilizes existing ET pipelines, which were contributed to the joint venture. The pipeline and terminal are now in service and we began loading our first commercial truck on Monday, August 5th.

Now, we'll take a little closer look at the second quarter results. ET's consolidated adjusted EBITDA was up 25% to $2.82 billion compared to $2.26 billion for the second quarter of 2018. This is due to strong growth in four out of five of our core operating segments, including record operating performance in our NGL and refined products segment. ET's DCF attributable to the partners as adjusted was $1.6 billion for the second quarter, up approximately $300 million or nearly 25% compared to the same period last year, primarily due to the increase in adjusted EBITDA. And coverage for the second quarter was 2 times. In July, Energy Transfer announced a distribution of $0.305 per common unit for the second quarter or $1.22 per common unit on an annualized basis. This distribution is flat compared to the first quarter of 2019 and will be paid on August 19th to unitholders of record as of the close of business on August 6th.

Turning to our results by segment, we'll start with the NGL and refined products segment. Adjusted EBITDA increased 40% to $644 million compared to $461 million for the same period last year. The increase was due to record transport and terminal volumes, which benefited significantly from the start-up of the Mariner East 2 as well as record frac volumes. NGL transportation volumes on our wholly owned and joint venture pipelines were 1.3 million barrels per day compared to 967,000 barrels per day for the same period last year. The increase was primarily due to higher volumes on our pipelines out of the Permian Basin and North Texas regions, as well as increased volumes on our Northeast assets due to the start-up of our ME2 pipeline in the fourth quarter of 2019. Second quarter average daily fractionated volumes increased to 701,000 barrels per day compared to 473,000 barrels per day last year, primarily due to the commissioning of our fifth and sixth fractionators at Mont Belvieu, which came online in July of 2018 and February of 2019 respectively.

As to our crude oil segment, adjusted EBITDA increased more than 35% to $751 million compared to $548 million for the same period last year. The increase between the second quarter of 2018 and the second quarter 2019 was primarily due to increased throughput in the Permian on existing pipelines and growth on our Bakken pipeline.

Crude transportation volumes increased to a record 4.7 million barrels per day compared to approximately 4.2 million barrels per day for the same period last year, primarily due to an increase in the barrels through our existing Texas pipeline and volume growth in the Bakken. During the second quarter, volumes on our Bakken pipeline averaged approximately 560,000 barrels per day, which is up nearly 20% year-over-year. As our results demonstrate, demand for space on both our Bakken pipeline and Permian Express pipes remain very strong.

For the midstream, adjusted EBITDA was $412 million compared to $414 million for the second quarter of 2018. Higher midstream throughput volumes were offset by lower NGL and gas prices, which impacted our results by $50 million. Compared to the first quarter of 2019, adjusted EBITDA increased to $30 million, primarily due to the volume increases across all of our regions and higher fees collected in the Permian and in the Northeast.

The other gas volumes were 13.1 million MMBtus per day compared to 11.6 million MMBtus per day for the same period last year. This increase was primarily due to higher volumes in the Permian, growth on Ohio River System in the Northeast, as well as growth in North Texas region.

In our Intrastate segment, adjusted EBITDA increased more than 20% to $460 million compared to $375 million for the second quarter of 2018. This increase was primarily due to additional EBITDA from Rover, higher utilization of our Transwestern and Trunkline system, and additional gas processing revenues on our Panhandle system.

Transportation volumes were 10.8 million MMBtus per day compared to 8.7 million MMBtus per day for the same period last year due to an increase of 1.2 million MMBtus per day from the Rover Pipeline as well as increases on Tiger due to production growth in the Haynesville Shale and deliveries to intrastate market and increased utilization of higher contracted capacity on Panhandle and Trunkline.

In our Interstate segment, adjusted EBITDA increased nearly 40% to $290 million compared to $208 million in the second quarter of last year. This was primarily due to a $65 million increase from commercial optimization activities as a result of a wider basis differential from West Texas to the Houston Ship Channel and an increase of $14 million in transportation fees, primarily due to new contracts and Red Bluff Express coming online in May of 2018. Reported transportation volumes increased primarily due to Red Bluff Express coming online as well as increased utilization of our Texas pipelines due to favorable spreads across our system.

As to Sunoco and USA Compression, for our investment in SUN, we had another solid quarter, adjusted EBITDA increased to $152 million compared to $140 million a year ago, primarily due to an increase in fuel volume sold and decreased operating expenses. And for investment in USA Compression, who also had a strong quarter, adjusted EBITDA was $105 billion compared to $95 million a year ago, driven by an increase in demand from compression services as well as a decrease in operating and SG&A expenses.

Now moving to our capex update, for the six months ended June 30th, 2019, Energy Transfer spent approximately $1.7 billion in organic growth projects primarily in the NGL and refined products and midstream segments, excluding SUN and USA Compression's capex. And for full year 2019, as mentioned, we have lowered our growth capex forecast from approximately $5 billion to approximately $4.6 billion to $4.8 billion.

Now, looking briefly at our liquidity position, as of June 30th, 2019, total liquidity under our revolving credit facility were approximately $3.56 billion and our leverage ratio was 3.6 times for the credit facility. 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 receive 50% equity credit from all three rating agencies, which represents an additional step-up in our plan to achieve our leverage ratio target of 4 times to 4.5 times.

Before opening the call up to your questions, I just want to reiterate that we are very pleased to have once again delivered another record quarter. Our increased 2019 adjusted EBITDA guidance is driven by our core segments, which continue to deliver strong performances that is supported by our predominantly fee-based earnings and are further augmented by strategic expansion projects, including Bakken, the Permian Express Pipelines, Frac VI, ME2, Bayou Bridge, Red Bluff Express, and others, as well as outperformance in our optimization businesses.

In addition, we continue to generate a significant amount of excess cash flow, which 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. As a result, we do not expect any common equity needs for the foreseeable future. With operations in nearly all of the major producing basins in the US and an integrated portfolio with a leading footprint across the midstream value chain, we are well-positioned to take advantage of 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.

Questions and Answers:

Operator

[Operator Instructions] Our first question comes from Spiro Dounis, Credit Suisse. Please proceed with your question.

Spiro Dounis -- Credit Suisse -- Analyst

Hey. Good morning, everyone. Maybe just starting off with the outlook, if we could. Over halfway through 2019 now and 2020 even closer, I was hoping maybe for some updated thoughts on how we should think about growth next year relative to 2019, especially in light of the guidance increase you guys just put out, but also maybe addressing some of the puts and takes around Bakken pipeline expansion and ME2 coming online, but also just being able to count on differentials next year sounds like that shouldn't be in the plan. Any thoughts there would be helpful.

Thomas Long -- Chief Financial Officer

Yeah. Good morning. This is Tom Long. As we kind of go through 2019, clearly we're probably not at that stage where we're going to start looking at guidance for 2020. Clearly we have seen some very good spreads this year, etc. But at the same time, we do have a lot of good growth projects. I think you highlighted it. But, I guess, I would really answer this is, we'll be looking later in the year of guidance really as you look out toward 2020. Obviously as we walk through this year, it's been nice to be able to walk this up, and we'll continue to look as we get through each quarter for the rest of the year. So...

Spiro Dounis -- Credit Suisse -- Analyst

Okay. Understood. And then, just on the capex reduction for 2019, can you maybe walk through some of the more specific drivers? I believe you'd expected at one point to backfill PGC and some of the other projects. Is that no longer the case? And then, where are you on adding an additional Permian crude pipe at this point?

Thomas Long -- Chief Financial Officer

Okay. Well, listen, I'll take the first part of that -- the first part about the overall reduction. I will say that, when you really look at, it was kind of across the board and in our segments, but remember that -- remember that the liquids -- the natural gas liquids segment clearly makes up 60% or so of our entire guidance. So, you can appreciate that that was the largest of the dollar amounts as we looked out. And really a lot of that was associated with the liquids line that we've talked about in here. But it also was lower cost associated with the frac. So, great job by the team, the engineering and construction team, etc, on being able to bring these costs down. So, this isn't a matter of just pushing some of the cost out. But Mackie, I'll let you kind of talk about the second part of that question.

Marshall S. McCrea -- President and Chief Operating Officer

Okay. Yeah. As you look at the kind of the crude side, we focus on -- right now, we're not really concerned about building new pipes. We're really focusing on the Bakken, Cushing, Nederland on moving volume but most importantly on selling our capacity. Spreads have been good and our focus is to turn in these as more pipelines come online that we can flip our contract and extend our contracts at margins that work for us. That doesn't mean we're not looking at and analyzing other projects, other growth projects, but our focus is on filling up our existing assets.

Spiro Dounis -- Credit Suisse -- Analyst

Helpful. And then, just to tack on to that last part, were you pretty active on that front both in crude and on gas over the last quarter?

Marshall S. McCrea -- President and Chief Operating Officer

Were we pretty active?

Spiro Dounis -- Credit Suisse -- Analyst

In terms of contracting and firming out the capacity.

Marshall S. McCrea -- President and Chief Operating Officer

Oh, yeah, absolutely. We have both of our teams on the natural gas side and on the crude side and on the NGL side are focusing it more on the long-term. We've seen margins go out, we've seen spreads go out, that's been really nice to be a part of, but now our focus is extending these contracts out five, seven, 10 years at very good margins. And we're looking more long-term as I mentioned it. So, yeah, we are in the process of extending contracts across Texas, our natural gas pipeline systems, and we're also focusing on extending not only our crude projects under long-term agreements but also time that to our Nederland terminal, our Bayou Bridge business and also the VLCC project that we're working on.

Spiro Dounis -- Credit Suisse -- Analyst

Very helpful. Thank you, gentlemen.

Operator

Our next question is from Jean Anne Salisbury, Alliance Bernstein. Please proceed with your question.

Jean Anne Salisbury -- Alliance Bernstein -- Analyst

Hi. Good morning. If you don't do a VLCC project in Nederland, what would be the maximum that you could export from the area of all products and do you get close to that after the upcoming DAPL and LPG expansions?

Marshall S. McCrea -- President and Chief Operating Officer

Well, what a -- this Mackie again, what a tough question. It's hard to say -- it's hard to answer that question because we have a tremendous capability of expanding Nederland. We can add multiple [Indecipherable] docks. We're also looking at some other areas we could add docks and add terminals. We are extremely optimistic that our VLCC project will go. So it's hard to even answer a question to believe -- to do what we do if it didn't happen. But we have, as I said, tremendous capability of expanding our business at Nederland, at Marcus Hook, along all the product lines, whether it's propane, butane, as you heard earlier, natural gas, we just started exporting. We're completing our first ethane project. We are building our second large LPG export project, so it's just kind of the beginning of what we can do at Nederland and Marcus Hook.

Jean Anne Salisbury -- Alliance Bernstein -- Analyst

Okay. Got it. So it's more of like the most cost-effective way to do it but it shouldn't be read as like a concern that if you didn't do it you would run out of capacity?

Marshall S. McCrea -- President and Chief Operating Officer

Right.

Jean Anne Salisbury -- Alliance Bernstein -- Analyst

Got it. Okay.

Marshall S. McCrea -- President and Chief Operating Officer

We'll be...

Jean Anne Salisbury -- Alliance Bernstein -- Analyst

And then, just given the falling gas prices, there's been some concerns around Marcellus and Utica E&Ps. I believe that in the past, you've referenced that if Ascent gets into financial trouble with Rover that Energy Transfer has the option to take over part of Rover. Is that still the case and can you provide anymore color on that?

Thomas Long -- Chief Financial Officer

Sure. This is Tom Long. Clearly when we set up the Rover, the contract -- when we were out contracting that, we clearly got securities and various -- I don't want to necessarily get into the complete details on that, but we do feel like we've got everything from LCs to other type securities that we can look at, but I think the most important piece of it is, there is standard dilution type features in that likewise. So, I think that maybe the way you're asking that question about taking over, it's more of a dilution where you get a larger percentage. So...

Jean Anne Salisbury -- Alliance Bernstein -- Analyst

Okay. That makes sense. That's all for me. Thank you very much for taking my questions.

Operator

Our next question is from Shneur Gershuni, UBS. Please proceed with your question.

Shneur Gershuni -- UBS -- Analyst

Hi. Good morning, guys. I was wondering if I can just get a clarification on Spiro's earlier question. In your response to his question about capital expenditure going forward in large projects, outside of the LNG project that you talked about in your prepared remarks, your response sounded like you're not really working on any big projects right now or not noodling a lot of big projects right now and really more focused on increasing utilization. Is that correct? And so, should we think that the capex trend for 2020 should be significantly lower than where we are for this year.

Marshall S. McCrea -- President and Chief Operating Officer

Yeah. This is Mackie. I'll start just on the comment of, we certainly are pursuing large projects. I mean, we're very excited about the Bakken expansion. We will expand. We're not sure how big that's going to be, but that will be a really nice optimization revenue source for us. We're also looking, as I mentioned earlier, to work with customers to move more volume out of Cushing and out of Midland. So, it's not that we're not looking at growth projects, but a lot of our emphasis and where we're really focusing on the longer term on our existing capacity and keeping and gaining as much value as we can through those existing assets.

Thomas Long -- Chief Financial Officer

Yeah. Listen, I'll take the second part of that. As far as that capex guidance, once again, we usually put that out with our third quarter call. And so, for 2020, this does not apply to. But we have said in the past, and I think we're still very good with that that, our capex spend is probably in that $3 billion to $4 billion range. But I'd like to hold off on 2020 until we do see kind of like what Mackie's talking about as we look at these projects that are currently in place and how the spend works on that. But I think $3 billion to $4 billion, Shneur, would be a good number to use for going forward if you're looking at long-term.

Shneur Gershuni -- UBS -- Analyst

That's very helpful, and it's good to hear that you're focused on high-return bolt-ons. Just sort of continuing along that lines, the results this quarter were very strong. It seems like you've surpassed the leverage target that the credit rating agency had outlined for you. Your coverage is strong. Your capex is now lower. Have you had any discussions with the agencies with respect to your credit outlook? Are you now in a position to consider buybacks at this stage because it sort of seems like it would be more enhancing credit-wise to actually buy back units when they're yielding over 9% versus much lower-yielding debt? I'm just wondering if you can sort of talk about the outlook in the agencies and where you see you are on buyback spectrum.

Thomas Long -- Chief Financial Officer

Well, clearly don't ever want to try to get out in front of the agencies, but I will answer your question very directly. Absolutely we continue to have meetings with them and update them on our projections. We think we do have a very compelling outlook for Energy Transfer as far as our leverage metrics, but also as far as our coverage metrics, etc. You are exactly right. I mean, buying back units right now obviously is very accretive. But I will say that leverage metrics that we're talking about, if you really kind of look at not just this quarter annualized or first quarter annualize, but even try to look back over the last four quarters, we have depending on the various calculations between the various agencies which they all have a little different methodologies as to how they go through that, you're clearly in that 4, 4.5 to 5 range.

I would not say we're in that 4 to 4.5 range yet. So, clearly it's exciting to be here. We feel like we're right on the doorstep, and clearly we're doing a lot of analysis internally here on how we would allocate those dollars. And you brought the debt pay down, but in other words between distribution growth or unit buyback or debt pay down. So, we're looking at that and, remember, it doesn't have to be one, it can be a combination of any of those, especially when you get as large as we are, you can kind of allocate dollars to each. So, we're looking at that and very excited to be able to even answer this question with you right now. So...

Shneur Gershuni -- UBS -- Analyst

That makes total sense. One final question, if I may. With the PDS closure, is there an opportunity to partner with SUN to move refined products on ME2X when it starts up to sort of fill the void for refined products in that market?

Marshall S. McCrea -- President and Chief Operating Officer

This is Mackie. Yeah, working with SUN, sure. I mean, we're always going to work with our affiliate where it makes sense. They, of course, are more heavily in the refined products as we are, and so anything that makes sense between our two partnerships, we'll certainly look at. From just an ET lens though, we're certainly looking at ways of utilizing our pipe in different manners and we do anticipate in the future utilizing some of our pipes -- more of our pipes for refined products, especially with what happens with PES. We're situated very well to be able to capitalize and to help the demand in a shortage of supply in Philadelphia and kind of New York area.

Shneur Gershuni -- UBS -- Analyst

All right. Perfect. Thank you very much, guys. Really appreciate the color today.

Operator

Our next question is from Michael Lapides, Goldman Sachs. Please proceed with your question.

Michael Lapides -- Goldman Sachs -- Analyst

Hey, guys. Two questions. One on the Bakken pipeline or DAPL and one on the VLCC. On DAPL, what are the steps? How should we think about the process to be able to get the appropriate permits and other items needed to actually add pumps or other items needed to expand capacity there?

Marshall S. McCrea -- President and Chief Operating Officer

Well, as Tom mentioned, it's funny, a little things like that we're pretty excited about. If you look at the opportunities and the needs to provide capacity up there, nobody compares to DAPL and the beautiful thing about DAPL is that all we have to do is add pumps to move materially more volumes. We've already secured volumes to move forward on an optimization project. However, as everybody knows, we're in the middle of an open season. We're very optimistic how that open season will go, and we will add pumps and other needed facilities to meet the contractual obligations that we'll have at the end of the open season. But it couldn't be better timing. There are some other projects, much smaller, was not near the netbacks that we'll provide for producers getting all the way to the Gulf Coast at significantly cheaper prices. So we're pretty excited about DAPL and look forward to increasing our volumes in the next couple of years.

Michael Lapides -- Goldman Sachs -- Analyst

Are there any specifically their permits or rights you need to be able to actually do this? I mean, brownfields are always easier than greenfield, but we live in a world where we're honestly building anything in a large part of the country is really challenging.

Marshall S. McCrea -- President and Chief Operating Officer

Every project's different. There's different permits and different steps that we have to take, and we've taken those steps and we're moving forward on optimizing this project as soon as we can.

Michael Lapides -- Goldman Sachs -- Analyst

Got it. And on the VLCC, are you all already in the MARAD process meaning to be able to get US government approval to build something offshore. I know that that can be an extended process. I'm just trying to think about timeline and when construction could actually start if you were to get the go ahead and get contracts.

Marshall S. McCrea -- President and Chief Operating Officer

We're in the middle of that. To put a time frame on it, you're probably talking more through this process at least three years, two-and-a-half to three years, two-and-a-half, probably best case, and three years. So we expect to make some filing soon. And as we mentioned earlier, we're very excited about this. It's going to be a great market opportunity for not only our Nederland and Permian Express systems but also more importantly for all of our customers that brings volumes into Nederland, but it's several years out but we're working on it with a lot of our teams.

Michael Lapides -- Goldman Sachs -- Analyst

Got it. Thanks guys. Much appreciate it.

Operator

Our next question is from Colton Bean, Tudor, Pickering, Holt. Please proceed with your question.

Colton Bean -- Tudor, Pickering, Holt -- Analyst

Hi. Good morning, guys. So I think you had noted the projects coming in below budget. Can you just offer us a brief overview of how you approach the budgeting process whether there are contingencies baked in, if that process shifted at all over the last few years?

Marshall S. McCrea -- President and Chief Operating Officer

Yeah. This is Mackie again. Every project is different. For example, we've built nine, or 10, or 11, 200,000 acre rails [Phonetic] over the coming -- over the past several years and continue to build them. So, we're pretty comfortable with those costs. And we certainly wouldn't have as much contingencies. And depending on the risk in areas of the country, certainly we would incorporate more contingencies. We -- Kevin and his team though are really looking ahead, and we try to go out, for example, on pipeline projects, look at the amount of rock, etc. So, we were doing a really good job on wherever at, on estimating the cost of projects, but we certainly treat every project differently depending on the specifics of that project.

Colton Bean -- Tudor, Pickering, Holt -- Analyst

Got it. And then, just on Interstate, a nice sequential step-up there, but natural gas sales margin was actually a little bit lighter than we would've expected given the Waha to Katy spread. Can you just update us on your hedge profile and whether we should expect some installation there if the spread does actually contract later this year?

Thomas Long -- Chief Financial Officer

Yeah. If you're referring to our residue volume that we control and we own, we don't really have exposure to that for the most part because we're buying that on a, for example, on a Waha Index and sell on the Waha Index. So, the prices are negative or zero. We really aren't exposed to that. Now, on some of our POP, we certainly are exposed, but a lot of that we do have under long-term contracts across the state to Katy.

Colton Bean -- Tudor, Pickering, Holt -- Analyst

Got you. And so, implicitly not a whole lot of basis hedging going on, on the Texas Interstate system?

Thomas Long -- Chief Financial Officer

Really the way we're hedging right now is, we're signing up contracts beginning over the next six months to a year under 10-year extensions. That's how we're hedging with third-parties.

Colton Bean -- Tudor, Pickering, Holt -- Analyst

Understood. Thank you.

Operator

Our next question is from Pearce Hammond, Simmons Energy. Please proceed with your question.

Pearce Hammond -- Simmons Energy -- Analyst

Yeah. Good morning, and thanks for taking my questions. Just following up on some of the questions on the VLCC project. I know there are a lot of these sorts of projects proposed on the Gulf Coast. What do you think differentiates your project and gives it a greater probability of getting completed?

Thomas Long -- Chief Financial Officer

Well, I think, one, we have the best of both engineering and construction and commercial teams, that helps a lot. But if you look at Nederland and you look at the amount of barrels that come in regardless of where the outlets are, pipelines have come from Canada, from Cushing, from West Texas, from every major area come into the Nederland and then we have significant connectivity to all the refineries, and course Bayou Bridge. So it's an incredible terminal with, I think, the largest aboveground oil storage in the country.

And so, if you look at all that, we offer a significant advantage just from a supply source. And then, from a market source, we just have to be compelling price, and we're working on our cost and we're negotiating with potential shippers and we feel real good about how we're progressing.

Pearce Hammond -- Simmons Energy -- Analyst

Thank you. And then, my follow-up is, what will be the capital cost of adding the eight fractionator at Mont Belvieu, and then do you see the fractionation market as being tight for an extended period?

Thomas Long -- Chief Financial Officer

I'll start out with the tightness of the fractionation. The way we look at it, we certainly try to pay attention to our competitors and look at what they're doing and overbuilt situations. But our real focus is on honoring our agreements. And as we've continued to grow our internal G&P business and as we've continued to tie to third-party cryogenics, we're under the gun to build fracs. Once we'll have % Frac VIII built, we'll have all of our fracs at about a 90% demand charge for all that capacity. It gives us a little leeway to grow more volumes on our pipelines, bringing volumes in there and also gives a little cushion toward any issue. So, we don't -- at some point, it'll fluctuate or get tight. But right now, all we're really concerned about is building fracs that meets the demands of our customers.

Pearce Hammond -- Simmons Energy -- Analyst

Okay. Great.

Thomas Long -- Chief Financial Officer

And then -- I'm sorry. This is Tom. I'll kind of take the second part you were saying from a cost standpoint as you look at these. Every one of these may vary a little bit depending on how much you just tie into that the previous frac or if you've got to try to go out a little bit further. I think you're probably looking at this one, probably in the $400 million, $450 million range or so.

Pearce Hammond -- Simmons Energy -- Analyst

Great. Thanks so much for taking my questions.

Thomas Long -- Chief Financial Officer

You bet.

Operator

Our next question is from Christine Cho, Barclays. Please proceed with your question.

Christine Cho -- Barclays -- Analyst

Morning, everyone. With NGL prices in contango and your storage position in Belvieu, is this a potential opportunity or is most of your storage contracted to third-party?

Marshall S. McCrea -- President and Chief Operating Officer

This is Mackie, again. Once again I hate to keep bragging about are assets and our teams, but we're so well-situated especially compared to the vast majority of our competition. The way we utilize our storage is of course number one, to make sure that we can handle all the volumes that come in and move all the barrels that come out of the tailgate of our fractionators. But we also do a lot of third-party, but where the margins are now, there are pretty significant differences in prices today for NGLs and what we see in the wintertime. So, we feel very fortunate to have the ability to store large amounts of NGLs if the opportunities arise to do that.

Christine Cho -- Barclays -- Analyst

Okay, great. And then, moving over to Rover, just given the structure of ownership there with the Holdco and then another partner outside that Holdco, I think, is there a word to be a potential sale of that? How would that work? Are there welfare role flow on this tag along rights?

Thomas Long -- Chief Financial Officer

Yeah. Christine, this is Tom. That's one that we're not going to be able to comment on right now. I mean, clearly you're right, you do have a structure in certain way that there is a Holdco and different structures. But that's -- like I said, that's not one that we can really comment on right now without discussing with our partners, so.

Christine Cho -- Barclays -- Analyst

Okay, fair enough. And then, on Lake Charles, can you just remind us, do you need to get the majority of your share of the eight MCP contracted all at once before moving forward with the project or can it be done in phases, like maybe you have enough to move forward as one train? Do you FID that and just continue to contract for the other trains or the economics don't make sense unless you do all at ones?

Tom Mason -- President, Lake Charles LNG

This is Tom Mason. It's a large scale project, and one of the benefits of size and scale of the project is, we reduce the unit cost by spreading the cost over a larger number of trains and volumes. So, our current plan is to continue to build the full 16.5 million tonnes and market 50% of that.

Christine Cho -- Barclays -- Analyst

Okay, thank you.

Operator

Our next question is from Jeremy Tonet, JPMorgan. Please proceed with your question.

Jeremy Tonet -- JPMorgan -- Analyst

Hi, good morning. I just wanted to pick up on some of the comments that you had in prepared remarks there. I'm not sure if I caught that right, but was there a half B of natural gas capacity that you're looking to extend from Central Texas to the Coast there, did you say? And how far West does that go? Does that get into the Permian? Does that get into Waha there? Any other details that you could share with us?

Marshall S. McCrea -- President and Chief Operating Officer

Sure. This is Mackie. Without getting a lot of details for competitive reasons, it will provide a little more capacity from the West, but predominantly there's -- we're seeing tremendous, really strong growth in some areas of East Texas where our pipelines run right to the heart of those areas. And then also, as you all know, there's a lot of volumes that are now feeding down into our Godley facility and we expect those volumes to grow. So we've been able to provide firm outlets for -- and also cartridge to move volumes from all parts of East Texas and North Central Texas down to the best markets in the country, which is Katy and kind of Beaumont area.

Jeremy Tonet -- JPMorgan -- Analyst

That's helpful. Thanks. And maybe just kind of drawing on a few questions or points that's been talked about here, and appreciate with Rover, there's news article out there talking about potentially monetizing that, and can't comment -- I would imagine, you can't comment too much on that, but just curious, is this the type of environment out there as far as M&A is concerned where you see the potential to kind of sell things that maybe aren't as core to your business and really use that as an opportunity to accelerate deleveraging or buyback stock with those proceeds if buyers are willing to pay more than what you guys value that asset at?

Thomas Long -- Chief Financial Officer

Yeah. Jeremy, actually, you asked the question and you could almost put the answer in the same format. And what I mean by that is that, I mean, clearly as we've kind of talked about in some of the previous calls, we do see the opportunities out there to maybe to look at -- as we look across our entire portfolio of assets that might make sense, and the drivers are just what you say. The drivers would be to delever at a faster clip and to give you more flexibility on whether it be the unit buyback, or debt pay down, or a combination, it's not really or, it can be and between them. So, yes, in answer to your question, we continue to evaluate assets internally that makes sense that would fit that bill.

Jeremy Tonet -- JPMorgan -- Analyst

So that's all for me. Thanks for taking my question.

Operator

Our next question is from Dennis Coleman, Bank of America Merrill Lynch. Please proceed with your question.

Dennis Coleman -- Bank of America Merrill Lynch -- Analyst

Great. Thanks. Thanks for getting me in here. I guess maybe we can start with the Mariner East. Obviously you mentioned you have 99% done on ME2X. What's left to do there? Obviously there's been quite a bit said and written and that last 1% seems to be the sticking point. But any update you can give there would be helpful.

Kevin J. Smith -- Energy Transfer LP -- Executive Vice President, Engineering & Construction

Sure. This is Kevin. We still have a number of HDDs in Crossing's to complete. That's all going per the plan. And as Tom mentioned in his opening statements, we're still very confident that we'll be able to put any ME2X in service by end of fourth quarter.

Dennis Coleman -- Bank of America Merrill Lynch -- Analyst

And on -- I guess, on just ME2, the last mile there, the work around, has that been resolved or is that still part of this last 1%?

Thomas Long -- Chief Financial Officer

We're not sure what you mean the last work around is ME2.

Dennis Coleman -- Bank of America Merrill Lynch -- Analyst

Well, you had the pipe that you repurposed to make ME2.

Thomas Long -- Chief Financial Officer

Oh, the GRE? Okay. I think the way we'll answer that is just how it's going is that, right now, we're focused on getting 2x in, which will give us a really three pipelines through that area to Marcus Hook. And then, later in 2020, we'll finalize the last segment which will give us kind of the max capacity that we'll need in the future through that area in the Marcus Hook.

Dennis Coleman -- Bank of America Merrill Lynch -- Analyst

Okay. And then, one I have asked before, but on the Orbit deal, obviously the rhetoric and trade noise continues. It doesn't seem to be impacting your project there, but any comments or color would be useful.

Thomas Long -- Chief Financial Officer

Yeah. It doesn't have any impact at all. We're moving forward. We're on time, met with their contingency in fact. Several weeks ago. they came in and they're moving forward. And I think both sides would like to see it end at some point, and we all believe it will. We're not sure how long it will be. But from Energy Transfer standpoint, our focus is finding a home for our liquids. And if that means China, it means China. If it means other parts of the world, then that's what we're doing. So, we certainly have expanded out to other areas, but we remain in negotiations with several -- a number of Chinese companies. And as soon as the tariffs were lifted, we expect to move forward hopefully on other projects. But, in the meantime, Satellite is going very well.

Dennis Coleman -- Bank of America Merrill Lynch -- Analyst

Alright. That's it for me. Thanks.

Operator

We have reached the end of the question-and-answer session. And I will now turn the call back over to Tom Long for closing remarks.

Thomas Long -- Chief Financial Officer

Yeah. Once again, we just want to thank all of you out there for joining us today. We really appreciate the support. We remain very, very excited about the performance of our existing assets and of course to be able to talk to all of you today about all the projects that we have coming online. We look forward to any other questions, follow-up questions later that you all might have, and look forward to meeting with you in the near future. That's all, operator. Thanks.

Operator

[Operator Closing Remarks]

Duration: 54 minutes

Call participants:

Thomas Long -- Chief Financial Officer

Marshall S. McCrea -- President and Chief Operating Officer

Tom Mason -- President, Lake Charles LNG

Spiro Dounis -- Credit Suisse -- Analyst

Jean Anne Salisbury -- Alliance Bernstein -- Analyst

Shneur Gershuni -- UBS -- Analyst

Michael Lapides -- Goldman Sachs -- Analyst

Colton Bean -- Tudor, Pickering, Holt -- Analyst

Pearce Hammond -- Simmons Energy -- Analyst

Christine Cho -- Barclays -- Analyst

Jeremy Tonet -- JPMorgan -- Analyst

Dennis Coleman -- Bank of America Merrill Lynch -- Analyst

Kevin J. Smith -- Energy Transfer LP -- Executive Vice President, Engineering & Construction

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