Energy Transfer LP (ET) 2017 Q3 法說會逐字稿

Greetings, and welcome to the Energy Transfer Third Quarter Earnings Call. (Operator Instructions) As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Tom Long, group CFO. Thank you, Mr. Long. You may begin.

Thank you, operator. Good morning, everyone, and welcome to Energy Transfer's Third Quarter 2017 Earnings Call, and thank you for joining us today. I'm also joined today by Kelcy Warren, Mackie McCrea, Matt Ramsey, John McReynolds 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 sale of an interest in Rover, followed by a discussion of the latest developments on our Bakken, Rover, Permian Express 3, Mariner East 2 and other growth projects. Then I'll turn our focus to a discussion of Energy Transfer Partners third quarter results, followed by a CapEx discussion, liquidity and funding update, and lastly a distribution discussion.

As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These are based on our beliefs as well as certain assumptions and information currently available to us. I'll also refer to adjusted EBITDA and distributable cash flow, or DCF, both of which are non-GAAP financial measures. You'll find a reconciliation of our non-GAAP measures on our website.

Before turning to recent developments and a growth project update, I just want to start by saying that we are pleased with Energy Transfer's very strong third quarter. ETP's adjusted EBITDA increased 25%, and DCF increased by 27% over the third 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 higher results from the midstream NGL and refined products segments.

Now turning to our most recent announcement. On October 31, we announced that we closed on our sale of a 49.9% interest in ET Rover pipeline or HoldCo to Blackstone Energy Partners. As a result of this closing, HoldCo is now owned 50.1% by Energy Transfer, and 49.9% by Blackstone Energy Partners. The agreement with Blackstone required Blackstone to contribute at closing, funds to be reimbursed, ETP for its pro rata share of the Rover construction cost incurred by ETP through the closing date, along with the payment of certain additional amounts. Immediately upon closing we used the proceeds to pay down debt, therefore reducing our leverage and to help fund growth projects. ETP now owns 32.56% of Rover, Blackstone owns 32.44% and Traverse owns 35%. Energy Transfer remains the operator of Rover, and we will continue to fully consolidate Rover results into our financials.

Moving to our growth projects, where we have several projects completed and ramping up, and others in the construction phase moving toward completion. As previously announced, our Bakken pipeline project went into commercial service under the committed transportation services agreement on June 1. The project has commitments, including shipper flexibility and walk-up for initial capacity of approximately 470,000 barrels per day and a total committed capacity of approximately 525,000 barrels per day. We're very pleased to have this project online, and our earnings are already seeing a significant increase as a result of the demand fees we're collecting. We are now delivering domestic crude production to refineries in the Midwest and along the Gulf Coast for the benefit of U.S. consumers.

Now looking at an update on Rover. Phase 1a was placed into service on August 31, 2017. And on October 9, we received approval from FERC to begin operating 3 compressor units at our mainline compressor station 1 in Carroll County, Ohio. We are pleased to say that Phase 1a of Rover is now transporting more than 1 BCF per day of natural gas from Cadiz Ohio to Defiance Ohio, the majority of which are at full tariff rate.

On October 31, FERC, along with their third-party technical experts completed their review of our recommended alternative monitoring protocol, and I'm pleased to say they approved our request. Yesterday, we also received the J.D. Hair reports from FERC for the remaining HDDs on Rover, which should allow us to resume construction on these drills in short order. Both of these developments provide us with more certainty in meeting our projected in-service dates.

For Phase 1b, drilling operations on our remaining HDD are nearly complete. We expect this phase will be in service and that we will be collecting demand fees on all of Phase 1 before the end of this year. In addition, construction of Phase 2 continues, and we feel confident the entire pipeline will be in service by the end of the first quarter of 2018.

Now moving on to Mariner East 2. We continue to make progress on the construction of this project. Mainline construction of the pipeline will be 99% in the ground and buried by the end of this year. Regarding construction activity in West Goshen, the Pennsylvania Public Utilities Commission issued an order last week that resulted in suspension of our underground drilling efforts. The focus of this order was related to a valve that was proposed to be installed in this township. We are evaluating the relocation or elimination of this valve, as well as other alternatives that we believe will allow us to move forward with this portion of the project in the near future.

Additionally, we continue to work with the Pennsylvania Department of Environmental Protection to secure approvals in order to move our remaining HDDs forward. As a result of these delays, we believe that this will push our in-service timing for ME2 to the second quarter of 2018.

On our Revolution project. Construction is scheduled to be completed in the first quarter of 2018, and we'll be waiting to go into full-service once Rover and ME2 are in service.

Now moving to West Texas. The 200 million cubic foot per day Arrowhead processing plant in Reeves County, in the Delaware Basin came online early in the third quarter. This plant meets a critical need for additional processing capacity and is ramping up to max capacity more quickly than expected. The 200 million a day Rebel 2 processing plant in Midland Basin will go into service in the second quarter of 2018. Including the Panther plant, which came online in December of last year, Rebel 2 is our third plant in the Midland Basin. We are nearing capacity in the Permian and will need Rebel 2 as soon as possible to meet growing producer demand in the region. The residue gas and NGL barrels for the Arrowhead, Panther and Rebel 2 plants will be delivered into ETP systems. Also in West Texas, our Red Bluff pipeline will run through the heart of the Delaware Basin and will connect our Red Bluff and Orla plants as well as multiple third-party plants to the Waha oasis header providing residue gas takeaway. The pipe will be 80 miles of 30 and 42-inch pipe, and will have a capacity of at least 1.4 BCF per day with guaranteed fee-based long-term commitments supporting the project. Our anchor shipper is Anadarko, and Western Gas has an option to buy into this project. The project is currently expected to cost less than $300 million and should be online in the second quarter of 2018.

On Permian Express 3, we completed a successful open season for Phase 1 and are moving forward to bring these volumes on around year end. We have the ability to expand by a minimum of 200,000 barrels per day and will launch an open season once we have the commitments to support an expansion.

Next, on Bayou Bridge. On the 30-inch segment from Nederland to Lake Charles, we transported an average of 147,000 barrels per day in the third quarter. On the 24-inch segment of Bayou Bridge, from Lake Charles to St. James, construction is expected to commence this quarter, and we now expect commercial operation to begin in the second half of 2018. Lone Star's 120,000 barrels per day FRAC V is fully subscribed by multiple long-term, fixed fee contracts. This also includes NGL product infrastructure and a new 3-million-barrel y-grade cavern. It is expected to be in

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quarter of 2018. And we're pleased to announce plans to construct our sixth fractionator at Mont Belvieu due to additional demand based contracted volumes. FRAC VI is expected to be in service in the second quarter of 2019, the majority of which is fully contracted. Next, the 400 million cubic foot per day agreement with Enable, which will allow us to begin fully utilizing idle pipeline and processing capacity in North Texas is expected to begin in the second quarter of 2018. When completed, this contract fills all unused capacity at our 700 million cubic foot per day Godley plant under a 10-year demand agreement.

Now let's turn to our third quarter results. As I mentioned, ETP had a very strong quarter. Adjusted EBITDA on a consolidated basis totaled $1.74 billion, which was up $354 million compared to the third quarter of 2016.

This increase is due to significantly higher results from the crude oil transportation and services segment as well as higher results from the midstream, NGL and refined products and intrastate segments. Third quarter results do reflect a total impact from Hurricane Harvey of $23 million, just over half of which is expected to reverse in future periods. I'll provide more details on this as I go through the individual segment results. DCF, attributable to partners, as adjusted, totaled $1.05 billion, an increase of $226 million compared to the third quarter of 2016. And this was primarily due to the increase in adjusted EBITDA.

Starting with the midstream segment. Adjusted EBITDA was $356 million compared to $314 million for the third quarter of 2016. This increase was primarily due to higher throughput volumes and higher NGL and crude prices. Gathered gas volumes totaled approximately $11 million MMBtus per day compared to $10 million MMBtus per day for the same period last year. This was primarily due to increased volumes in the Permian from the ramp-ups of Orla and Panther processing plants, growth from Ohio River System in the Northeast as well as the acquisition of the PennTex in North Louisiana. NGL production totaled 449,000 barrels per day compared to 421,000 barrels per day for the third quarter of 2016. Equity NGLs were 27,000 barrels per day for the third quarter of this year compared to 34,000 barrels per day for the same period in 2016.

During the third quarter, we did see approximately $2 million impact to midstream from Hurricane Harvey. Growth on our Ohio River system in the Northeast continues to exceed our expectations driven by greater-than-anticipated results from our anchor shippers on this pipeline in the dry Utica. We continue to see volumes fill up on our processing plants in the Permian Basin and expect to announce future processing expansions to support our volume growth from our committed shippers.

Now looking at the NGL and refined products segment. Adjusted EBITDA increased to $423 million compared to $383 million for the same period last year. The increase was due to higher volumes on our Texas NGL pipelines and our Mariner East system, increased refinery services margins and higher throughput at the Lone Star fractionators. NGL transportation volumes on our wholly-owned and joint venture pipelines were 836,000 barrels per day compared to 766,000 barrels per day for the same period last year due to increased volumes out of the Permian Basin and Louisiana. Refined products transportation volumes on our wholly-owned and joint venture pipelines were 612,000 barrels per day compared to 611,000 barrels per day for the same period last year. Year-over-year, average daily fractionated volumes increased to 390,000 barrels per day compared to 338,000 barrels per day last year due to the start-up of our fourth fractionator at Mont Belvieu, which was commissioned in October of 2016 as well as increased producer volumes.

For the third quarter, the total impact from Hurricane Harvey was approximately $7 million. The majority of this was a result of some downtime at 2 of our fractionators at Mont Belvieu. However, we were able to move the majority of the barrels into storage, so we will be able to recognize this revenue in the fourth quarter as we pull these barrels out of storage and run them through our fracs.

Now looking at the crude oil segment. Adjusted EBITDA increased to $396 million compared to $169 million for the same period last year. The increase was primarily due to placing our Bakken pipeline in service in the second quarter of this year, as well as the acquisition of a crude oil gathering system in West Texas, increased volumes on existing assets and an $18 million increase from LIFO accounting. Crude transportation volumes increased to 3.8 million barrels per day compared to approximately 2.7 million barrels per day for the same period last year, primarily due to placing the Bakken pipeline, Delaware Basin extension, Phase I of Bayou Bridge and the Permian Longview and Louisiana Access projects into service as well as the Vitol acquisition and growth on existing assets. Crude terminal volumes increased to 1.9 million barrels per day compared to 1.6 million barrels, primarily due to growth in Nederland and Fort Midland. During the third quarter, disruptions due to Hurricane Harvey resulted in a $14 million impact. This was due to $9 million reduction in crude transport as well as $5 million related to OpEx for repairs related to the storm.

Much of this shortfall in transportation fees is related to T&D contracts. So we expect to recognize these revenues over the next year.

In our Intrastate segment, adjusted EBITDA increased to $163 million compared to $133 million in the third quarter of last year. This was primarily due to higher natural gas sales from pipeline optimization activity, increased storage margin as well as growing fees related to exports to Mexico, higher results related to our commercial optimization business and higher EBITDA from unconsolidated affiliates due to placing Trans

Pecos and Comanche Trail into service. Transported Intrastate volumes increased due to higher demand for exports to Mexico as well as the addition of new pipes to our Intrastate system. We continue to expect volumes to Mexico to grow, particularly with the start-up of the Comanche Trail in January of 2017, and the start-up of Trans Pecos pipeline in March of 2017, which will result in increased demand for transport services through our existing pipeline network.

In our Interstate segment, adjusted EBITDA was $273 million compared to $278 million for the third quarter of 2016. We did see an impact from the contract restructuring on Tiger as well as lower rates on some of our pipelines due to weaker basis spreads and mild weather. These decreases were partially offset by $10 million of revenues from placing Phase 1 of Rover pipeline into service on August 31. We continued to expect earnings in this segment to pick up once the remaining sections of Rover are in service, and we are able to efficiently provide end-user customers with Marcellus and Utica gas. In addition, we will also be receiving significant revenues from our backhaul capabilities on Panhandle and Trunkline.

Moving on to All Other segment, which includes our equity method investment in limited partnership units of SUN LP, consisting of 43.5 million units, representing 43.7% of SUN's total outstanding common units along with other assets. Adjusted EBITDA was $133 million compared to $113 million a year ago, primarily due to an increase of $25 million related to unconsolidated affiliates, reflecting an increase in earnings from our investment in PES and higher earnings from our gas marketing and compression businesses, partially offset by a decrease of $9 million from our investment in Sunoco LP and a $11 million of higher transaction-related expenses.

Now moving on to a CapEx update. For the first 9 months of 2017, ETP funded approximately $4.8 billion in organic growth projects or on a net basis $3.8 billion after factoring in $1 billion of asset level debt. For full year 2017, we expect to spend approximately $4.1 billion on organic growth capital expenditure funding, net of $1 billion financed at the asset level, as well as proceeds from the partial sale of Rover in October. This virtually eliminates all of our funding needs for the fourth quarter of this year. For 2018, we expect to spend approximately $3 billion on organic growth projects. We will continue to be diligent in our evaluation of the capital markets for funding. We will fund these projects in a manner that is expected to preserve our investment grade rating. We anticipate funding the majority of the equity portion through a mix of retained cash flow from excess coverage in hybrid securities.

Taking a look at our liquidity position and funding strategy. Both the legacy ETP $3.75 billion credit facility and the legacy SXL $2.5 billion credit facility remains outstanding. In aggregate, the combined partnerships have borrowing capacity of up to $6.25 billion and total liquidity under these 2 facilities at the end of the quarter was approximately $4.1 billion.

We have launched a syndication process for a new $5 billion revolving credit facility at ETP to replace the existing legacy ETP and SXL credit facilities. Upon closing of the new facility, ETLP will contribute its debt and assets up to ETP, and we will add cross guarantees to make all legacy ETP and SXL debt pari-passu.

In September, we issued $750 million of 4% senior notes due 2027, and $1.5 billion of 5.4% senior notes due 2047. In addition, in September, we redeemed all of the outstanding $500 million of 6.5% senior notes due July 2021. And in October, we redeemed all of the outstanding $700 million of our 5.5% senior notes due April of 2023. During the third quarter, in total, ETP received net proceeds of nearly $1.2 billion from common equity issuances inclusive of the follow-on equity transaction on August 14, and ATM activity prior to August 14. As of September 30, 2017, ETP's leverage as defined by the legacy SXL credit agreement was 4.16x. This morning, ETP filed a prospectus supplement detailing a perpetual preferred equity security offering, for which we will be holding a number of marketing calls over the next few days. We have watched this market develop and feel this security provides an extremely cost-effective means of raising capital. Generally, these types of securities will receive at least 50% equity treatment from all 3 rating agencies. These types of securities provide equity credit at a lower yield than common equity and without the associated IDRs. Additionally, they are not convertible into common units.

Next, I'd like to touch on our recent distribution announcement. In October, ETP announced a distribution of $0.565 per common unit for the third quarter or $2.26 per common unit on an annualized basis. This was an increase of $0.015 compared to our second quarter 2017 distribution and will be paid on November 14 to unit holders of record as of the close of business on November 7. With the great quarter that ETP had and the contribution from our major projects coming online, we were excited to be able to maintain our distribution growth. As we evaluate the best use of this excess cash flow going forward, we will continue to review further increases on a quarter-by-quarter basis.

Now moving on to ETE, I'll begin with ETE's third quarter results followed by a liquidity and financing update. For the third quarter, ETE's distributable cash flow as adjusted totaled $271 million. ETE's coverage for the third quarter was 1.05x. In October, ETE announced a quarterly distribution of $0.295 per unit. This equates to $1.18 per unit on an annualized basis. This was an increase of $0.01 compared to our second quarter of 2017 distribution and will be paid on November 20 to unit holders of record as of the close of business on November 7. ETE continues to have a healthy liquidity position and ended the quarter with a debt-to-EBITDA ratio of 3.45x for our credit facility. As of September 30, 2017, there was $1.19 billion in outstanding borrowings under the credit facility. Therefore, at the end of the third quarter, the overall ETE stand-alone debt was $6.68 billion with a blended interest rate of approximately 5.06%.

Now, for a brief Lake Charles update. On June 28, we signed a Memorandum of Understanding with Kogas and Shell to study the feasibility of joint participation in the Lake Charles Liquefaction project. The project will utilize existing regasification facilities owned by Energy Transfer. As a brownfield project on the Louisiana Gulf Coast, Lake Charles is a highly competitive export project in terms of its advanced state of development, projected cost, and pipeline connectivity. We are very pleased with our progress and will work closely with our MOU partners to achieve final investment decisions in the near future as the market conditions continue to tighten.

Before opening the call up to your questions, I would just like to say that looking back over the first 9 months of this year, our base businesses have continued to perform very well. Bakken crude oil pipeline in Phase 1 of Rover are already contributing increased cash flows, and we have made great progress toward improving ETP's liquidity position. Our construction and engineering groups remain very focused on safely and responsibly bringing our projects into service, including the final phases of Rover as well as the Mariner East, Bayou Bridge, Enable and Permian Express projects. Once again, we had a great quarter. Our asset base remains well-positioned for growth as we continue bringing these projects online, I just want to reiterate that we do not expect to evaluate any internal restructuring transactions to occur before late 2019 at the earliest. At ETP, we remain firmly committed to our investment-grade rating, and we continue to place emphasis on maintaining a strong balance sheet by lowering our leverage, while also increasing coverage and liquidity. And at ETE, the priority remains supporting its core operating subsidiaries.

With that, operator, that concludes our prepared remarks. Please open the line up for questions.

(Operator Instructions) Our first question comes from the line of Jeremy Tonet with JPMorgan.

Seemed like there was really strong results across segments. But, I guess, we were just a little surprised with midstream declining a little bit quarter-over-quarter here. Was just wondering, if you could expand upon the drivers there, a little bit more, especially with the equity NGLs coming down Q-over-Q and if you could just refresh us as far as what you see for producer activity around the Horn and if there is any kind of more lingering hurricane impact, sounds like it's modest from what you were saying before?

Yes, Jeremy, that is a good question. I think on the last call, as you recall, we tried to call out the -- what we call the onetimes that occurred in Q2. So this is really about still a very strong Q3. But it was really more about the call out that we made with some onetime items. And they were really more of just kind of true-ups around some volumes and et cetera. But that's the reason we highlighted that in the second quarter. So, I guess, what I would say is that we're obviously very excited with the way third quarter has come out, volumes, et cetera. But it really is more of a Q2 type onetime's that occurred. As you can see, quarter-over-quarter of last year, we are up quite a bit with the start-up of all the plants that you've seen us announce over the last year.

Jeremy, this is Matthew. I would like to add one thing. Every quarter we can't really do a lot about the onetime. There's a lot of MBC payments that you know come to or not. But if you look overall, it's just a midstream growth. In South Texas, we're up 1/4 of a BCF '16, quarter-to-quarter '16 to '17. In the Northeast, we are up 35% or 800,000 a day and actually moving up B today. Our (inaudible) -- Permian Basin is up over 20%. So really our midstream volumes that of course feed into our processing and residue and everything is up and growing and looking better every quarter, especially with improving oil prices.

So you touched on a bunch of different regions there. Is pretty much every region in growth at this point? Or any other color you can provide there as far as producer activity?

Yes, other than 2 areas, North Texas is relatively flat. As you know, we will be bringing in significant volumes in the second quarter of next year to our Enable projects. We're very excited about that utilizing -- underutilized capacity both pipeline and processing plant. And then in the Midcontinent, we are down slightly. However, we're seeing more drilling, and we believe that will actually level out and start growing in future quarters with improved commodity prices. But yes, everywhere else, there is either growth or significant growth across all of our regions where we're active.

That's helpful. And just want to touch on your comments as far as distribution growth is concerned. And seems like in the marketplace, there is a growing consensus as far as a higher value ascribed to larger coverage in trying to minimize external funding to the extent possible. Just wondering if you could let us know your thoughts on how that -- kind of clear market preference plays into your calculus as for as distribution growth is concerned.

Yes, Jeremy, this is Kelcy. I think you know this, so sorry if I'm repeating myself. But first of all, we focus with the rating agencies -- the sentiment of the rating agencies. Tom Long does a fantastic job of communicating and understanding what we need to do to remain investment-grade, and I will tell you that, that governs a lot to us. In fact, we just will not risk that. So let's start with that. Then we look at what we have, we have a little bit better crystal ball than what you have. And that we know what's coming our way in terms of additional cash flow, distributable cash flow. And then as you heard us say before, we're committed to remaining above a 1 coverage ratio with both ETP and ETE going forward. And with those factors considered, we feel a responsibility and the whole industry used to feel this. It is odd to me that everybody has moved away from this, but we feel responsibility to distribute a safe amount of cash flow to our unit holders, and that's exactly what we did this quarter and we'll continue to do.

Our next question comes from the line of Brian Zarahn with Mizuho Securities.

Just following upon on the distribution policy. Given that ETP's distribution yields 13%, understanding a desire to return cash to unit holders, but does it really, given that you did have $3 billion of projects for next year, wouldn't a pause on the distribution makes some sense given where the equity is currently?

Well as you -- and Tom, I'd like for you talk about this too. We're not issuing equity and don't have plans to issue equity for the foreseeable future. So that's #1. We do think that our unit price will recover. I think at some point there's got to be some sanity to come back into the market. So with those factors we -- if we were issuing a lot of equity over the next 12 to 18 months, then we might view this differently, but we are not. And Tom, you want to talk about that?

Yes. You bet. Brian. As you know, we've been very, very diligent in how we've navigated through all the funding of these projects as we got to kind of the final phases. So we kept a balance and like Kelcy is saying here right now, we kept a balance with the agencies also. And we're excited to see this EBITDA coming up, because that's where our deleveraging is going to occur. So as you see these projects come on and the EBITDA contribution, I think, you'll see that even as we go through next year, we're standing firm. Like Kelcy is saying, no equity at least through the mid next year. And that's where -- and as I walk through the funding and some of the remarks that I previously made there, you can see that we don't have a lot of funding for the remainder of this year, virtually none. And when you look out for even next year, we feel like we're in good shape. So and I guess you also saw the announcement today, like I mentioned. So only perpetual preferreds. So we've got ways to continue to fund in a very efficient way.

And then just to confirm, you expect no common equity issuance next year?

Right now what we're saying Brian, we said through mid-next year is what we put in the release and that's what we're still sticking with. We will update if we push that further. But right, now it's what we are saying.

And then related to that, any update on discussions on chasing Mariner East 2?

Really no update as Kelcy and as we said in the past, is that any of the assess that we have -- our preference is to own them. They're accretive and even to grow them by ourselves. However, it does make a lot of sense when you can get a premium from a potential partner and more importantly, can bring a partner in to add substantial value by subscribing to the long-term fee-based commitment. So we're certainly still open-minded, and we're certainly still in discussions with different parties, both on the production side and the market side, and we'll continue to evaluate those opportunities.

Okay, then last one from me and maybe just coming back to the distribution, policy and the IDR structure and reaffirm that you don't expect any type of potential simplification for another 2 years, but the market has been very impatient given despite improvements in DCF, in EBITDA and projects gradually making their way into service? So are you considering other alternatives to change ETP's IDR structure before the end of 2019?

No.

Our next question comes from the line of Darren Horowitz with Raymond James.

Mackie, with respect to what's going on in Pennsylvania with the EPA or the PUC around ME2, what are the variables. As you guys see it around meeting that 2Q '18 in service from a timing perspective and how do you think about if that ends up slipping a little bit that could shift 2018 volume ramp on Revolution? Is it a situation where you can get that residue gas connection with Rover, but the NGL service in the Marcus Hook is going to be impacted? Or how do you see that unfolding?

Well, I guess, I'd answer that with -- right now we've got our heads down. The industry is kind of dealing with unprecedented challenges. We're certainly at the forefront of that because of all of our activity, but with Matt Ramsey and his team we're doing everything we can to work with PA DEP and to get all the HDDs completed and on time. As we have said, we do know now that we'll probably slip into the second quarter. However, we are going to do everything we can to bring it online and in service sometime in the second quarter. As far as Revolution, yes, we need Mariner and we need Rover to fully put Revolution in service and so we're pushing hard for that. As in our comments, we're highly confident that we're going to have Rover in Phase 1 into this year and Phase 2 sometime in the first quarter, and we're going to do everything we can to expedite work with the agencies and get Mariner 2 in as early in the second quarter if possibly can.

Okay. And then as a follow-up. Just thinking about dry gas coming out of West Texas. How do you guys now think about that balance between supply growth and takeaway capacity at Waha? And more importantly, what do you think the impact on Waha basis could be in light of an upsized Gulf Coast express and the direction that that's taken incremental gas?

We're probably -- it's probably well known, but we're probably more well positioned than anybody. There is not lot of capacity out of West Texas. Really the only way out other than West is through our pipe to Mexico, which we still believe will be sometime down the road before the fully ramping up. So getting volume growth out of there is going to depend on either a new project or existing capacity of which we have. So we're extremely optimistic over the next 12 to 24 months that the basis will blow out -- probably blow out materially. We're well positioned to take advantage of that. We're actually going to be feeding that with a lot of these projects that we're bringing on and ramping up with our processing plants and with our Red Bluff upstream intrastate. So we continue to be believers. The industry does. The producers do. If you look at what's happened to oil prices and everything that's going on in the Middle East, it points to nothing, but significant volume growth out of the Permian Basin and a more significant need to move those volumes out. We certainly continue to evaluate other ways to more efficiently and inexpensively move volumes out by expanding systems that we have or using systems that we have in different manner. And so we will continue to evaluate that and we do believe will play a part of that growth on the expansion out of the Waha area, but in the meantime, we're pretty excited about what's going to happen as far as basis spread and how it benefits our assets over the next couple of years.

It's Matt Ramsey. Let me add one thing ME2 for just a second. I think it's important. With regard to our progress up there, we should be by the end of the year showing about 45 to 50 days, will have 99% of our mainline pipe in the ground at ME2. So there's a lot in the paper about us, starting and stopping, and what's going on out there with the regulatory agencies. We're working closely with those guys, and most of the hold-up has come with regard to HDD drills up there. But we're working through that process. It went through a core process. So we had certain time guidelines under the order. And sometimes the PA DEP uses their full-time allotment to respond back to us, that slows us down. But as far as the mainline construction of the pipe itself, about 99% of the pipe should be in the ground by the end of the year on the schedule we have right now.

Our next question comes from the line of Michael Blum with Wells Fargo Securities.

Maybe just another couple of questions on ME2, to start. Just to clarify, so is ME2 comes in the second quarter, does that include ME2X? Or is that later?

No, ME2X, of course, we're building it as soon as we complete a spread. We're following that up with 2X, but 2X is scheduled to come online in 2019, first quarter of 2019.

Okay. And that's probably could lead into my second question, which is, can you talk about the $3 billion you're planning to spend in 2018? Kind of what are the big chunky pieces of that?

Well, Michael, I think you can probably appreciate from the projects right now that the chunky pieces of it are coming around the ME2, ME2X is making up probably the largest pieces of it. We're not going to break that down by segment at this point. But I will say that, you've also heard us talk about the FRAC today, FRAC VI. So it is the projects that we do have approved that are ongoing. And so you can probably kind of walk through segment-by-segment of where that's really coming from. So...

Okay. And then, just in the third quarter, it looks like the refined products in NGL's segment, CapEx was about $1 billion in Q3. Was that mostly ME2?

That's correct.

Our next question comes from the line of Ted Durbin with Goldman Sachs.

Appreciate the comments on the distribution and the lack of equity but, I guess, I'm wondering as you're thinking about next wave of projects relative to your cost of capital, do you feel like you're missing out on any projects that you might normally like to do, just given where the ETP yield is and the desire to not issue equity?

No not really, I mean, this is a very odd market, and I think all of our peers would agree with this. We lose out on projects routinely these days to private equity, not really to our peer group. And I think others would say that as well. So we're -- cost capital is really not influencing our loss of access to projects, but rather there's just a lot of private equity that hires management teams and they are in for the short-term, but it does matter. They are winning and we're not. So that's, Mackie, would you agree with that? I mean, I am not seeing much...

Well I will add that they're winning, but they're also winning at rates that we don't think they'll even be profitable in some areas. They're underestimating their cost, they are not experienced and some are very inexperienced teams, and it's just not an area that we're interested in getting into is just to get a deal done, to do a price under what it costs to build it.

Okay, that's helpful. And then coming back to the Mariner East. With the delays now on 2 and 2XL, how are you thinking about the returns on those projects based on the committed volumes that you have?

Once we get them in service, we couldn't be more excited about the returns. The way we talk about and the way we think we see it now out in the industry is that, Mariner needs to come online. There is a tremendous amount of barrels that are there are now and are going to be there in the future. And they're looking for a home. But we've got to get the project completed. We need to start pulling those barrels. We think Marcus Hook will be the best export and the largest in the country over the next 2 to 3 years with growth. We think it will be the premium market around the world, both in Europe and Asia, for propane, ethane and butane and also meet needs along the Eastern Gulf Coast. So we just need to get in line. And it's an accretive project today on the commitments that we have, and we think there is a tremendous amount of volume growth in volumes that will reach out to us as we bring the system online.

Great, great. And then last one from me. Tom, this perpetual preferred. What have you sort of penciled it in terms of sizing there? I'm sure it will be somewhat market dependent, but how do you think about the size of that raise?

Yes and listen -- you can probably appreciate with the filing that we've made today. That's the detail that we can put out right now. But please keep in mind, as we kind of progress through the marketing over the next couple of days, you will see more detail on that. But at this point, can't really talk about the rest of it. So...

Is it fair to say the pricing on that one. What other peers have done on that, you're looking to be roughly in line with pricing in terms of a yield basis?

Yes. And listen, I think that's fair when you really kind of look out whether it'd be a bond offering or anything else, you always try to look at kind of it appears and where are some of the other comps. Once again, that's probably as much I can say right now. But...

Our next question comes from the line of Shneur Gershuni with UBS.

I guess, first off, I kind of wanted to focus on the perpetual preferred that you guys spoke about today and I kind of wanted to understand how to think about that? Are you thinking of it is kind of the debt like portion of funding CapEx where you use internally generated cash flow as much as you can for the equity portion and we should think of this is more of the debt side? And kind of also wanted to ask about the sort of what's the driver of it as well, too. You issued $1 billion worth of equity in August, arguably more than we had thought that you had needed. Is this very rating agency driven to get you to where your consolidated leverage needs to be at? I was just trying to understand sort of the motivations and how to be thinking about this preferred?

Yes. And listen, you probably brought up several of the pros to doing these. Clearly, getting at least 50% equity credit is, obviously, a benefit. And keep in mind, as we look out, I mean, you hear Mackie, you keep hearing us talk about more projects. I mean, when you've got a fantastic commercial team like we have here, it's very important that you stay ahead of these projects, especially with this market, the way we're looking at it right now on the equity side. So we feel like this is very prudent thing to do. So I don't know that I take it to looking at it from a debt or an equity when we look at it, I think, this is as much as any. It's a very efficient cost of -- cost to capital as you look out in funding a lot of good projects. But clearly, getting the equity credit is a plus on the plus side of this. So...

Okay, fair enough. And then just continuing on the consolidated leverage theme here. I mean, you have a backdrop where earnings are accelerating at ETP, which should definitely help you out. At the same time, you have excess retained distributable cash flow at ETE. In your prepared remarks, you talked about how you've issued new notes in terms of pushing out the maturities at ETE. In the spirit of leverage reduction on a consolidated basis, what are the options that you are looking at with the excess retained cash flow at Energy Transfer equity next year? Do you look at share treasury services with ETP? Do you consider extending the waiver, so that way you can effectively transfer cash flow from ETE where it's not being spent into ETP (inaudible) trying to understand kind of the levers that you have with respect to deploying the cash -- the excess cash that will be at ETE?

Yes. Listen, I think this one is probably, I don't mean to make it quite so simple, but it really is just to continue to pay down the revolver. In other words, you're going to see any of the excess cash flow just to bring down the debt. But remember, at ETE, as these IDR subsidies roll off the leverage is going to drop significantly, the leverage metrics at ETE. So you can see what we've been laying out, all of our projections and how we've been communicating with the agencies. But I would look at as nothing more than you see it paying down the revolver.

So there is still room on the revolver at ETE to pay down?

Oh yes, yes. We are probably about $1.2 billion, $1.19 billion round on that revolver. So as you know, as part of the SUN transaction likewise we've got that debt preferred. So that's $300 million you'll see paid down, and then that still leaves you plenty of headroom to pay down on the revolver.

Okay. And then just transitioning to ME2. I know there has been a lot of, I guess, questions about why not JV it and so forth. But it would seem to me that as I look at the potential of the Northeast, that would be a project you would want to own in its own right and never share with anyone. It seems like over time the volumes will come to you almost regardless because of the lack of other options. Does it really makes sense to do a JV? Or is this something that you really should keep to yourself and earn the excess returns over time?

Yes, I will say -- by the way I agree with you, however, with one exception. And if there was a customer that could -- is very similar to what we did with the Dakota Access Pipeline, you could find better customers to bring into that than -- I'm sorry, the partners than the partners we have that they move barrels. And similarly, with Mariner East, we would only consider that type of a partnership. Your point, though, I hear your point -- your point is that if it gets built, the barrels going to come to us anyway. That's -- we're not -- I don't know, we're less tolerant of that risk, I guess, and so we are open-minded. If a party was bringing liquids, bringing value to the project, we would certainly consider that.

Okay, fair enough. And just one last cleanup question. You've got the legacy facilities out there for SXL and for, I guess, legacy ETP. Do you combine them at some point? When we do sort of clean up all the facilities?

Oh yes, absolutely. Listen, we're excited to be executing on what we said we would when we brought the 2 companies together. So the current 2 facilities, of course, as you know totaled $6.25 billion, and we are close to getting the new revolver wrapped up. It will be a $5 billion facility. And so all the debt will be pari-passu by year-end, like what we had put in place when we did this transaction. So you'll see that occur right toward the end of November and maybe December 1st. So...

Our next question comes from the line of Tom Abrams with Morgan Stanley.

I want to ask a business question on recontracting, with more people who are talking about it now and you had some impact there with Tiger in the Interstate segment. One of your peers, Boardwalk, had something at Fayetteville they did recently. And I think Midcon Express and another one that some consultants are mentioning might have some recontracting risk. So you did a lot of things to mitigate these risks? Can you just talk about them a little bit? And maybe order of magnitude, what the headwind might be over the next year?

You bet. This is Mackie. Yes, we're continually not only trying to grow the company, but also trying to retain as much value and assets and capacity that we own throughout all of our assets. Some of the contracts that are rolling off of some of our bigger pipeline projects over the next 2 or 3 years, we are addressing that. We're open-minded, as we were on Tiger to rearranging or reducing or shifting cost to help reduce our short-term on shortfalls for additional business elsewhere. We continue to evaluate that. We also continue to evaluate different purposes for some of these pipelines, and also different hydraulics on these pipelines on ploughing the most efficient and profitable direction. So it is something that, of course, we are looking ahead and concerned with in several areas. But it's not of immediate concern, and we're certainly are engaging with any producer, any shipper who is looking to shift costs and to, I guess, remove some pain short-term, but add value to our assets long-term.

All right. And then just, I don't want to ask a question so much on the distribution. But just the way I'm understanding it, depending on the size of the preferred, maybe a joint-venture, just how the regular business goes when projects actually come up, all those things adding to EBITDA, coupled with a desire to build coverage and, I think Kelcy used the word safe on the distribution means that you could keep increasing it at the current rate or you might go flat in '18. But it's something that you are just evaluating as you go. Is that a fair way to summarize all the commentary?

I think that's probably fair. In other words, I want to make sure I highlight that we do look at this every quarter when we do have discussion. But when we look it at each quarter, we're also looking out and looking at these projects. So yes, by all means, I think, that's probably a fair way of stating it. So...

Our next question comes from the line of Keith Stanley with Wolfe Research.

Just one quick clarification on Mariner East. You mentioned potentially relocating the valve outside of West Goshen or eliminating the valve. Just costs or challenges with this. And then the second quarter in service date, I'm assuming that you guys are baking in that you pursue one of those options. So you are not really depending at this point on the case being resolved at the PUC?

Well, with regard to the first question. Yes, that is an alternative not to put the valve on that side at all. So that is something that we could do. And we think there is a resolve to this issue. There is lots of questions within the city. They went and got an administrative law judge to give an adjunctive relief and then the PUC upheld that. But I think that there are number of different ways to resolve this issue, involving some land up there, and we feel very, very confident that we will have this issue resolved in a fairly short order, short time period. And then move on to meet that in-service date that we put in front you this morning.

Okay. So you are thinking you can resolve it outside of the PUC process, it seems, with the town or through relocating it?

We do. We fight through a lot of these issues and rarely does a township can win and get an adjunction against this, but we -- these are day-to-day affairs for us to work through this and this one got a little bit more publicity than most of the them but we'll resolve this, and we want to be good corporate citizens in all these townships that we go through. And we just understand sometimes, we just have to work with the regulatory authorities and get these things done. It's a different world out there right now. And our biggest delay right now on this is rolling through this process with PA DEP to get these drills done. And so if we go at the pace that we think we're going to go through here and hopefully we begin to get them to turn them around a little bit quicker, we'll make these deadlines. But it's just a little bit different world that you're operating in out there every day. We don't think West Goshen is going to any way effect our in-time on this, on this in-service date.

That concludes the Q&A for today. I would like to turn the floor back to Tom Long for closing comments.

All right. Well listen, once again, thank all of you for joining us today. And as I mentioned, we're very excited about all these projects and what we have coming online. Thank all of you for your support, and we look forward to talking to you in the future.

This does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation.