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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 Instructions]
It is now my pleasure to turn it over to your host, Tom Long, Chief Financial Officer. Mr. Long, you may begin.
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 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 few 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 segments 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 two 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're 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 costs 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 our 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 offtake.
Energy Transfer is actively marketing its 50% of the LNG offtake or 8.25 million tons per annum. The project would convert Energy Transfer's existing Lake Charles LNG import and the gasification 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,
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 29, 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 and efficiently reaching the best markets for our customers. Our further expansion efforts at Marcus Hook are underway and advancing 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 offtake 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 alkylation. 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 it's 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 of 2020 and anticipate it will be at full capacity very quickly.
We're also moving forward with another 150,000 barrel 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 frack capacity at Mont Belvieu to over 1 million barrels per day. As to our 24 inch 352 mile Lone Star Express expansion, 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 expected to be in service by or before our original estimate 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 barrel 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 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, 2 and 3 pipelines, which are part of our Permian Express joint venture with Exxon Mobil 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, a 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 bring on additional 200 million cubic foot per day processing plant in the Permian Basin ahead of schedule by the end of this year. This plant 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. The 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're also nearing completion of a debottlenecking project in Central Texas that can assist us losing approximately 20 miles of existing pipe with 42 inch pipeline and will provide an incremental 500,000 Mcf per day at capacity to Katie 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 Heber Texas, to newly constructed terminal in Midland, Texas area. This is a 50-50 joint venture agreement was 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 5.
Now, we'll take a little closer look at the second quarter results. ETs consolidate 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 product segment.
ETs 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 two 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 19 to unitholders of record as of the close of business on August 6.
Turning to our results by segment, we'll start with the NGL and refined product 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 startup of the Mariner East 2 as well as record frack 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 through the startup of our ME2 pipeline in the fourth quarter of 2018.
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 six fractionators in Mont Belvieu, which came online in July of 2018 and February of 2019, respectively.
As for 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 of 2019 was primarily due to increased throughput in the Permian on existing pipelines and growth on our Bakken pipelines.
Crude transportation volumes increased 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 pipelines 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 in both our Bakken pipeline and Permian Express pipes remain very strong.
For the mid-stream, 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 $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 in 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 North Texas region.
In our Interstate 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 in MMBtus per day from the Rover pipeline, as well as increases on Tiger due to production growth and the Haynesville shale and deliveries to Interstate markets, and increase utilization of higher contracted capacity on Panhandle and Trunkline.
In our Interestate 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 $65 million increase from commercial optimization activities as a result of a water 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 increase utilization of our Texas pipelines due to favorable spreads across our system. As to Sunoco and USA Compression or investment in Sun, who 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 million 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 a CapEx update, for the six months ended June 30, 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 CapEx. And for full year 2019 as mentioned, we have lowered our growth CapEx forecast from approximately $5 billion to approximately $4.6 to $4.8 billion.
Now, looking briefly at our liquidity position, as of June 30, 2019, total liquidity under our revolving credit facilities 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 revolving credit facility and for general partnership purposes.
As a reminder, these securities received 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 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 find our excellent backlog of growth projects in a credit friendly and a creative manner and allow us to further organically strengthen our bank 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'll remain very focused on safety and project execution.
Operator, please open the line up for questions.
[Operator Instructions] Our first question comes from Spiro Dounis, Credit Suisse. Please proceed with your question.
Hey, good morning, everyone. Maybe just starting out with the outlook if we could. We're 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 '19, 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, ME2 to 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?
Yeah, good morning, this is Tom Long. As we kind of go through 2019, clearly, we're not we're probably not at that stage where we're going to start looking at guidance for 2020. Clearly, we had seen some very good spreads this year, et cetera. 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 towards 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.
Okay, understood and then just on the CapEx reduction for '19. Can we walk through some of the more specific drivers? I believe you'd expected one point to backfill PGC and some of the other projects? Is that no longer the case? And then where are you on adding additional Permian crude pipe at this point?
Okay, well, listen, I'll take the first part about the overall reduction, I will say that when you really look at it kind of across the board and our segments, but remember that the liquids, the natural gas liquid 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 that we 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, et cetera 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.
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, Midland 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.
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?
Were we pretty active?
In terms of contracting and firming out the capacity.
Yeah. Absolutely, we have a – both of our teams on the natural gas side and on the crude side and on the NGL side are focusing 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 and 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 tying that to our Nederland terminal, our Bayou Bridge business and also the VLCC project that we're working on.
Very helpful. Thank you, gentlemen.
Our next question is from Jean Ann Salisbury, AllianceBernstein. Please proceed with your question.
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 are you - do you get close to that after the upcoming DAPL and LPG expansion?
This is 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 [indiscernible] docks. We're also looking at some other areas, we can 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 it to do what we do if it didn't happen. But we have as I said tremendous capability of expanding our business at Nederland and Marcus Hook along all the product lines, whether it's propane, butane, as you heard earlier, natural gasoline, 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 just beginning of what we can do with Nederland in the market.
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 concerns that if you didn't do it, you would run out of time?
Right.
Got it, okay.
Yeah, we'll be able to – we'll be, yes.
And then just given the fall in 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 any more color on that?
Sure, this is Tom Long. Clearly when we set up the Rover 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 types of 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 may be the way you're asking that question about taking over, it's more of a dilution where you get a larger percentage.
Okay, that makes sense. That's all for me. Thank you very much for taking my question.
Our next question is from Shneur Gershuni, UBS. Please proceed with your question.
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?
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 on 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.
Yeah and 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 Mackey's talking about is, we look at these projects that are currently in place and how the spend works on that. But I think three to four Shneur would be a good number to use for going forward a few looking at long-term.
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 your credit rating agencies 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 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 from the agencies and where you see you are on the buyback backdrop?
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 for as our leverage metrics. But also, as far as our coverage metrics et cetera, 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 the first quarter annualized, 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 for 4.5 to 5 range. I would not say we're in that 4 to 4.5 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 how we allocate those dollars and you brought up debt pay down. But the 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 dollar stage. So we're looking at that, and very excited to be able to even answer this question with you right now.
That makes total sense. So one final question, if I may, with the PES closure, is there an opportunity to partner with Sun to remove refined products on ME2x once it starts up to sort of fill the void for refined products in that market?
This is Mackie. Yeah, working with Sun, sure, I mean we're always going to work with our affiliates, where it makes sense. They, of course are more heavily into 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 what's happened with PES we were situated very well to be able to capitalize and to help the demand and the shortage of supply in Philadelphia and kind of New York area.
All right, perfect. Thank you very much guys, really appreciate the color today.
Our next question is from Michael Lapides, Goldman Sachs. Please proceed with your question.
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?
Well, as Tom mentioned, it's funny, little things like that we're pretty excited about. If you look at the opportunities and the need 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 at the end of the open season, but couldn't be better timing. There's some other projects much smaller with not near the net backs that will provide produces getting all over the Gulf Coast, it's significantly cheaper process. So we're pretty excited about that DAPL and look forward to increasing our volumes over the next couple years.
Are there any specific either permits or rights you need to be able to actually do this? I mean, Brownfield's always easier than Greenfield, but we live in a world where we're honestly building anything and a lot large part of the country is really challenging.
Every project is 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.
Got it and on the VLCC are you all already in the maybe read process meaning to be able to get US government approval to build something offshore, I know 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?
We're in the middle of that. To put a time frame on it, you're probably saying – you're talking going through this process at least three years, two and a half to three years, two and a half, probably best case and then three years, so we can 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.
Got it, thanks, guys, much appreciated.
Our next question is from Colton Bean, Tudor, Pickering, Holt. Please proceed with your question.
Good morning, as 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 they're contingencies baked in if that process has shifted at all over the last few years?
This is Mackie again. Every project is different. For example, we built nine or 10 or 11, 200,000 like trials coming over the past several years and continue to build them. So we're pretty comfortable with those costs, so we certainly wouldn't have as much contingencies. And depending on the risk and 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 and for example, in pipeline projects, look at the amount of rock et cetera. So we were doing a really good job on wherever we're at on estimating the cost of projects, but we certainly treat every project differently depending on the specifics of that project.
Got it and then just on interest rates, a nice sequential step up there, but natural gas sales margin was actually a little bit lighter than we would have expected given the Waha to Katie spread. Can you just update us on your hedge profile? And whether we should expect some insulation there if the spread does actually contract later this year?
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 the Waha index and selling on the Waha index. So if 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 Katie.
Got you, so implicitly, not a whole lot of basis hedging going on the Texas Interstate system?
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.
Understood. Thank you.
Our next question is from Pearce Hammond, Simmons Energy. Please proceed with your question.
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?
Well, I think one, we have the best of both engineering and construction and commercial teams so that 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 that come from Canada, from Cushing, from West Texas, from every major area come into Nederland. And then we have significant connectivity to all the refineries and of course Bayou Bridge. So it's an incredible terminal with I think the largest above ground oil storage in the country. And so if you look at all that we offered it a significant advantage, yes, from our supply source. And then from a market source, we just have to be compelling price. And we're working our cost and we're negotiating with potential shippers, and we feel real good about how we're progressing.
Thank you. And then my follow up is what will be the capital cost of adding the eighth fractionator at Mont Belvieu and then do you see the fractionation market as being tight for an extended period?
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 any overbuilt situations. But our real focus is on honor our agreements. And as we've continued to grow our internal G&P business as we've continued to tie to third party crowds in next year, we're under the gun to build fracks. Once we'll have Frac VIII built we'll have all of our Fracks at about a 90% demand charge. For all that capacity gives us a little leeway to grow more volumes on our pipelines bringing volumes in there and also gets a little cushion if there's any issues. So we don't at some point fluctuate or get tight. But right now, all we're really concerned about is building fracks that meets the demands of our customers.
Okay, great.
Yeah. And then – I'm sorry, this time, 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 the previous frack or if you've got to go out a little bit further. I think you're probably looking at this one, probably in that, $400 million to $450 million range or so.
Great, thanks so much for taking my questions.
Our next question is from Christine Cho, Barclays. Please proceed with your question.
Good morning, everyone. With NGL prices in contango and your storage position in Belvieu. Is this a potential opportunity or as most of your storage contract is third party?
This is Mackie again. Once again, I hate to keep bragging about our 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 target 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 as they have.
Okay, great. And then moving over to Rover, just give the structure of ownership there with the whole HoldCo and then another partner outside that HoldCo I think, if there were to be a potential sale of that, how would that work? Are there row for a row flows tag along?
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 it structured in certain way that there is a HoldCo and different structures. But like I said, that's not one that we could really comment on right now without discussions with our partner.
Okay, fair enough. And then on Lake Charles, can you just remind us, do you need to get the majority of your share the eight MTP contracted all at once before moving forward to 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 that once?
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 year costs by spreading the cost over a larger number of trains and volume. So our current plan is to continue to build the full 60.5 million tons and market are 50% of that.
Okay, thank you.
Our next question is from Jeremy Tonet, JPMorgan. Please proceed with your question.
Hi, good morning. Just want to pick up on some of the comments that you had in your prepared remarks there and not sure if I caught that right. But was there a half BE 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 or any other details that you could share with us?
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 we're seeing tremendous – really strong growth in some areas of East Texas where our pipelines run right through 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 volume to grow. So we may we provide firm outlets and also corkage to move volume from all parts of East Texas in North Central Texas down to the best markets in the country, which is Katie and kind of Beaumont area.
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 buy back stock with those proceeds, buyers are willing to pay more than what you guys value that asset at?
Yeah. No, 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 look at – as we look across our entire portfolio of assets that might make sense and the drivers are just what you said The drivers would be to delever at a faster clip. And they 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, to answer your question, we continue to evaluate assets internally that make sense that would fit that bill.
That's all for me. Thanks for taking my question.
Our next question is from Dennis Coleman, Bank of America, Merrill Lynch. Please proceed with your question.
Great, thanks. Thanks for getting me in here. I guess maybe if we can start with 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 get there will be helpful.
Sure, this is Kevin. We still have a number of HTDs and crossings 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 ME2x in service by end of fourth quarter.
And I guess, on just ME2 the last mile there the workaround has that been resolved? Is that still part of this last 1%?
Yeah. No, I'm not – we're not sure what you mean the last work around ME2.
Well, you had the pipes that you repurposed to make ME2 functional.
The GRE, I got it. Yeah. I think the way we will answer that and how it's going is that right now we're focused on getting to Exane [ph], which will give us really three pipelines through that area to Marcus Hook. And then later and 2020 will finalize the last segment, which will give us kind of the max capacity that we will need in the future through that area in the Marcus Hook.
Okay. And then when I – I have asked before, but on the Orbit deal. Obviously, the rhetoric and trade noise continue, doesn't seem to be impacting your project there. But any comments or color would be useful?
Yeah, it doesn't have any impact at all, we're moving forward with our own time. They're continuously – 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's 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 and 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 are lifted, we expect to move forward, hopefully on other projects, but in the meantime, Satellite's going very well.
Alright, that's it for me. Thanks.
We've reached the end of the question-answer-session. And I will now turn the call back over to Tom long for closing remarks.
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.
This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation.