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Greetings, and welcome to the Energy Transfer Third Quarter 2018 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Tom Long. Thank you, you may begin.
Thank you, operator. Good morning, everyone, and welcome to the Energy Transfer Third Quarter 2018 Earnings Call, and thank you for joining us today. I'm also joined today by Kelcy Warren, Mackie McCrea and other members of the senior management team, who are here to help answer your questions after our prepared remarks. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These are based on our beliefs as well as certain assumptions and information currently available to us. I'll also refer to adjusted EBITDA 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. Finally, following the completion of the merger of ETE and ETP on October 19, we now refer to the combined partnership as Energy Transfer LP, or simply ET. I just want to start by saying that we are extremely pleased with Energy Transfer's third quarter performance. Consolidated adjusted EBITDA was up more than 30% over the third quarter of last year, and pro forma for the merger of ETE and ETP, DCF attributable to the partners of ET as adjusted increased nearly 30%. We continue to see tremendous growth in all of our major businesses, and reported record operating results in the midstream, crude, NGL and interstate segments. For Q3 2018, our adjusted EBITDA was $2.6 billion, which equates to an annualized run rate of over $10 billion. Distribution coverage for the quarter was 1.73x, which resulted in excess cash flow after distributions of nearly $600 million for the quarter. These results demonstrate the strength of our balance sheet and our ability to internally generate a large amount of equity capital, which can fund our excellent backlog of growth projects in a credit-friendly manner. Now turning to the rest of our call. I'll start today with recent developments followed by an overview of our new growth project announcements and the latest developments on our Rover, Mariner East, Permian Express and other projects. Then I'll discuss Energy Transfer's third quarter results with a brief CapEx earnings outlook and liquidity discussion. Starting with the ETE ETP merger. On October 18, 2018, ETP unitholders voted to adopt the merger agreement, providing for the merger of ETP with ETE for $27 billion in ETE common units. Based on the results, over 98% of the units have voted, voted in favor of the merger. The merger transaction closed on October 19, and the common units of the combined company, which is now simply Energy Transfer LP, began trading on the New York Stock Exchange under the ticker symbol ET. Under the terms of the transaction, ETP unitholders received 1.28 ETE common units for each ETP common unit they own. As a result, in the transaction, ET issued approximately 1.46 billion units to former ETP unitholders. With this issuance, ET's current unit count is approximately 2.6 billion common units outstanding. We are very excited to have completed the merger, creating a more simplified ownership structure and a stronger partnership going forward. Energy Transfer Operating, or ETO, as I will refer to it, is the legacy ETP and substantially all of the assets are owned by ETE were dropped into this entity in exchange for common equity in ETP, now ETO. We are very pleased to see that recently Moody's has revised the ETO credit rating from negative to stable. We expect in the near term to launch a life-time exchange whereby we will offer the legacy ETE noteholders the ability to exchange their notes for an equivalent ETO note. This exchange will allow the legacy ETE noteholders to become pari passu with the legacy ETP noteholders and will remove their structural subordination. Now looking at our growth projects. Yesterday, we announced plans to construct our seventh Lone Star fractionator as well as an expansion to our Lone Star Express Pipeline. Similar to Frac VI, which is currently under construction, Frac VII will also have a capacity of 150,000 barrels per day and is fully subscribed under long-term demand-based agreements. Frac VI is now expected to be in service in the first quarter of 2019, ahead of schedule. And Frac VII is expected to be in service in the first quarter 2020. These fracs will provide much needed capacity required to fulfill incremental demand from our customers. Since Frac V, which went into service in July of this year is already running at full capacity. Upon completion of Frac VI and VII, Lone Star will be capable of fractionating more than 900,000 barrels per day at Mont Belvieu. We will continue looking at adding more fracs in the future as demand continues to grow. In the Lone Star Express expansion, we'll provide capacity for significant transportation commitments Lone Star has secured from the customers in the Delaware and Permian basins. The 24-inch 352-mile pipeline expansion will add approximately 400,000 barrels of NGL pipeline capacity, and will extend from Lone Star's pipeline system near Wink, Texas to the Lone Star Express 30-inch pipeline south of Fort Worth, Texas. It is expected to be in service by early in the fourth quarter of 2020. In October, we launched a binding expansion open season to solicit shipper commitments for expanded transportation service on the Bakken pipeline from the Williston Basin in North Dakota to storage terminals in Patoka Illinois and Nederland, Texas. The Bakken pipeline currently has a capacity of approximately 525,000 barrels per day, and this open season is being conducted to fill expansion capacity up to 570,000 barrels per day. Recent differentials and continued basin growth highlights the need for additional take away capacity out of the basin. And the Bakken pipeline offers unique flexibility for shippers to access markets across the Midwest and the Gulf Coast. Moving on to the 30-inch Permian Gulf Coast pipeline, which we announced during the quarter, will be a joint venture project between Magellan, MPLX and Delek. The 600-mile pipeline will provide unprecedented flexibility from the Permian Basin for deliveries to both Energy Transfer's Nederland terminal, which is the largest aboveground single owner crude oil storage facility in the United States as well as Magellan's east Houston terminal, an ultimate delivery through our respective distribution systems. Additionally, it will provide shipper capacity to our storage facilities and pipeline header system at Nederland. During the third quarter, we commenced a 60-day open season to solicit binding commitments. The open season ended on Tuesday, and we have sufficient commitments to move forward. However, we intend to launch a supplemental open season to accommodate request from multiple shippers who have asked for more time to finalize TFA negotiations and to obtain their management's approval. The pipeline is expected to be in service in mid-2020. Now turning to the Rover pipeline. 100% of Rover's 3.25 Bcf per day mainline capacity has been in service since June 1, and we're currently flowing over 3 Bcf on the pipeline. As of September 1, we are collecting demand charges of 100% of the longhaul contractual commitments on Rover. On November 1, we received approval from FERC to commence service on the Sherwood and CGT laterals, the final laterals needed to complete the project. These laterals are now in service and allow us to add an additional receipt point and delivery point for natural gas production in West Virginia. Now moving on to ME2 and 2X. 100% of the mainline construction and hyrdo testing is complete. Line pack and commissioning activities on segments of ME2 are already underway, and we now expect to place ME2 in initial service this quarter. And we expect the ME2X pipeline to be in service in the third quarter of 2019. As we bring the various segments of the projects into service, they will continue to correspond with ramp ups in capacity obligations. And we will be able to fill all current and future capacity obligations. Looking now at the Orbit Joint venture, which is a joint venture with Satellite Petrochemical USA Corp. for which we will 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, and we continue to expect the export terminal to be ready for commercial service in the fourth quarter of 2020. The expansion of the 36-inch North Texas pipeline, which we jointly own with Enterprise is expected to be completed by the end of the year. Upon completion, the North Texas pipeline will provide approximately 160,000 MMBtus per day of additional capacity from West Texas for deliveries into Old Ocean natural gas pipeline, which resumed service during the second quarter. During the third quarter, the remaining capacity of the pipeline was put into service, increasing the total capacity we jointly own with Enterprise from 130,000 to 160,000 MMBtus per day. The 24-inch Old Ocean pipeline originates in Maypearl, Texas and it extends South 240 miles to Sweeny, Texas. Now moving on 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 this plant is expected to be full by the end of this year. In addition, the 200 million cubic foot per day Arrowhead II cryo plant went into service at the end of October, and we expect it to be full by the end of the first quarter of 2019. We have recently approved construction of another 200 million cubic foot per day processing plant in the Delaware Basin, and we expect to add 1 or 2 more new plants per year in the Midland and Delaware Basin over the next few years as demand remains strong. On the Red Bluff Express Pipeline, which went into service in May, we are seeing material growth in volumes and expect volumes to continue to grow until the second phase of the pipe comes online in the second half of next year. The majority of these volumes are also flowing through our Waha Oasis Header, thereby generating additional revenues downstream. In Permian Express 3, the final 50,000 barrels per day of capacity went into service in September bringing the total capacity of PE3 to 140,000 barrels per day, and it is operating at full capacity. In fact PE1, PE2 and PE3 are all operating at full capacity today. As for Bayou bridge, we are nearing completion of the construction on the 24-inch segment from Lake Charles late trials to St. James and expect commercial operations to begin by year-end. Now let's move on to the third quarter results. Today, I'll discuss Energy Transfer's results pro forma for the merger, then I will also walk you through ETO segment results for the quarter. Additional disclosure regarding quarterly results can be found in the ET press release issued yesterday or in the ETE or ETO 10-Qs, which are expected to be filed later today. Energy Transfer's consolidated adjusted EBITDA was up more than 30% to $2.6 billion compared to $1.9 billion for the third 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 the growth from our other major segments, both sequentially as well as quarter-over-quarter. On a pro forma basis for the merger, ET's DCF attributable to the partners as adjusted was $1.4 billion for the third quarter, up $296 million or nearly 30% compared to the same period last year, primarily due to the increase in adjusted EBITDA. Pro forma for the merger, coverage for the third quarter was 1.73x resulting in excess cash flow after distributions of nearly $600 million. And on the distribution, in October, ET announced a distribution of $0.305 per common unit for the third quarter or $1.22 per common unit on an annualized basis. This distribution is flat compared to the second quarter of 2018, and will be paid on November 19 to unitholders of record as of the close of business on November 8. Now let's look at our results by segment, and we'll start with the NGL and refined product segment. Adjusted EBITDA increased to $498 million compared to $439 million for the same period last year. The increase was due to record transport and frac volumes as well as increased refined products terminal volumes, partially offset by lower results from our optimization and marketing group. NGL transportation volumes on our wholly-owned and joint venture pipelines were 1.1 million barrels per day compared to 836,000 barrels per day for the same period last year, mainly due to increased volumes on our pipelines out of the Permian Basin and on the Mariner West and Mariner South pipelines. Year-over-year, average daily fractionated volumes increased to 567,000 barrels per day compared to 390,000 barrels per day last year, primarily due to the commissioning of our fifth fractionator in July of 2018 as well as increased volumes from Permian producers. Let's move to the crude oil segment. Adjusted EBITDA increased to $682 million compared to $420 million for the same period last year. The increase was primarily due to growth on our Bakken pipeline, increased throughput in the Permian on existing pipelines, an increase of $108 million, excluding unrealized gains and losses from the crude oil acquisition and marketing business related to favorable basis differentials between Midland and the Gulf Coast as well as higher ship loading and throughput fees at our Nederland terminal. Crude transportation volumes increased to 4.3 million barrels per day, an all-time high compared to approximately 3.8 million barrels per day for the same period last year, primarily due to volume growth in the Bakken and increased production from the Permian Basin. During the third quarter, volumes on our Bakken pipeline averaged 509,000 barrels per day. For the midstream, adjusted EBITDA was $434 million compared to $356 million for the third quarter 2017, primarily due to higher throughput volumes and higher NGL and crude oil prices. Gathered gas volumes also reached a record 12.8 million MMBtus per day compared to 11.1 million MMBtus per day for the same period last year. This was primarily due to increased volumes in the Permian from higher producer demand, growth on Ohio River System in the northeast as well as growth in North Texas. In our interstate segment, adjusted EBITDA was $416 million compared to $273 million for the third quarter of 2017. This increase was primarily due to additional EBITDA from the commissioning of Rover. Interstate transportation volumes were 10.2 million MMBtus per day compared to 6.1 million MMBtus per day for the same period last year due to an increase of 2.2 million MMBtus per day from bringing the Rover pipeline into service as well as higher utilization on Panhandle and Trunkline and increases from Tiger due to production increases in the Haynesville Shale. For our intrastate segment, adjusted EBITDA increased to $221 million compared to $163 million in the third quarter of last year. This was primarily due to a $55 million increase 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. We expect our intrastate business to continue benefiting from wider-basis differentials throughout most of 2019. I reported intrastate transportation volumes increased primarily due to RIGS now being treated as a consolidated subsidiary as well as more favorable market pricing in the Texas markets. As for the all other segment, adjusted EBITDA was $78 million compared to $133 million a year ago. This was largely due to a reduction in our investment in the Sunoco LP and the contribution of CDM to USAC in April of 2018. Now moving on to CapEx and our 2019 adjusted EBITDA update. For the 9 months ended September 30, 2018, Energy Transfer spent $3.3 billion in organic growth projects primarily in the NGL and refined products and midstream segments. For full year 2018, we now expect to spend approximately $4.5 billion to $4.7 billion on organic growth projects, primarily in the NGL and refined products, midstream and intrastate segments. As we move into 2019, we continue to find projects where we are anticipating very favorable returns. Like our newly announced Frac VII and Lone Star Express expansion, we expect these to fill up quickly or be full immediately upon being placed into service. Between our announced projects and other new opportunities we are seeing, we expect to spend approximately $5 billion in 2019 on organic growth projects, primarily in the NGL and refined product segment. Looking at Energy Transfer's adjusted EBITDA for 2019, we currently expect adjusted EBITDA of $10.6 billion to $10.8 billion. Looking briefly at our liquidity position as of September 30, 2018, total liquidity under our revolving credit facility was approximately $3.7 billion and our leverage ratio was 3.53x for the ETP credit facility. On October 19, 2018, the ETP 5-year credit facility was amended to increase the borrowing capacity to $5 billion. Subsequently, we terminated the legacy ETE credit facility, and as a result, we now have total borrowing capacity of $6 billion between this facility and our 364-day facility. Before we open the call up to your questions, I want to say that we are pleased to have reported another very strong quarter. Contributions from the Bakken crude oil pipeline and Rover were big components of this growth in earnings. We're also excited to have completed the merger ETE and ETP and move forward as a more streamlined organization with enhanced financial flexibility and an improved cost to capital. You were already seeing our enhanced ability to internally generate a significant amount of excess cash flow, and we're excited for the continued DCF growth, as we complete our backlog of accretive growth projects. And with leading footprints across the midstream value chain and nearly all of the major producing basins in the U.S., we are better positioned than ever to take advantage of accretive growth capital projects. With that, operator, that concludes our prepared remarks. We'll open the line up for questions.
[Operator Instructions] Our First Question is from Michael Blum from Wells Fargo Securities.
I think, my first question is more of a high level then I had a couple of more detailed follow-ups. I guess, maybe this is for Kelcy. You've got simplification done, the market was waiting for that. I guess what are your strategic priorities right now for the company? And kind of where are you focused on a go-forward basis?
Yes, Michael. Well, Tom's said a lot of it in his prepared remarks, but as you and I spoke not long ago, we really -- I want to thank Tom Long and the team for getting this done a lot faster than anybody expected, including me, and he could not have done that without working with the rating agencies and showing them a timeline by which we would achieve certain goals. As part of that, Michael, we were given somewhat of a playbook about the rating agencies of what they would like to see us do. And I will tell you what that is, they would like to see us get to a 4.5 debt to EBITDA and possibly we'd be considered to move up a notch. But also with that, we would maintain a 1.6 coverage ratio or greater. So we have a laser-focus here to get to that as soon as we can. And we think we're going to get there sooner than most people think. So that means -- that it means we're still going to grow, that doesn't mean we're not going to continue to pursue growth projects. I would tell you on growth projects, Mackie and his team are bringing in better return projects than I've ever seen in my career. It's not unusual to see a mid- to high-teen project when you're building a $30 million gathering system or $70 million cryo plant. But it's very unusual to see a few billion dollars invested in. You see those type returns on those assets too, that's very unusual. Haven't seen that in a long, long time, maybe never. So we're excited about our growth, but we're going to be very disciplined. You're going to see us get to those objectives, the kind of the -- where the rating agency has guided us, that we owe them that, they certainly work with us. And we greatly appreciate about it. And once we get to that, then you're going to see 1 or 2 things happen. You're going to see either a resumption of distribution, increases to our unitholders, which I hope is the case, or if the market doesn't suggest that's what we should be doing, then we -- you'll see us doing unit buybacks. So that's a little bit of our high-level playbook.
That's very, very helpful. I appreciate it. Two more detailed follow-ups probably for Tom. One, of the $5 billion CapEx number for 2019, how much of that is identified projects today? And can you flag any kind of like the larger projects that are in that bucket?
Yes. No, you bet. Michael. First off, they're all identified, just to be real clear on that. So if you probably to try to break it out by each of the segments, it's still the NGL, the refined product segment that's going to be more than half of it. I'd probably say 60% of that spending. And you can appreciate the projects that we've announced around the fracs. Of course you still have some on the ME2, 2X that will be continuing to spend on. So that's probably some of the biggest chunks of the NGL and refined products the line -- as well as the line. Then you probably move into the midstream segment. You heard us talk about some of the new plants we're building, et cetera. So that's probably -- and that's probably in that 20% range. I'm just kind of giving you ballpark. The crude oil, with the pipeline that we've announced, et cetera, you're probably in about that 15% range and then I'll give you kind of just everything else kind of to make out the last 5% there. So that's the way I would walk through that with you.
Great. And then last just more of a clarification question for me. The EBITDA number that you put out there for 2019, I just want to confirm, is that consolidated EBITDA or is that net to ET only?
That is consolidated -- that is consolidated EBITDA, the way we'll be reporting adjusted EBITDA.
Our next question is from Shneur Gershuni from UBS.
Just a little bit of some follow-ups on Mike's questions. For starters, you set a lot of operating record this quarter outside of the crude segment as well too. I was wondering how much operating leverage do you have on the existing assets to continue to grow the existing assets? And I was wondering if you can also talk about potential future FIDs, can DAPL be twinned and so forth? The things that you're looking at beyond the $5 billion of CapEx in terms of supporting the, I think, $10.7 billion midpoint that you put out there?
Mackie was -- Mackie, I think -- okay. I'm sorry, Mackie was in a discussion. He needs to answer this.
I am sorry, could you repeat the question?
Okay, sure. So you set a lot of operating records this past quarter outside of crude, and so I was kind trying to understand how much more operating leverage you have on the asset that are already in service today to continue driving growth, and also if you can talk about potential future FIDs of projects that are not contemplated as part of your CapEx backlog? Could DAPL be twinned or other things that you're looking at?
Okay, yes.
Mackie, you're supposed to...
Okay, yes. This is Mackie. Yes, we had such an exciting quarter and Kelcy always says my name, but our team's here that has made a lot of this happen and all the way down to our operations. But if you look at across the board, this increase in our transportation on all of our systems is incredible. For the most part, as Tom said, our crude pipelines are running at full capacity, DAPL is running at full capacity, that's why we've started an open season, we'll continue to evaluate whether we can expand even beyond that capacity in the future. We continue to look at all of our assets as we're doing on our 12-inch converting it to diesel to more fully utilize and more efficiently and profitably utilize all of our pipelines. So everything that we have with the spreads that you see in the intrastate business and the crude and NGL, we are maxing out as much as we can. We still have some capacity left. Our NGL that we're filling up as we bring on the next 2 fracs, and which still are looking at of course bringing on Mariner II and loading that up almost immediately. As far as FID on new projects, we had already announced significant projects. We, as you can imagine, to meet the demand of what's going on in Permian and Delaware, we're already looking down the road. The industry was kind of caught without enough capacity for producers. And so we're scrambling to help that situation. So we certainly will continue to look to bring on other projects to meet the demand for our customers.
Okay. And as a follow-up, Tom, you sort of put out a $5 billion CapEx number, and you also had your guidance numbers out there as well too. Where do you see leverage for the consolidated ET at the end of 2019? And are there any other levers to pull some non-strategic asset sales like USAC or -- and the SUN remains strategic as well also?
Yes, listen, we -- as you know, there's a different calculations as to how the various agencies calculate this, but as I've reported in my prepared remarks, for the credit facility, we're at 3.53. So clearly a very, very strong number. So as you look out through 2019, we are clearly exceeding any of that, let's say, the leverage targets that we had originally kind of laid out even when you go back to the last projections we put out during the merger of ETE and ETP. So by the end of '19, I'm just going to reiterate what Kelcy said there, our targets to get to 4.5, I'm not trying to guide you that we will be there by the end, but we clearly are going to look at every option like we've been doing. As to how to fund the $5 billion in a very accretive way as well as into a very credit-enhancing way. So we're going to balance that as we work through the year. And you see all the various options that we have by what we've done over the last kind of 18 months here. So that's where I would probably answer that question with you that we're going to a charge there as fast as we can to the 4.5.
Our next question is from Michael Lapides from Goldman Sachs.
One longer-term question. Just curious we've seen announcements out of Sempra, we've seen announcements today out of Cheniere, LNG related. Just curious how you're thinking about the future development of Lake Charles?
Yes, this is Kelcy. The gentleman, Tom Mason, that oversees that is actually in China, working on this very thing. We see Lake Charles moving forward. We think it's one of the better LNG opportunities to export LNG from the United States. We just need customers, and we have had a partnership with Shell. That partnership has at best stalled, I would say. Shell does not have this project up high on their to-do list, I think, but we do. So we are working as hard as we can to find markets, to find partners in Lake Charles. And we're very optimistic, we will get there some time in '19, we'll have enough to FID.
Meaning you anticipate having partners, having an EPC contractor, and obviously, having customers signed up. And would you like to have it fully contracted before you make FID? Or would you do it at a certain percentage level?
No, we'd like to have it fully contracted. And keep in mind though, the partners could be customers. So we're not ruling that out either.
Meaning similar to what we've seen at facilities like Cameron, where the customers are also the co-owners?
Correct.
Our next question is from Jean Ann Salisbury from AllianceBernstein.
Just a couple of project questions. I had a question about the new Lone Star project. Correct me if I'm wrong, but I think that you now will have two 24-inch lines going kind of across the western part of Texas, but still just the same 30 inches beyond that. So I guess, said another way, will you need to basically build across the other half of Texas to get more barrels to Mont Belvieu?
No. This is Mackie. We -- when we built the 24-inch and tied into 30-inch, we kind of look into future not only for growth out in West Texas, but also for potential growth from Oklahoma and the north. And so we overbuilt from kind of Dallas Fort Worth to Mont Belvieu and it has paid off now. Now we're saving significant dollars by just as you mentioned looping the 24-inch, doubling our capacity out of West Texas, which will meet the demands that we have already contracted and what we fill next couple of years. So really exciting project that will come on very quickly and fill up very quickly.
That's very helpful. And then kind of a similar question. Bakken crude production as you mentioned, it is kind of nearing total pipeline capacity out of the basin. I think the most of DAPL is 30 inches, which I think another basins move kind of well over 600,000. So what kind of sets that constraint? And what would it take to expand a lot more than the 600,000 on DAPL -- 570,000?
Yes, this is Mackie, again. Clearly, there is a lot of things we can do -- we can add pumps. The one limitation that we have is we tied DAPL into ETCO. So moving all the way down to the coast and Nederland, we do have a lower MAOP on that -- the system that we converted from natural gas to oil. So that's really one of the bigger restrictions of why we can't move significantly more volume. But as I mentioned, we'll continue to evaluate on a continual basis of adding pumps and moving more volumes as the volumes grow up there. As far as looping that project, they're probably at some point in the future, will we need to be another project. We're looking not necessarily looping DAPL, but out of the northwest areas of the United States, some needs up in there, so who knows what the future holds, but right now, we're just trying to optimize what we have.
Great, that's helpful. And then one last quick one, if I may. What are you hearing from investors about why your stock hasn't really worked since the combo?
We're hearing uncertainty. There's a lot of people and some of them already asked questions that we have a great deal of respect with, and we are all perplexed. So I don't know.
Our next question is from Colton Bean from Tudor, Pickering, Holt.
Mackie, just to circle back to the NGL side of things, it looks like pretty strong Mariner South volumes this quarter. As you look at adding 300,000 barrels of fractionation capacity by Q1 '20, what are your thoughts on downstream markets for the propane? And can Mariner be expanded to handle those LPG export volumes?
Absolutely. One of the -- as I mentioned earlier, we're all scrambling -- industry is scrambling for building enough frac space to meet the demand. Along with that, there's got to be a home for the product. And so one of our strategies and one of our, I guess, most important emphasized areas is expanding our export capabilities not only out of Marcus Hook, but also out of Mont Belvieu. So you can certainly see over the coming years or 2 announcements that we'll be making on expanding our capability. For example, we're -- by the second quarter of 2019, we'll be exporting natural gasoline for the first time. And we'll continue to look at finding outlets -- more liquid outlets around the world for our growing propane and butane volumes.
Got it. And just circling back to the discussion around Dakota. So you mentioned some limitations on ETCO. It seems like Plains and the other Capline partners seem to be pushing that project forward. If you were to see Capline reversing that incremental southbound capacity from Patoka, does that free up or at least offer an option to really max out Dakota access to its true [tie-in] capacity?
Well, we don't really -- regardless of what happens with Capline, we'll be maxing out the Dakota pipeline in the -- our open season that we are going through now as an example of that, we will look, as I mentioned earlier, to expanding that more. If there's an opportunity to loop that and to be able to move more barrels, we'll certainly continue to look at that. But Capline, we see it as a little bit differently. Even if it is reversed, we kind of anticipate that being much heavier sour crude that doesn't necessarily compete with the crude that's moving through DAPL. So that pipeline really doesn't concern us.
Got it. So the preference is to direct any incremental barrels to Nederland, if at all possible?
Correct.
Our next question is from Spiro Dounis from Crédit Suisse.
Just wanted to start up on the new fractionation announcements, saw a lot of announcements this quarter from you and others. But just with respect to that the next wave potentially that could be coming. How quickly do you think we should expect that to be announced just to keep up with customers? And does it ever make sense to start building maybe larger 300,000 or 400,000 a day units?
This is Mackie again. Well, the original units that were built years ago were 60,000 and then 90,000 and then 100,000 and then 120,000. We actually were the first company to build 150,000 barrels a day or building one that will bring on in January. We can't really speak for what everybody else's plans are. A lot of that's already come out in their earnings calls, but as we've said, we'll be bringing on Frac VII and unlike a lot of our projects that might take a month or 2 to tier up. Frac VII be full the day we bring it on, we'll be bringing volumes out of storage, and then also new volumes on into that fracs. So as you can imagine with all that said, we're certainly looking down the road at the next frac and probably several more as the demands require over the coming years.
Great. And then just with respect to the Permian and the potential for, I guess, additional takeaway. I think we heard from Enterprise last week who said that they're not done building pipes there. And obviously there's a lot coming online at the end of '19. Just curious where we all stand on that outside of your current slate?
And I'm sorry, pipeline -- NGL pipeline?
Sorry. No, with respect to crude.
Crude. Yes, we try not to kind of look at what others are doing. All we're trying to do is maximize the capacity that we have and control. And then as everybody knows, we're working on our 30-inch with our partners. We completed an open season. We have a tremendous amount of interest and having -- and as we mentioned, have enough volume to move forward, but we are going to launch or have launched supplemental open season because of the request by a lot of our customers, some of them came in kind of late into the process, some a very material and from a volume perspective. And so we will continue to work on that so that we can reach a point to finally kind of size what that pipeline diameter will be.
Great. Just the last one if I could. Any color you can provide on natural gas exports to Mexico? Just curious what you're seeing there now? And if we could expect any trends to continue?
Well, it's -- we're kind of waiting on Mexico, I think is the answer to that. We several years ago brought on two 42 inches, they are relatively empty that are prepared to deliver 2.5 Bcf tomorrow, if there's enough pipeline capacity in market in Mexico. And in South Texas, we're delivering either directly through our own pipe or others. Our Bcf and that will be grown through our systems, there's new pipelines that have come on. As everybody knows, that we will continue to create a lot more capacity to head south. I think the U.S. is just waiting on Mexico to complete their projects, to complete their plants and to begin taking the volumes that they have contracted. And we see that coming in next year or so.
Our next question is from Jeremy Tonet from JPMorgan.
Just wanted to start off with Permian gas there, it seems like Transwestern got a bit of boost and some of your other pipes during the quarter. So just wondering if it's related to squeezing out incremental takeaway from the basin, can you take -- squeeze out more gas takeaway? And on the interstate side, as far as takeaway out of Permian, how do you think about the balance between kind of terming out versus kind of enjoying these wide arcs right now? How do you think about that now?
Well, okay, I'll start Transwestern, yes, we're seeing the margins widen, the spreads even from gosh from Waha up to the -- our Panhandle lateral, we've seen the dollar spreads recently. Transwestern is a little different animal though, unlike intrastates that are more market driven. We do have a tariff. So we can't charge more than the tariff, but we have seen our volumes grow, we've seen the demand, we have a tremendous amount of demand, really in both directions, leaving the Delaware Basin south down to Waha and also heading up north to Panhandle, our Panhandle lateral, and then also heading of course to California and Phoenix. So that's an asset like a lot of ours that's kind of lingered, and we've kind of struggled to create profits and now we're seeing that demand or the value of that capacity grow really across all of our systems.
That's very helpful. And Kelcy, M&A has been a big part of the ET strategy historically and granted there's a big focus on the balance sheet right now in getting leverage where you want it to be. But just wondering when you look out there right now, are there -- do you think about potential opportunities if you bolted on something that was strategic and also could help accelerate the deleveraging process? Is that something that you guys think about? Or any thoughts you could share there?
Absolutely. We -- it's been really fun since we've announced this merger to resume our M&A strategy. We were kind of blocked out of that market for a while. So we are now really churning a lot, which is our style. We look at -- Ray Davis used to call it, we kiss a lot of frogs looking for prince. But we are -- we are working it hard. I will tell you though, we're not finding any deals, and what, I mean, by that is first of all, you got to have somebody willing to transact with you and then secondly it needs to be accretive and certainly not leveraging. So we're not finding any deals right now, but that has a way of changing, that has a way of swinging one way or another. Energy Transfer is better positioned than anybody in the market, and I mean, I'll stand toe to toe with anybody who wants to have this discussion and I win. And that is we're more diversified, we've got stronger cash flows, we can survive any kind of trends, we're going to see basis swings in various commodities, and we'll hurt like everybody else, but not as much because we're so diversified. And I think when those times do occur, I think we will be able to see some good opportunities, and we'll be poised and ready.
That's helpful. And maybe just a quick last one if I could. You talked about potential evaluation of SEACOR. Security in some form and whether that be helpful to what you guys are looking to do. Is that -- do you have any updated thoughts that you could provide there?
Yes, we continue to look at that. And we've -- our Head of Tax, Brad Whitehurst, is here staring at me, with kind of a mean stare. He and I talked about a lot, we don't like paying tax, we don't think our unitholders like us to subject them to tax and, however, if we find that there's compelling reason that if we have the SEACOR currency that would help us fund our growth, help all of our unitholders, then we are certainly open to that. And we'll continually look at it. And where we stand today, we've obviously not seen that or we would have made that move.
Our next question is from Keith Stanley from Wolfe Research.
I appreciate the 2019 EBITDA outlook. The $10.6 billion to $10.8 billion that's actually even a little above the S-4 projection, which I think was $10.4 billion. What's driving that? Is it just improved volumes and market conditions here?
Yes, it is. But it's also as we just continue to look at these projects ramp up, Mackie stated it very well. A lot of credit to the entire team from the commercial team to operations team, et cetera, to be able to continue to extract more value out of all of our segments. Because when you realistically look down, this wasn't any one segment. It was all of them that contributed to this. So I guess, I would just say that's great -- it's great to see everything perform on the high side. I know when we pull those numbers together, we always try to be very realistic with our numbers. And I know at the time some of the conversations I've had, I'm not sure if everyone out there truly believe we were going to hit those numbers. But we knew when we pulled them together, there were some upside there, and it's great to see them. Everything coming to fruition here.
That's great. And then on the -- a follow-up on the CapEx. So can you say how much of the $5 billion for next year relates to projects that you have haven't announced yet and we don't know about? And then as part of that, would you rule out completely issuing equity next year given that CapEx outlook for 2019?
Well, listen, I'll definitely take the second part of the question first, if that's all right. What we're going to do and I think Kelcy teed it very, very well when we spoke through it, it's great. $600 million of retained cash flow for this quarter, I think even with that guidance that we've given you, if you look out kind of quarter-by-quarter, you'll see that number grow. Probably grow to $700 million, $750 million per quarter. That's a lot. And so as you look out, we're going to do everything we can, once again, to be the most accretive paths we can take on the funding, we will do. But also from the standpoint of the balance sheet and the leveraging, we're going to continue to manage through that. So we do not expect to be any equity, but at this time, I'm not sitting here and saying that as all these great projects, very good high-return projects keep coming in, we're going to manage that, and then we're going to manage it in a very efficient way.
I'd like to add to that. The projects that have been developed and Mackie was correct in allocating compliments to the team. It's just a remarkable group of people that can just consistently find great growth opportunities. But also everybody needs to understand sometimes we're required to spend money out of defense, and we're seeing more of that now. There's more private equity back startups that will just do anything that can do, encroach into your area and erode the Enterprise. And we're -- so we're spending some money to address that defensive strategy and that's just the nature of the business, that's what we're required to do.
Great. And on the projects we don't know about is the $5 billion just stuff you guys have already announced to the market or does it include other things?
Yes. I believe Tom mentioned that or answered that earlier. It's projects we've announced.
Our final question today is from Dennis Coleman from Bank of America Merrill Lynch.
I just have a couple of follow-ups. Timing on the second open season for the 30-inch line out of the Permian?
We've started of officially, I don't know if it's Monday, but we're already in conversations, and we'll continue to be conversations until we fill that pipeline up.
Okay. And then just on ME2, you said the line is 100% complete. So you won't be using the workaround that you've talked about?
Yes. Well, what we said is that ME2 will be in service this quarter, and we're pushing hard as everybody knows. As far as go-arounds, I'm not sure what you're referring to other than -- what? Yes, so the bottom line is what we've said is we're in service with ME2 soon, we're in service with 2X [indiscernible] by the third quarter of next year, and we couldn't be more excited to bring it on soon and also to grow our business as soon as we can.
This concludes the question-and-answer session. And I'd like to turn the floor back over to management for any closing comments.
Once again, I thank all of you for joining us today. As you can see, another record quarter for us. Very, very excited about the performance of the overall asset base, and as well as all the projects coming online. So obviously, not just this quarter, but looking out at the future, very, very excited about all of it. Thank all of you for once again for all your support, and we look forward to talking to you in the near future.
This concludes today's teleconference. You may disconnect your lines at this time, thank you for your participation.