Tom Long – Group Chief Financial Officer and Principal Accounting Officer Mack McCrea – Chief Commercial Officer Matt Ramsey – President, Chief Operating Officer Tom Mason – Executive VP and General Counsel

Shneur Gershuni – UBS Jeremy Tonet – JP Morgan Jean Ann Salisbury – Bernstein Darren Horowitz – Raymond James Keith Stanley – Wolfe Research Michael Blum – Wells Fargo Securities. Colton Bean – Tudor Pickering Holt Dennis Coleman – Bank of America Patrick Wang – Robert W. Baird Sunil Sibal – Seaport Global Securities

Greetings and welcome to Energy Transfer's Second Quarter Earnings Conference Call. [Operator Instructions] 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, and welcome to Energy Transfer's Second Quarter 2018 Earnings Call. And thank you for joining us today. I'm also joined today by Kelcy Warren, Mack 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 Rover, Mariner East 2, Permian Express 3, and other growth projects. Then I will 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 will also refer to adjusted EBITDA and distributable cash flow, or DCF, both of which are non-GAAP financial measures. You will 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. Now 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 unitholders 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 as strategic M&A transactions. It also increases retaining cash to accelerate deleveraging. Following the merger we are expecting a DCF coverage ratio of 1.6 times to 1. 9 times, which equates to about $2.5 billion to $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. Now moving to our growth projects, and we will start with Rover. On May 31, we received authorization from FERC to commence service on the Supply Connector B and Full Mainline B pipeline segments on Rover. As of June 1, 100% of mainline capacity which is 3.25 Bcf per day is in service, and 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, rep 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 7, and Berger's town on February 13 and planned orSherwood and EGT by mid-August. Our Revolution processing plant is complete and we expect it to go into service once Rover has received full approval of the remaining supply laterals. Now moving on the 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 Whiteman Township. To avoid any delays in the ME2 projects 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 ME-2X also continues and 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 prudential approval for the construction of their ethane cracker in early July and 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 the existing ETP pipelines and this 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 2 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 but 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 it 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 P3 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 began in the fourth quarter of 2018. We are pleased to announce that Lone Star’s 120,000 barrels per day FRAC V were in the service in July ahead of schedule, this brings our told frac capacity at Mont Belvieu to nearly 600,000 barrels per day. As a reminder FRAC V is fully subscribed by multiple long-term fixed fee contracts, and also includes NGL product infrastructure, and a new 3 million barrel of y-grade cavern and we continue to expect the 140,000 barrels per day FRAC 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 1, 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 onetime $30 million benefit that was a result of several items, without these non-recurring items, our midstream segment saw a strong growth primarily due to higher throughput volumes, and higher NGL and crude prices. Compared to the first quarter of 2018, the 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. Now 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 bases 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 1, 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 from commercial optimization activities due to 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 intrastate 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. Intrastate 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 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 $19 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 sales 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 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 to $4.8 billion in organic growth projects, primarily in the NGL and Refined Products, Midstream and Intrastate segments. The increase is primarily due to the 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 7.58% Series D. fixed-floating-rate cumulative redeemable perpetual preferred units. Once again these securities provided an extremely cost effective meaning 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 core 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 interested 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, and as of June 30, 2018, ATP’s leverage was 3.87% per the credit facility. In July ETP announced a distribution of $0.565[ph] 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 14 to unit holders of record as of the close of business on August 6. 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 at $53 million. In July ETE announced a quarterly distribution of $0.305 per unit this equates to $1.22 per unit on an annualized basis, and will be paid on August 20, to unit holders of record as of the close of business on August 06. 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. So 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 unit holders 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.

[Operator Instructions] Our first question is coming from the line of Shneur Gershuni with UBS, please proceed with your question.

Good morning guys. I recognized that you can't say much about the simplification projections, so 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 am trying understand how are you using this legacy pipe will help the project advance and how does it address the PUC issues, and I guess the diameter is large enough and so for those, just wondering if you can give us a little bit more color on that.

Okay this Macky. We’ve secured a pretty significant volume for these projects ME1, ME2 and ME-2X. However those projects will ramp up over time so the utilization of the 12-inch more than provide the necessary capacity to move the volumes that we've contracted, and also allows us to bring ME2 online hopefully by the end of this quarter, so it's it was necessary but it has no impact whatsoever on our contract obligations.

And this is Matt, let me expand on that little bit. On ME2, obviously, the first issue with the use of the 12-inch line through there. We have, kind of repeating what we said in the earlier remarks, 99% of mainline construction is complete, the 1% that remains on mainline construction is associated with ACD's that we are completing right now. So we have 16 ACD's to complete, all those have been approved by PA DEP and they're either drilling ahead or they're in the stage where we are going back to PA DEP with when we have an return when the department approves, We don't have to have any changes approved by PA DEP going forward like that. All the of them are finished. And as Tom said in the early remarks, 80% of the line has been hydro tested. So we feel confident that we'll be finished with ME2 and service by the end of third quarter of this year.

Great. Thank you for that update. Just a couple of quick follow-ups, the ETP has just posted a record quarter and has done extremely well on the crude and on the natural gas sides as well. Obviously, the spread environment is largely contributed to that. Is 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 Matt again. I'll kind of walk through each component. On the NGL, it is really not something we look at. We are very pleased that we completed the 24-inch and 30-inch a little while back, because there not a lot of capacity, so we do that basis of the value that's transportation from West Texas to Houston going up over next 18 months. So well-positioned there, but no hedging strategies there. Around natural gas, we've been pretty disciplined on a prudent approach where we have going to have an hedge at healthy margins from our capacity. There is a considerable amount of capacity that we have not hedged and the capacity that we have brought on recently and will be bringing on buy the end of the year. So our approach is kind of two-fold on a really natural gas and oil is to secure as much as we think is necessary long-term, and also look at it 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, and light over their environment is today with a volume growth at the Permian Basin, and lack of capacity out of the Permian Basin.

Great. And one final question. Are there any updates or progress with Lake Charles on the LNG side?

It’s Tom Mason. Not really since our last quarterly, we are 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 JP Morgan. Please proceed with your question.

Good morning, congratulations on the great results. I just want to pick up on kind of – I want to share the question from a little bit different angle here. Just granted to you guys looking to kind of lock in margins, as it makes sense, over the next kind of year also. But I'm just wondering, how sustainable are these kind of margin, these results that we see in the crude oil segment, and the intrastate segment. Is there any kind of anticipation 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 I said in the last call, we certainly can't predict where gas and oil prices are going and certainly can't predict where basis is going. However, we have a team that looks at this daily, have weekly discussions on what's the capacity today, what pipeline can be completed, where are volume ramp ups headed, and then we make our decisions based on that. So as I said earlier, we have hedged in some areas where it makes sense to hedge. We have plenty of capacity and we lock in tenured deals. But it also make a lot of sense to hold a lot of the capacity of when we see a severe shortage of capacity in the NGL, and oil segments over at least the next 1.5 year to 2 years.

Got it. So I mean, it sounds like you can't predict exactly what is going to happen in 3Q et cetera, but there is no notable headwind to think that this was going to change dramatically?

Correct.

Thank you. And then just wanted to touch on some of the expansions here, I was just wondering, as far as Permian takeaway, I was curious from Permian Express 1 given how Sunrise comes online pretty soon, looks like it brings more than enough volumes into which falls there. And is there room in Permian Express 1 to pick up the volume here in of the coast? Or would it make sense to kind of expand that pipe, given how much will be coming in, when that project comes online?

I think I'll answer it a little more broadly. We are looking at every pipeline we own in our partnership, whether it's in oil service or not, to more fully utilizing, and/or to put it in the sort of that makes more sense. So certainly Mariner 1 is in that basket where we are looking at every possible way of increasing capacity out of that, that could benefit our revenues.

Got it, in Permian Express 1?

Permian Express 1, Permian Express 2 and Permian Express 3, and any of our abilities to expand those assets we are looking at it daily. And we will have expansions, hopefully announced in the near future.

Great. Thanks. And maybe you are not able to get more information this time, but in the same vein Dakota Access Pipeline, seems like there is a lot of need to expand that as well, any thoughts you could share?

You bet. This Mackie, again. I just said we are looking at everything that we own, how do we create a more capacity and hence more revenue. We have a lot of testing on that system recently. We do expect to be able to increase that capacity, we are not really for competitive reasons saying what that will be, but it's something that we are moving forward on and we will increase our capacity as much as efficiently possible to build growing barrels out of Bakken.

That’s all from me. Thanks for taking my questions.

Thank you. Our next question is coming from the line of Jean Ann Salisbury from Bernstein. Please proceed with your question.

Hi, good morning. You may have answered this in the last question, but 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?

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 expansion, we are looking at expanding Mariner 1, we looking at what we do – I'm sorry, Permian Express 1, we looking at what we can do on Permian Express 3. We'll probably have a Permian Express 2 expansion, and then we are also looking at other pipelines we possibly put into oil transportation service.

Okay. And then, those are mainly coming from drag-reducing agents like I guess?

Everywhere we possibly can use DRA across the country, we are using it every one of our pipeline.

You are already using. Okay. Thank you. And would it be possible to get your current estimate of how much more you were expecting to make and crude marketing this year than last, after you account for the hedges that you have in place for rest of the year?

Talking about hedges, this is Mackie again, Tom may add to it. But as we mentioned, we've hedged more heavily in the fourth quarter and first quarter of next year. And then it falls off pretty significantly on our hedges throughout the remainder of 2019.

And listen, I will add a little bit to that. I mean as you all know, we don't really give guidance. Of course, we are looking at coming out with an S-4 shortly with some projections. But I'll just echo what Mackie just said, we've got some upside, but we are not quantifying that at this time.

Okay, fair enough. And thank you that’s all from me.

Thank you. Our next question is coming from the line of Darren Horowitz from Raymond James. Please proceed with your question.

Good morning guys. Mackie, if I could, I wanted to go back to the discussion around PE3 and PE4, and then that new 30-inch line 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? And 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 of St. James, where do you want those barrels to go

Wherever our customers want them to go. We'll let them are guide us, but as I mentioned, we are looking at expanding Permian Express 3, which will be Permian Express 4. You're right on it, once we do that it will probably move 100,000[ph] barrels. That's probably kind of the limit of the efficient capacity we can add, and then of course with our 30-inch pipeline that we are moving board with in our discussions, negotiations and we feel very good about, that would add at least another 1 million barrels. And to community owns, certainly, a lot of folks we are talking to, would like to go further down the stream. And we are 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. So as you know, we have the ability to provide when available 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 a significant scale, with regard to export capabilities, either at Lake or St. James?

Yes, we certainly have seen our export capacity grow, with things continued to grow throughout the country and we have the ability to have a pretty significant growth at Nederland and we are serving for sitting down that path.

Okay. And then last question for me. As you guys think about the opportunity to provide the best economic netback 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, if its year-to-date, it's Nederland, no doubt. And that's one of the benefits of the 30-inch, in addition to a great product that we hope to announce one day soon. We also receive upstream and downstream benefits from Nederland certainly is a great beneficiary of that service, both for header deliveries to refineries, for storage, service and also for export service, which we have expanded and will continue to expand over the years to come.

Appreciate, thanks Mackie.

Thank you. The next question is coming from the line of Keith Stanley with Wolfe Research. Please proceed with your questions.

Hi, good morning. Quote 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 delevering plans are mainly from EBITDA growth going forward?

Yes, you bet, Keith. As you really look at the of course $2.5 billion to $3 billion of retained cash flow that we 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 4 times to 4.5 times leverage ratio. So depending – 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 at them, but it's also going to be than the balance of how you look at funding these things and we are going to try to always optimize the return to the unitholders. And so you're going to see is kind of an navigate that way. So let's say, for example, you end up with even more cash flow, yes, you would be using it to even deleverage at a faster clip. But I can't emphasize enough to what an already faster clip are going to be deleveraging as you bring these two companies together.

Okay. And then just on follow-ups on some of the other ones. So Mariner what is the capacity of the interim solution, using the 12-inch line in some areas?

We really haven't shared capacities. We may be doing that in the future, but the multipronged 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?

Yes Marine 2.

For Mariner 2 – 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 in the third quarter of 2019.

For Mariner 2, it would be third quarter of 2019 as originally planned?

Yes, for the next segment through – yes, the last segment of Mariner 2 will be completed in October of 2019.

Okay. All right. And one last quick one, just crude marketing; is there any – should we think there is 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?

So 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 we would see realized margins and results? Is there a month or two lag or anything like that in the crude marketing business?

Yes, there is. For example, we said and what the spread will be, I believe it's almost $20 for September. So it is unlike the natural gas, where the spreads, for example, between WTI and Houston are already set kind of pre-advance for the most part, and so, for example, for the remainder of this year, I think the spread is $19 to $20 for September, October, November, and December. So any unhedged volumes, that's where the prices that we are moving for.

Okay, thank you.

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 that – with those NGL 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?

Predominantly would be exported, but certainly there's other markets for butane and propane in domestic markets.

Okay. And then 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? And that would be helpful. Thanks.

Yes. As we said, we are looking at expanding it. We hope to be able to do that in the near future. In the meantime, we are averaging high-100s, we transported over 500,000 and we have the ability possibly to expand at least 100,000 barrels as we complete our analysis. But we are averaging – we have averaged close to 500,000, maybe a little bit over 500,000 a day recently.

Okay. And then just to clarify from an earlier question. The full capacity on ME2; when that will be available? And then the ME-2X will be, I think, you said at the end of Q3 2019?

Yes, the next tranche will be by the end of third quarter, first part of fourth quarter, on Mariner 2 and 2X. And then the final pipeline completion will be completed about a year later in the third quarter of 2020.

Okay, great.

And Michael, we are already impacted to let you know, we’re beginning the double line, so that kind of gives you an idea on ME2 that – of course, you don't do that until you get done, when you get visibility to completion and we are 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.

Good morning. So just a follow-up in the questions around the Dakota Access this morning. So you mentioned the 1,000 barrels a day potential expansion capacity; would a larger expansion be contingent on more southbound capacity, maybe in the form of a cap line reversal?

No. Cap line reversal wouldn't have anything to do with our business out of Bakken.

Okay. And so ed-comp [ph] is sufficient to handle any incremental expansion, or just at Midwest refining complex?

Ed-comp[ph] will be able to handle the contract – the volumes that we contract to transport. Some of the customers find stop-in at Patoka, but whatever we contract at Ed-comp [ph] we will be able to handle it.

And 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 Lou Drivis[ph] And kind of similar to the other areas or other segments, we are looking at our capacity and it's concerning us in regards to a one or two years. And so at some point in the near future, we will be working at expanding our Lone Star pipeline capacity. And so 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.

I guess just the last one here, maybe tripling down to discussion around intrastate and then some of the hedging aspects there. So 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 captures has been a little bit weaker versus what we see on the screen for Waha to Katy spreads. So 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 1.5 years, or so?

Yes. One thing that hit our intrastate segment, we did have a couple of customers whose volumes fell off and/or, for example, CFE didn't use much capacity as it did the quarter before. So that kind of skewed the results. But, any kind of hedging that we have as it falls off over the next year or two, right now the spreads are a much wider than what we've hedged, if that answers your question.

Yes, it did. I 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. And 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 markets hook. In fact, the number of customers are desiring to have both kind of hedged due to weather potential issues. So we are – we'd be disappointed if you're not announcing in the next year, an expansion of our satellite area, but at least 150,000 barrels more. But we are putting a lot of emphasis with our teams on expanding our ethane and propane exports at the Gulf coast and markets hook.

Okay, great. And then switching back to the 30-inch Permian line. You talked – when you first started talking about some commercial commitment, any updates that you can share there in terms of building enough commercial commitments to make an official announcement?

Yes, I’ll address that. There’s kind of a new phenomenon in our industry and that's if you get enough gas together and find a little bit of money, you can make an announcement that you’re building a pipeline. So we are going to wait until we know we are going to build that pipeline. So we are certainly hesitate to say how close we are, but it has, [indiscernible] earlier, we are really optimistic of where we stand. There is 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. So we are very excited about our project and hope, certainly before the next earnings call to be announcement. And we announce that we'll be building it.

Great. That’s useful. And then maybe just one more for me. I think I read that increased volumes on Panhandle and Trunkline were contracted capacity. Is that new contracts? And if so, can you talk about terms and tenders there?

You bet. It's interesting because in the past, we used to kind of worry about questions about when contracts 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 and now more profitable as contracts roll off. So we have seen the transportation value on Panhandle and on Trunkline increase over the last several quarters. We anticipate that to continue to increase. And then 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, in Rover, those are all tied to Rover. So those are all tenured contracts. I believe that's 750,000. On typically – on Panhandle and Trunkline and even TW, those are particularly two-to three-year extensions.

Perfect. Thanks. That’s it from me.

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 you could spend a minute on Mexico. Can you refresh us on the latest in volume transactions on Trans Pecos and Comanche Trail? Just wondering, have you seen – have you sort to see any congestion relief on the Mexico side of the border, with some of the new infrastructure that recently started up there? And then can you give us a general update on your overall export volume expectations over the next year or so?

Yes, as we've said, we've put a lot of emphasis on export, where the commodity is. We expect of a natural gas volumes to Mexico to increase. They have been slowing coming. About our total systems are moving in and around 100,000 a day. However, with some activity out of Mexico recently on some RFP's that come out, we do expect those volumes to begin increasing in the second quarter of 2019 and growth pretty significantly from there.

All right. That’s sounds great. And then moving back to Orbit, have your the tariff discussions impacted and your thoughts on time at all?

No. No, the uniqueness of the project is, we are selling ethane at the dock to satellite and their handling it from there. So we don't see any impact on our partnership from tariffs related to China.

All right, excellent. Thank you, that’s it from me.

Our next question is coming from the line of Sunil Sibal with Seaport Global Securities. Please proceed with your question.

Hi, good morning guys. Just a couple of clarifications. The leverage metrics four times to 4.5 times that 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. And then when you think about you rating – credit ratings longer term, you will clearly be BBB minus kind of the rating, post the closing of the transaction. Is there a thought process to kind of walk on further improving that versus kind of managing the shareholder returns?

The last part of your question, I'm not sure, if I was able to clearly hear. Could you repeat that?

Yes, I was just trying to understand, is BBB minus kind of the goal? Or is it intended to kind of improve it further versus returning capital to the equity guys?

Listen, we feel like the investment grade. It's kind of the, well, the BBB minus with a stable outlook is good. I will deny that if we ended up with our company of this scale with a strong coverage and strong leverage that we wouldn't love to see kind of the mid-BBB kind of the BAA 2 type ratings.

Okay, got it. And then one book keeping one for me. How much capital do you have remaining for 2018 for spending?

Yes. We got a CapEx funding for 2018 of 4.5 times. We did put a range of this time and of 4.5 times to 4.8 times and some of that is just some new projects, smaller ones that we've not talked about yet, about so you're probably looking at somewhere in that range. So we've given that as we look at 2018.

Okay, got it. And then just last one a little bit big picture for me. Have you seen a fair bit of facet package in the midstream space out there? And you guys will obviously kind of reload from a cost of equity capital perspective post transaction closing. I was wondering, if any thoughts on that in terms what’s available in the market and also asset transaction versus corporate M&A, how do you see appetite for that kind of next year forward?

Our appetite for the M&A.

Yes. Like I 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 aware our equity process has been trading. So we’ve really been out of that and when we regret that. However, I'll start with this. This is how we’re going to solve your question. The first thing to solve is that we must get to the credit metrics that we've identified and we made commitments to do that and we are really confident and pleased with our ability to get to the 4.5 times a debt-to-EBITDA. Should there be an odd opportunity that would come our way that we feel like it was so compelling, we would need to meet with the right gain season and get their feel for what we are thinking and why we are thinking. Let’s say this asset was not only accreted but it was also very strategic. And then we’re not saying we might do such a thing. However, we are not seeing any bargains right now. There is not a lot of opportunities and I bet you everybody that you talk to would say the same thing. We've got – guys, we've got an investment banker selling assets to investment bankers right now. I mean that’s dogs and cats living together kind of thing. So we are 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, guys. That’s all I had.

Thank you.

Thank you. We have reached the end of a question-and-answer session. So I'd like to have the floor back to Mr. Long for any additional concluding comments.

All right. Well, listen, thank you all of you once again. I think you can kind of 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. And of course, went forward with the consolidation of ETE and ETP. So I 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.