Greetings, welcome to the Energy Transfer 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. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Tom Long, Energy Transfer Partners Chief Financial Officer. Thank you. You may begin.
Thank you, operator. Good morning, everyone, welcome to the Energy Transfer second quarter 2018 earnings call. Thank you for joining us today. I'm also joined today by Kelcy Warren, Mackie McCrea, Matt Ramsey, John McReynolds, Tom Mason, and other members of the senior management team who are here to help answer your questions after our prepared remarks. I'll begin today with an overview of our simplification transaction we announced last week, followed by a discussion of our latest developments on our Rover, Mariner East 2, Permian Express 3, and other growth projects. I'll turn our focus to a discussion of Energy Transfer Partners' second quarter results, followed by a discussion on CapEx, liquidity and funding, and lastly, distributions. 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 and distributable cash flow, or DCF, both of which are non-GAAP financial measures. You'll find a reconciliation of our non-GAAP measures on our website. Before I provide an overview of the ETE, ETP transaction, I just want to start by saying that we are very pleased with Energy Transfer's record second quarter. ETP's adjusted EBITDA increased more than 30%, and DCF attributable to the partners of ETP, as adjusted, increased nearly 40% over the second quarter of last year. I will provide more details later on in the call, but this increase is due to significantly higher results from the crude oil transportation and services segment, as well as strong growth in several other of our segments. Turning to our most recent announcement.
Last week, ETE and ETP entered into a merger agreement providing for the acquisition of ETP by ETE for $27 billion in ETE common units. Under the terms of the transaction, ETP unit holders will receive 1.28 ETE common units for each ETP common unit, implying a price of $23.59 per unit based upon ETE's closing price immediately prior to the announcement of the transaction. This represents an 11% premium to the previous day's ETP closing price and a 15% premium to the 10-day volume-weighted average ETP price. The transaction is expected to be immediately accretive to ETE's DCF per unit. We expect to maintain ETE's distribution per unit at its current level. In addition, the transaction will create a more simplified ownership structure as we are eliminating the IDRs, which will improve our overall cost of capital.
This will allow us to continue pursuing accretive growth capital projects and strategic M&A transactions. It also increases retained cash to accelerate deleveraging. Following the merger, we are expecting a DCF coverage ratio of 1.6-1.9 times, which equates to about $2.5 billion-$3 billion of annual retained cash. This greatly reduces our external common or preferred equity funding needs going forward. We do expect the pro forma partnership to be rated investment grade. The transaction is expected to close in the fourth quarter of 2018, subject to approval by the majority of the unaffiliated ETP unit holders and other customary closing conditions. We expect to file the S-4 early next week. Moving to our growth projects, we'll start with Rover. On May 31st, we received authorization from FERC to commence service on the Supply Connector B and full Mainline B pipeline segments on Rover.
As of June 1st, 100% of mainline capacity, which is 3.25 BCF per day, is in service, we are currently collecting demand charges on approximately 80% of the contracted capacity. Rover is now 100% mechanically complete. For our overall project restoration activities, rough cleanup is 99% complete, final cleanup is 81% complete, and revegetation is 78% complete. We expect to have all these restoration activities 100% complete this month. We submitted in-service request to FERC for Majorsville on May 7th and Burgettstown on February 13th and plan to file for Sherwood and CGT by mid-August. Our Revolution processing plant is complete, we expect it to go into service once Rover has received full approval of the remaining supply laterals. Moving on to ME2 and 2X. We continue to make progress on the construction of ME2 with 99% of mainline construction complete and 80% of hydro testing complete.
In addition, 100% of HDDs are completed or in process in line with our approved HDD plan, with no more drilling reevaluation reports required from DEP. The Pennsylvania PUC's commissioners have overturned the prior decision that prevented continued construction in West Whiteland Township. To avoid any delays in the ME2 project schedule, we will utilize a section of an existing pipeline in the affected area for initial in-service. This plan does not require any new permits, and we have made all applicable regulatory notifications. As a result, we continue to expect to place ME2 in service by the end of this quarter. This will allow us to bring sufficient capacity online to meet all of our initial contractual commitments. Construction of ME2X also continues, we expect the pipe to be online in mid-2019.
As we announced on our last call, ETP and Satellite Petrochemical USA Corp have entered into definitive agreements to form the Orbit joint venture to construct a new ethane export terminal on the U.S. Gulf Coast to provide ethane to Satellite. Satellite received provincial approval for the construction of their ethane cracker in early July, we continue to expect the export terminal to be ready for commercial service in the fourth quarter of 2020. Also during the second quarter, we completed an open season for the J.C. Nolan diesel pipeline. That will transport diesel fuel from Hebert, Texas, to a newly constructed terminal in the Midland, Texas, area. The pipeline will utilize existing ETP pipelines and is projected to have an initial capacity of 30,000 barrels per day. ETP and Enterprise are in the process of expanding the jointly owned 36-inch North Texas Pipeline.
The North Texas Pipeline will provide approximately 160,000 MMBtus per day of additional capacity from West Texas for deliveries into the Old Ocean natural gas pipeline once it is completed at the end of this year. The Old Ocean natural gas pipeline, which is a 50/50 joint venture between ETP and Enterprise, resumed service during the second quarter with initial capacity of 130,000 MMBtus per day, increasing to 160,000 MMBtus per day by the end of the third quarter. The 24-inch Old Ocean Pipeline originates in Maypearl, Texas, and extends south 240 miles to Sweeny, Texas. Now moving to our processing plants in West Texas. The 200-million-cubic-foot-per-day Rebel II processing plant in the Midland Basin went into service at the end of April. The volumes are ramping up, and we expect it to be full by year-end.
In addition, construction on another 200-million-cubic-foot-per-day cryogenic processing facility, which will be near our existing Arrowhead plant, is expected to be completed in the fourth quarter of this year. Also in West Texas, our Red Bluff Express Pipeline went into service in May. This 1.4 Bcf per day natural gas pipeline runs through the heart of the Delaware Basin and connects our Orla plant, as well as multiple third-party plants, to our Waha Oasis header. We are currently expanding this project by an additional 25 miles of 30-inch pipeline, which is expected to be in service in the second half of 2019. On our Permian Express 3, as a reminder, we successfully brought a portion of PE3 online in the fourth quarter of 2017.
During the second quarter, we completed a successful open season for approximately 50,000 additional barrels per day, which represents the final phase of the approximately 140,000 barrels per day PE3 project. We expect this final 50,000 barrels per day to be online later this year. We are also making significant progress with our new 30-inch crude oil pipeline joint venture project with Magellan and other strategic partners. This pipeline will provide unprecedented flexibility from the Permian Basin for deliveries to East Houston and to the significant market and refinery corridor in the Nederland-Beaumont areas. It will also provide shipper capacity to our storage facilities and pipeline header systems, as well as to access to Bayou Bridge. Continuing with Bayou Bridge, construction of the 24-inch segment from Lake Charles to St. James continues, with commercial operations expected to begin in the fourth quarter of 2018.
We are pleased to announce that Lone Star's 120,000 barrels per day Fractionator V went into service in July ahead of schedule. This brings our total frac capacity in Mont Belvieu to nearly 600,000 barrels per day. As a reminder, Fractionator V is fully subscribed by multiple long-term fixed-fee contracts and also includes NGL product infrastructure and a new three-million-barrel Y-grade cavern. We continue to expect the 140,000 barrels per day Fractionator VI to be in service in the second quarter of 2019. The majority of this frac is fully contracted under demand-based contracts. At our Godley plant, full take-or-pay commitments on the 400-million cubic foot per day 10-year agreement with Enable went into effect July 1st, and they are already flowing near the full amount. Now let's turn to our second quarter results. As I mentioned, ETP had another very strong quarter.
Adjusted EBITDA on a consolidated basis was a record $2 billion. This was up more than $500 million compared to the second quarter of 2017. This increase is due to significantly higher results in the crude oil segment as a result of both the Bakken Pipeline coming online as well as strong growth from several of our other segments. DCF attributable to the partners as adjusted also hit a record high of $1.3 billion. This was an increase of $371 million compared to the second quarter of 2017, primarily due to the increase in overall adjusted EBITDA. ETP's coverage for the second quarter was 1.23 times, resulting in excess cash flow over distributions of $249 million. Turning to our results by segment and starting with midstream, adjusted EBITDA was $414 million compared to $412 million for the second quarter of 2017.
During the second quarter of 2017, our midstream segment recorded a one-time $30 million benefit that was the result of several items. Without these non-recurring items, our midstream segment saw strong growth, primarily due to higher throughput volumes and higher NGL and crude prices. Compared to the first quarter of 2018, midstream adjusted EBITDA was up $37 million, primarily due to volume growth across the majority of our regions. Gathered gas volumes totaled approximately 11.6 million MMBtus per day, compared to 11 million MMBtus per day for the same period last year. This was primarily due to increased volumes in the Permian from higher producer demand and growth on the Ohio River system in the Northeast. In the NGL and refined products segment, adjusted EBITDA increased to $461 million compared to $388 million for the same period last year.
The increase was due to higher transport volumes on our Texas NGL and Mariner West pipelines, increased refined products terminal volumes, and growth at the Lone Star Fractionators, as well as higher results from our optimization and marketing group. NGL transportation volumes on our wholly owned and joint venture pipelines were 967,000 barrels per day compared to 835,000 barrels per day for the same period last year, mainly due to increased volumes out of the Permian Basin and on the Mariner West pipeline. Year-over-year, average daily fractionated volumes increased to 473,000 barrels per day compared to 431,000 barrels per day last year due to increased volumes from the Permian producers. Moving on to the crude oil segment, adjusted EBITDA increased to $548 million compared to $228 million for the same period last year.
The increase was primarily due to placing our Bakken Pipeline in service in the second quarter of 2017, increased throughput on existing pipelines, primarily from Permian producers, and higher ship loading and throughput fees at our Nederland Terminal due to an increase in exports, as well as an increase from the crude oil acquisition and marketing business related to favorable basis differentials between Midland and the Gulf Coast. Crude transportation volumes increased to 4.2 million barrels per day compared to approximately 3.5 million barrels per day for the same period last year, primarily due to placing the Bakken Pipeline in service on June 1st of 2017 and increased production from the Permian Basin. During the second quarter, volumes on our Bakken Pipeline averaged 473,000 barrels per day. In our intrastate segment, adjusted EBITDA increased to $208 million compared to $148 million in the second quarter of last year.
This was primarily due to a $47 million increase from commercial optimization activities due to the wider basis differentials from West Texas to the Gulf Coast, as well as the acquisition of the remaining interest in the RIGS pipeline in April. Our reported intrastate transport volumes increased primarily due to RIGS now being treated as a consolidated subsidiary, as well as more favorable market pricing in the Texas markets. In our interstate segment, adjusted EBITDA was $330 million compared to $262 million for the second quarter of 2017. This increase was due to additional EBITDA from the partial in-service of Rover. We expect earnings in this segment to continue increasing with the commissioning of the remaining Rover supply laterals.
Interstate transportation volumes were 8.7 million MMBtus per day compared to 5.3 million MMBtus per day for the same period last year, due to an increase of 1.7 million MMBtus per day from bringing a portion of Rover into service, as well as higher utilization on Panhandle and Trunkline, increases from Tiger due to production increases in the Haynesville Shale, and increases on Transwestern as a result of favorable spreads across the pipeline. Moving on to the all other segment, which includes our equity method investment in limited partnership units of Sunoco LP, consisting of 26 million units, representing 32% of Sunoco's total outstanding common units. Subsequent to our contribution of CDM to USA Compression in April 2018, the all other segment also includes our equity method investments in USA Compression, consisting of 19 million USAC units and 6 million Class B units, representing 27% of USAC's limited partner interest.
Adjusted EBITDA was $90 million compared to $107 million a year ago, due to a $44 million decrease in earnings from our investment in Sunoco LP, primarily due to Sunoco LP's sale of retail assets to 7-Eleven, as well as its repurchase of 17 million common units in February 2018, and a decrease of $12 million due to the contribution of CDM to USAC in April of 2018. This was partially offset by increases in adjusted EBITDA related to unconsolidated affiliates due to our equity method investment in USAC, as well as higher EBITDA from our investment in PES. Now for a CapEx update. For the six months ended June 30, 2018, ETP funded approximately $2.2 billion in organic growth projects, primarily in the NGL and refined products and midstream segments.
For full year 2018, we expect to spend approximately $4.5 billion-$4.8 billion in organic growth projects, primarily in the NGL and refined products, midstream, and interstate segments. The increase is primarily due to new growth projects. Taking a look at our funding activities for the quarter as well as our liquidity position. In July, ETP issued $445 million of its 7.625% Series D fixed to floating rate cumulative redeemable perpetual preferred units. Once again, these securities provide an extremely cost-effective means of raising equity capital, and ETP used the proceeds to repay amounts outstanding under its revolving credit facility for general partnership purposes. Like our other recent preferred unit offerings, these securities also received 50% equity treatment from all three rating agencies. In June, ETP issued $3 billion aggregate principal amount of senior notes in a four-tranche offering.
The proceeds of which were used to redeem approximately $1.65 billion of outstanding senior notes and for general partnership purposes. In addition, during the second quarter, ETP bought out the remaining interest at RIGS and paid off the RIGS credit facility. As of June 30, 2018, total liquidity under ETP's revolving credit facility was approximately $3.6 billion. As of June 30, 2018, ETP's leverage was 3.87 for the credit facility. In July, ETP announced a distribution of $0.52 per common unit for the second quarter, or $2.26 per common unit on an annualized basis. This distribution is flat compared to the first quarter of 2018 and will be paid on August the 14th to unitholders of record as of the close of business on August the 6th. Now let's move on to ETE. For the second quarter, distributable cash flow, as adjusted, totaled $407 million.
ETE's coverage for the second quarter was 1.15 times, resulting in excess cash flow over distributions of $53 million. In July, ETE announced a quarterly distribution of $0.305 per unit. This equates to a $1.22 per unit on an annualized basis and will be paid on August 20th to unitholders of record as of the close of business on August the 6th. ETE continues to have a healthy liquidity position and ended the quarter with a debt to EBITDA ratio of 2.79 times for our credit facility. As of June 30, 2018, ETE had approximately $544 million available under its revolving credit facility. Before opening the call up to your questions, I just want to say that we are once again very pleased to have reported another strong quarter.
Contributions from Bakken Crude Oil Pipeline and Rover were big components of this growth in earnings, and we also continue to make great progress toward improving ETP's leverage metrics. We are also very excited to have announced a simplification transaction that provides a premium to current ETP unitholders and is expected to be immediately accretive to ETE's distributable cash flow per unit. With this transaction, ETE will have an approximately $100 billion enterprise value with a simplified structure, enhanced financial flexibility, and a lower cost of capital. Our new financial structure is expected to greatly strengthen our balance sheet and credit profile and position the combined company for continued growth. Looking ahead to the rest of 2018, we are excited for the expected DCF growth as we complete Rover, ME2, and other key projects. With that operator, that concludes our prepared remarks. Please open the line up for questions.
Thank you. Ladies and gentlemen, at this time, we will be conducting the question-and-answer session. If you would like to ask a question, please press *1 on your telephone keypad. The confirmation tone will indicate that your line is in the question queue. You may press *2 if you'd like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Our first question is coming from the line of Spiro Dounis with UBS. Please proceed with your question.
Hi, good morning, guys. I recognize that you can't say much about the simplification projections. I'll just keep my questions to some project questions. Specifically, I was wondering if you can expand a little bit on your prepared remarks with respect to Mariner East 2. I'm trying to understand how using this legacy pipe will help the project advance, how does it address the PUC issues, and is the diameter large enough and so forth. I was just wondering if you can give us a little bit more color on that.
Okay, this is Mackie. We've secured pretty significant volumes for these projects, for ME1, ME2, and ME2X. However, those projects ramp up over time. The utilization of the 12-inch more than provides the necessary capacity to move the volumes that we've contracted. It also allows us to bring ME2 online, hopefully by the end of this quarter. It was necessary, but it has no impact whatsoever on our contractual obligations.
This is Matt. Let me expand on that a little bit. At ME2, I guess it's obviously the first issue with the use of the 12-inch line through there. We have, kind of repeating what was said in the earlier remarks, 99% of the mainline construction is complete. The 1% that remains on mainline constructions is associated with the HDDs that we are completing right now. We have 16 HDDs to complete. All those have been approved by PA DEP. They're either drilling ahead or they're in the stage where we're going back to PA DEP when we have an inadvertent return. They've all been approved. We don't have to have any changes approved by PA DEP going forward like that. All the road bores are finished. As Tom said in the earlier remarks, 80% of the line has been hydro-tested.
We feel confident that we'll be finished with ME2 and in service by the end of the third quarter of this year.
Great. Thank you for that update. Just a couple of quick follow-ups. ETP has just posted a record quarter and has done extremely well on the crude and on the natural gas side as well. Obviously, the spread environment has largely contributed to that. Has there been any talk internally or in terms of thought process about potentially to lock in some of those spreads into some longer term contracts and so forth? Or are you limited by walk up or on other issues? Just trying to understand kind of the ability to sort of capture this for the longer term.
It is Mackie McCrea again. I'll kind of walk through each component. On NGL, it's really not something we look at. We're very pleased that we completed the 24 and 30-inch a little while back because there's not a lot of capacity. We do even see that basis or the value of that transportation from West Texas to Houston going up over the next 18 months. We're well positioned there, but no hedging strategies there. Around natural gas, we've been pretty disciplined on a prudent approach where we have gone out and hedged at healthy margins some of our capacity. There's a considerable amount of capacity that we have not hedged and capacity that we have brought on recently and will be bringing on by the end of the year.
Our approach is kind of twofold on really natural gas and oil, is to secure as much as we think is necessary long term, and also look at when will other pipelines be coming online, which very likely will shrink that basis, and to extend our contracts past that period of time. Around the oil side, we have hedged a while back a considerable amount of our capacity. However, we still have a considerable amount left, and right now we don't think it makes sense to necessarily lock in hedges on that capacity in light of where the environment is today with volume growth out in the Permian Basin and the lack of capacity out of the Permian Basin.
Great. One final question. Are there any updates or progress with Lake Charles on the LNG side?
This is Tom Mason. Not really since our last quarterly call. We're continuing to market our LNG capacity, and things are progressing, but other than that, kind of what we talked about last quarter.
Great. Thank you very much, guys. Really appreciate the update.
Thank you. Our next question is coming from the line of Jeremy Tonet with J.P. Morgan. Please proceed with your question.
Good morning. Congratulations on the great results. I just wanted to pick up on this question from a little bit different angle here. Just granted, you guys are looking to kind of lock in margins as it makes sense over the next kind of year or so. I'm just wondering, how sustainable are these results that we see in the crude oil segment, in the interstate segment? Is there any kind of dissipation in the environment out there where 3Q or 4Q might come in lower than what you did in 2Q, or is this kind of a run rate that you guys are able to achieve and build off of in the current environment?
This is Mackie again. As we said in the last call, we certainly can't predict where gas or oil prices are going, and we certainly can't predict where basis is going. However, we have a team that looks at this daily, have weekly discussions on what capacity is available today, what pipelines will be completed, where volume ramp-up's headed, then we make our decisions based on that. As I said earlier, we have hedged in some areas where it makes sense to hedge, where we have plenty of capacity and we can lock in 10-year deals. It also makes a lot of sense to hold a lot of that capacity when we see a severe shortage of capacity in the NGL and oil segments over at least the next year and a half to two years.
Got you. It sounds like you can't predict exactly what's going to happen 3Q, et cetera, there's no notable headwinds to think that this was going to change dramatically.
Correct.
Thank you. Then just want to touch on some of the expansions here. Was just wondering as far as Permian takeaway, was curious on Permian Express 1, given how Sunrise will be coming online pretty soon, looks like it brings more than enough volumes into Wichita Falls there. Is there room in Permian Express 1 to pick up the volumes there and send it to the coast? Would it make sense to kind of expand that pipe, given how much will be coming in when that project comes online?
Yeah, I think I'd answer that a little more broadly. We're looking at every pipeline we own in our partnership, whether it's an oil service or not, to more fully utilize it and/or to put it in a service that makes more sense. Certainly Mariner 1's in that basket where we're looking at every possible way of increasing capacity out of that could benefit our revenues.
Got Permian Express 1?
I'd say Permian Express. Yeah. Permian Express 1, Permian Express two and three, any of our abilities to expand those assets, we're looking at it daily, and we will have expansions hopefully to announce in the near future.
Great, thanks. Maybe you're not able to share more information at this time, but in the same vein, Dakota Access Pipeline seems like there's a lot of need to expand that as well. Any thoughts you could share?
You bet. This is Mackie again. Like I just said, we're looking at everything that we own, how do we create more capacity and hence more revenue? We have run a lot of testing on that system recently. We do expect to be able to increase that capacity. We're not really, for competitive reasons, saying what that will be. It's something that we're moving forward on and we will increase our capacity as much as efficiently possible to be able to move growing barrels out of Bakken.
That's all for me. Thanks for taking my question.
Thank you. Our next question is coming from the line of Jean Ann Salisbury with Bernstein. Please proceed with your question.
Hi. Good morning. You may have answered this with the last question, can you do any more with drag-reducing agents on your current Permian pipelines or is that pretty much maxed out at this point?
Can you do more what? Could you add any more?
Can you get any more capacity on your Permian pipelines with drag-reducing agents at this point or is that pretty much maxed out?
Yes, we can. As I mentioned earlier, we can expand. We're looking to expand in Mariner East 1. We're looking at what we can do on I'm sorry. Permian Express 1. We're looking at what we can do on Permian Express 3. We'll probably have a Permian Express 4 expansion. We're also looking at other pipelines we possibly could put into oil transportation service.
Okay, those are mainly coming from drag-reducing agents, I guess, or?
Oh, yeah, everywhere we possibly can use DRA across the country, we're using on every one of our pipelines.
You already are. Okay. Thank you. Would it be possible to get your current estimate of how much more you're expecting to make in crude marketing this year than last, after you account for the hedges that you have in place for the rest of the year?
Me do it. Talking about hedges, this is Mackie again. Tom may add to it, as we've mentioned, we have hedged more heavily in the fourth quarter and first quarter of next year, it falls off pretty significantly on our hedges throughout the remainder of 2019.
Yeah. Listen, I will add a little bit to that. As you all know, we don't really give guidance. Of course, we're looking at coming out with an S4 shortly with some projections. I just echo what Mackie just said. We've got some upside, we're not quantifying that at this time.
Okay, fair enough. Thank you. That's all for me.
Thank you. Our next question is coming from the line of Darren Horowitz with Raymond James. Please proceed with your question.
Morning, guys. Mackie, if I could, I wanted to go back to the discussion around PE3, PE4, and then that new 30-inch line that you guys are considering. How do you think about the scale of what PE4 could look like, whether or not it's 80 or 100 or maybe a little bit more? Then more specifically, when you guys think about the scale and scope of this possible joint venture 30-inch line, how does the thought process once Bayou Bridge comes into service and the ability to move barrels from Nederland East to St. James, how does the thought process shift with regard to physical barrels ending up in the East Houston Ship Channel versus Beaumont, Nederland, or even further east to St. James? Where do you want those barrels to go?
Wherever our customers want them to go. We'll let them guide us. As I mentioned, we are looking at expanding Permian Express 3, which would be Permian Express 4. You're right on. Once we do that, it'll probably be between 80,000 and 100,000 barrels. That's probably kind of the limit of the efficient capacity that we can add. Then, of course, with our 30-inch pipeline that we're moving forward with in our discussions, negotiations and feel very good about, that would add at least another million barrels. To continue on, certainly a lot of the folks we're talking to would like to go further down the stream, and we're talking to some of the producers and shippers out of West Texas that not only want to go to Nederland and East Houston, but also want to go further into St. James.
As you know, we have the ability to provide whatever piece of that service, including storage and export, that our customers are looking for, but we let them guide us.
Mackie, do you think the next step for that then would be something of significant scale with regard to export capabilities either at Lake Charles or St. James?
We certainly have seen our export capacity grow. We think it's going to continue to grow throughout the country, and we have the ability to have a pretty significant growth at Nederland, and we are certainly proceeding down that path.
Okay. Last question from me. As you guys think about the opportunity to provide the best economic net back return for your customer, it seems like barrels clearing the dock, especially given the supply push that we see makes the most sense. What's more advantageous for you, incremental capacity at Nederland or something new at Lake Charles or St. James?
New for us to acquire or build?
What makes the most economic sense? Where can you guys make the most profit and provide the best economic return to your customers?
Well, as it sits here today, Nederland, no doubt. That's one of the benefits of the 30-inch, in addition to a great project that we hope to announce one day soon. We also receive upstream and downstream benefits, Nederland certainly is a great beneficiary of that service, both for header deliveries to refineries for storage service, also for export service, which we have expanded and will continue to expand over the years to come.
I appreciate it. Thanks, Mackie.
You bet.
Thank you. The next question is coming from the line of Keith Stanley with Wolfe Research. Please proceed with your question.
Hi, good morning. After the merger close, would you plan to pay down debt with some of the retained cash flow, or should we think of retained cash flow as more likely to get allocated to growth CapEx and de-levering plans are mainly from EBITDA growth going forward?
Yeah, you bet. Keith, as you really look at the, of course, the $2.5 billion-$3 billion of retained cash flow that we've talked about in the discussions over the last week or so. What you're going to really see as much as any is you're going to see us start managing toward that four to four and a half times leverage ratio. The variables that go into that are going to be what is going to be the funding needs around all these organic projects as you look out, Adam. It's also going to be then the balance of how you look at funding these things. We're going to try to always optimize the return to the unit holders. You're going to see us kind of navigate that way.
If, let's say, for example, you end up with even more cash flow, yes, you would be using it to even de-leverage at a faster clip. I can't emphasize enough to you what an already faster clip we're going to be de-leveraging as you bring these two companies together.
Okay. Just on follow-ups on some of the other ones. Mariner, what is the capacity of the interim solution using the 12-inch line in some areas?
We really haven't shared capacities. We can look at maybe doing that in the future. The most important aspect of the question is we have sufficient capacity to handle what we've contracted.
Okay, when would you expect the full pipeline at the 275,000 a day to be completed with the remaining HDDs complete?
For Mariner 2?
Yeah, for Mariner 2.
For Mariner 2, well, for the next segment, the last segment through what we call the GRE area, we expect that to be completed by the third quarter or end of third quarter of 2019.
For Mariner 2, it would be third quarter 2019 as originally planned.
Yeah. For the next segment, the last segment of Mariner 2 will be completed in October of 2019.
Okay. All right. One last quick one. Just crude marketing. Should we think there's any lag between the time when spreads expand or compress and when you guys realize results in the crude marketing business? Is there any lag there to be mindful of?
I'm sorry, could you repeat the question?
Is there any lag between when we look at kind of the West Texas to East Texas spread on the screen from when that expands or compresses and when you would see realized margin and results? Is there a month or two lag or anything like that in the crude marketing business?
Yes, there is. For example, it's set in for what the spread will be. I believe it's almost $20 for September. It is unlike the natural gas side where the spreads, for example, between WTI and Houston are already set kind of pre in advance for the most part. For example, for the remainder of this year, I think the spread is $19 to $20 for September, October, November, and December. Any unhedged volumes, that's what the prices that we'll move it for.
Okay. Thank you.
Yeah.
Thank you. The next question is coming from the line of Michael Blum with Wells Fargo Securities. Please proceed with your question.
Thank you. Just wanted to ask another question on Mariner East 2. When that initial tranche of capacity comes on at the end of the third quarter coming up here, will those NGLs that go on that line, should we assume they're going to be exported, or are there other markets that they're going to go to?
It predominantly would be exported, certainly there's other markets for butane and propane in domestic markets.
Okay. Can you talk about just the latest on Dakota Access Pipeline, just kind of where you stand from a volume or utilization standpoint and how that's ramping, that'd be helpful. Thanks.
Yeah. As we said, we're looking at expanding it. We hope to be able to do that in the near future. In the meantime, we're averaging close in the high 400s. We've transported over 500,000, and we believe that we have the ability possibly to expand at least another 100,000 barrels as we complete our analysis. We have averaged close to 500, maybe a little bit over 500,000 a day recently.
Okay. Just to clarify from an earlier question, the full capacity on ME2, when will that be available? The ME2X will be, I think you said the end of Q3 2019.
Yeah, the next front will be by the end of the third quarter, first part of fourth quarter on Mariner 2 and 2X. The final pipeline completion will be completed about a year later in the third quarter of 2020.
Okay, great. Thank you.
Hey, Michael, we're already line packing, to let you know. We're beginning to fill the line. That kind of gives you an idea on ME2. Of course, you don't do that until you get down where you got visibility to completion, and we're doing that.
Great. Thank you.
Thank you. The next question is coming from the line of Colton Bean with Tudor, Pickering Holt. Please proceed with your question.
Morning. Just to follow up on the questions around Dakota Access this morning. You mentioned the 100,000 barrels a day of potential expansion capacity. Would a larger expansion be contingent on more southbound capacity, maybe in the form of a Capline reversal?
No, Capline reversal wouldn't have anything to do with our business out of Bakken.
Okay. ETCOP is sufficient to handle any incremental expansion or just at the Midwest Refining Complex?
ETCOP will be able to handle the volumes that we contract to transport. Some of the customers are fine stopping at Patoka, but whatever we contract, ETCOP will be able to handle it.
Got it. Thank you. I guess just on the NGL transportation side, so volumes up fairly meaningfully despite the ME1 outage. Could you update us on where you stand with the remaining capacity on Lone Star Express and West Texas Gateway there?
You bet. The NGL segment has been just phenomenal. Our teams have done such a great job ever since we bought Louis Dreyfus. Kind of similar to other areas or other segments, we are looking at our capacity, and it's concerning us in regards to one or two years. At some point in the near future, we will be looking at expanding our Lone Star pipeline capacity. Both frac and Lone Star capacity, we will be looking at that very closely to make sure that we have new loops and new pipelines built in sufficient time to meet our contractual obligations.
Perfect. I guess just the last one here, maybe tripling down on the discussion around interstate and then some of the hedging aspects there. It looks like your natural gas sales margin ticked up maybe $20 million on a Q-over-Q basis, but the year-to-date margin capture has been a little bit weaker, versus what we see on the screen for a Waha to Katy spread. Is that attributable to the hedging? I guess, should we expect any of those hedges to roll off, kind of similar to what you noted on crude oil, over the next year and a half or so?
Yeah. One thing that hit our interstate segment, we did have a couple of customers whose volumes fell off and/or, for example, CFE didn't use as much capacity as it did the quarter before. That kind of skewed the results. Yeah, any kind of hedging that we have as it falls off over the next year or two, right now the spreads are much wider than what we've hedged, if that answers your question.
Perfect. I'll leave it there. Appreciate it.
Thank you. Our next question is coming from the line of Dennis Coleman with Bank of America. Please proceed with your question.
Yes. Good morning. I wonder if I might just get a little more update on the Orbit JV. You said that there was an approval in China. Are you seeing any opportunities for expanding that or other opportunities like that?
Absolutely. We have teams working daily on not only expanding the capacity there, but also expanding Marcus Hook. In fact, a number of the customers are desiring to have both, kind of a hedge due to weather potential issues. We'd be disappointed if we're not announcing in the next year an expansion in our Satellite area of at least 150,000 barrels more. We are putting a lot of emphasis with our teams on expanding our ethane and propane exports at the Gulf Coast and Marcus Hook.
Okay, great. Switching back to the 30-inch Permian line. You talked, when you first started talking about this, about some commercial commitments. Any updates that you can share there in terms of building enough commercial commitments to make an official announcement?
Yeah, here's how I address that. There's kind of a new phenomenon in our industry, that's if you get enough guys together and find a little bit of money, you can make an announcement that you're going to build a pipeline. We're going to wait until we know we're going to build that pipeline. We're certainly hesitant to say how close we are. As was read by Tom earlier, we're very optimistic of where we stand. There's not a pipeline out there that's even more close to the value that we provide for the customers and the shippers than ours with both East Houston and Nederland. We're very excited about that project and hope, certainly before the next earnings call, to be announcing it. When we announce it, we'll be building it.
That's useful. Maybe just one more from me. I think I read the increased volumes on Panhandle and Trunkline were contracted capacity. Is that new contracts? If so, can you talk about terms and tenors there?
You bet. It's interesting because in the past, we used to worry about questions about when a contract run out, what are we going to do? Well, on most of our systems, Panhandle and Trunkline being two of them, the basis is actually wider now and more profitable as contracts roll off. We have seen the transportation value on Panhandle and on Trunkline increase over the last several quarters. We anticipate that to continue to increase, as everybody knows, as we ramp up Rover, that also adds revenue to both Panhandle and Trunkline on a backhaul basis.
Great. Anything specific on contract length or anything like that?
Well, for example, on Rover, those are all tied to Rover, those are all 10-year contracts. I believe that's 700,000 or 750,000. Typically on Panhandle and Trunkline and even TW, those are typically two to three-year extensions.
Perfect. Thanks. That's it for me.
You bet.
Thank you. The next question is coming from the line of Patrick Wang with Robert W. Baird. Please proceed with your question.
Hey, good morning, everyone, and thanks for taking my question. Just wondering if we could spend a minute on Mexico. Can you refresh us on the latest in volume trends on Trans-Pecos and Comanche Trail? Just wondering, have you started to see any of the congestion relief on the Mexico side of the border with some of the new infrastructure that recently started up there? Can you just give us a general update on your overall export volume expectations over the next year or so?
Yeah. As we've said, we're putting a lot of emphasis on export, whatever the commodity is. We expect our natural gas volumes to Mexico to increase. They've been slow in coming. I believe total systems are moving around 100,000 a day. However, with some activity out of Mexico recently on some RFPs that come out, we do expect those volumes to begin increasing the second quarter of 2019 and grow pretty significantly from there.
All right. That sounds great. Moving back to Orbit, have the tariff discussions impacted your thoughts on timing at all?
No. The uniqueness of that project is we are selling ethane at the dock to Satellite and they're handling it from there. We don't see any impact on our partnership from tariffs related to China.
All right. Excellent. Thank you. That's it for me.
Around ethane.
Thank you. Our next question is coming from the line of Sunil Sibal with Seaport Global Securities. Please proceed with your question.
Yeah. Hi, good morning, guys. Just a couple of clarifications. The leverage metrics four to four and a half x, which you mentioned previously on the call, just wanted to clarify, that's based on the agency calculation, or is that mainly your covenant calculation?
No, that's based upon the rating agency calculation.
Okay. Got it. When you think about your credit ratings longer term, you will clearly be triple B minus kind of rating post the closing of the transaction. Is there a thought process to work on further improving that versus managing the shareholder returns?
Gosh, the last part of your question, I'm not sure if I was able to hear clearly here. Could you repeat that?
Yeah, no, I was just trying to understand, is triple B minus the goal, or is it intended to improve it further versus returning capital to the equity guys?
No, listen, we feel like the investment grade, the triple B minus with a stable outlook is good. I won't deny that if we ended up with a company of this scale with strong coverage and strong leverage that we wouldn't love to see a mid triple B, kind of a Baa2 type rating.
Okay. Got it. Then one bookkeeping one for me. How much capital do you have remaining for 2018 for spending?
We've got a CapEx funding for 2018 of $4.5. We did put a range this time in, a $4.5-$4.8. Some of that is just some new projects, smaller ones that we've not talked about yet, you're probably looking at somewhere in that range. We've given that as we look at 2018.
Okay. Got it. Just last one, a little bit big picture for me. You're seeing a fair bit of asset packages in the midstream space out there, and you guys will obviously reload from a cost of equity capital perspective post the transaction closing. I was wondering if you have any thoughts on that in terms of what's available in the market and also asset transactions versus corporate M&A, how do you see appetite for that next year forward?
Just our appetite for the M&A?
Yeah
Like we said on the last call, I believe, and we believe, the market should believe that to correctly run these partnerships, you should mix the correct amount of M&A with organic growth. That's been virtually impossible for us as a result of where our equity price has been trading. We've really been out of that, and we regret that. However, I'll start with this. This is how we're going to solve your question. The first thing to solve it is we must get to the credit metrics that we've identified, and we've made commitments to do that, and we are really confident and pleased with our ability to get to the 4.5 debt to EBITDA.
Should there be an odd opportunity that would come our way that we feel like was so compelling, we would need to meet with the right agencies and get their feel for what we're thinking, why we're thinking. Let's say this asset was not only accretive, but it was also very strategic. We're not saying we might do such a thing. However, we're not seeing any bargains right now. There's not a lot of opportunities. I bet you everybody that you talk to would say the same thing. Gosh, we got investment bankers selling assets to investment bankers right now. That's dogs and cats living together kind of thing. We're just going to study it and do our jobs and hopefully resume our M&A activity in the not too distant future.
Okay, got it. Thanks, Kelcy. That's all I had.
Thank you.
Thank you. We have reached the end of our question and answer session. I'd like to pass the floor back over to Mr. Long for any additional concluding comments.
All right. Well, listen, thank you, all of you, once again. I think you can see how much excitement we have about the performance of our existing asset base, as well as all the projects that we have coming online. Of course, moving forward with the consolidation of ETE and ETP. Thank all of you once again for the support, and we definitely look forward to talking with you in the near future.
Ladies and gentlemen, this does conclude today's teleconference. Again, we thank you for your participation, and you may disconnect your lines at this time.