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Edited Transcript of ETE earnings conference call or presentation 7-Nov-19 2:00pm GMT

Q3 2019 Energy Transfer LP Earnings Call

DALLAS Nov 26, 2019 (Thomson StreetEvents) -- Edited Transcript of Energy Transfer LP earnings conference call or presentation Thursday, November 7, 2019 at 2:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Bradford D. Whitehurst

Energy Transfer LP - Executive VP & Head of Tax of LE GP, LLC

* Marshall S. McCrea

Energy Transfer Operating, L.P. - Chief Commercial Officer & Director of Energy Transfer Partners, L.L.C.

* Thomas E. Long

Energy Transfer LP - Group CFO & Director of LE GP, LLC

* Thomas P. Mason

Energy Transfer LP - Executive VP, General Counsel & President – LNG of LE GP, LLC

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Conference Call Participants

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* Christine Cho

Barclays Bank PLC, Research Division - Director & Equity Research Analyst

* Colton Westbrooke Bean

Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Midstream Research

* Danilo Marcelo Juvane

BMO Capital Markets Equity Research - Analyst

* Elvira Scotto

RBC Capital Markets, Research Division - Director & Chief Analyst

* Jeremy Bryan Tonet

JP Morgan Chase & Co, Research Division - Senior Analyst

* Keith T. Stanley

Wolfe Research, LLC - Research Analyst

* Michael Jacob Blum

Wells Fargo Securities, LLC, Research Division - MD and Senior Analyst

* Michael Jay Lapides

Goldman Sachs Group Inc., Research Division - VP

* Pearce Wheless Hammond

Piper Jaffray Companies, Research Division - Research Analyst

* Shneur Z. Gershuni

UBS Investment Bank, Research Division - Executive Director in the Energy Group and Analyst

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Presentation

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Operator [1]

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Greetings, ladies and gentlemen. And welcome to Energy Transfer Third Quarter 2019 Earnings Conference Call. (Operator Instructions) It is now my pleasure to introduce your host, Mr. Tom Long. Thank you, you may begin.

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Thomas E. Long, Energy Transfer LP - Group CFO & Director of LE GP, LLC [2]

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Thank you, operator. Good morning, everyone, and welcome to the Energy Transfer Third Quarter 2019 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.

Just 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, and distribution coverage ratio, all of which are non-GAAP financial measures. You'll find a reconciliation of the non-GAAP measures on our website.

Let's start with a few highlights. As we look at the business, the third quarter was another strong quarter. Our business is doing very well as we benefit from a franchise that is fully integrated across the midstream value chain from wellhead to market. We are delivering high-return projects with strong cash flows.

On the financial side, adjusted EBITDA for the third quarter of 2019 was $2.8 billion, this was up 8% compared to the third quarter of last year. DCF attributable to the partners of ET as adjusted was $1.5 billion, which was an increase of approximately 10% over the same period last year. The NGL & Refined Products segment delivered another record quarter as a result of the ramp up of Mariner East II and record frac volumes that were driven by Frac VI coming online, and our other major businesses delivered solid performances with increased volumes across the majority of those segments.

Distribution coverage for the quarter was 1.9x, which resulted in excess cash flow after distributions of $712 million for the quarter. Year-to-date, our excess cash flow after distributions totaled approximately $2.4 billion. This excess cash flow plus the Series E preferred units issued in April has allowed us to fund year-to-date growth capital expenditures without the issuance of common equity or debt.

During the third quarter, we successfully brought on Arrowhead III processing plant online, bringing our total processing capacity in the Permian Basin to approximately 2.5 Bcf per day.

In addition, Phase 2 of our Red Bluff Express Pipeline is now complete. The J.C. Nolan Pipeline went into service in August and Permian Express 4 went into full service October 1. And in September, we announced the entry into a merger agreement with SemGroup, which I will discuss in more detail shortly.

For 2019, we have increased our adjusted EBITDA guidance range to $11 billion to $11.1 billion. We are lowering our full year 2019 growth capital guidance to approximately $4 billion.

For 2020, we expect organic growth capital expenditures to be approximately $4 billion, excluding expected expenditures related to the pending SemGroup acquisition. And we expect to provide 2020 adjusted EBITDA guidance later this year or early next year.

Now taking a closer look at the SemGroup acquisition, which we see as a strategic acquisition and a transaction that will provide immediate benefits and consistent with our plans to improve our financial position. On September 16, we announced that we entered into a definitive merger agreement to acquire SemGroup Corporation for a total consideration, including the assumption of debt, of approximately $5 billion based on the closing price of Energy Transfer common units on September 13, 2019. On October 16, we received early termination of HSR and the shareholder meeting and vote are now scheduled for December 4, 2019. We expect the transaction to close shortly after receiving the vote. This acquisition is expected to be immediately accretive to distributable cash flow for common unit and would increase our portion of fee-based cash flows from fixed fee contracts. We expect the combination of these complementary assets to provide increased connectivity for Energy Transfer's Crude Oil and NGL transportation businesses. We have a long and successful track record of integrating companies and asset teams. We are highly confident we will achieve significant synergies. Integration teams from both companies are fully engaged in the integration planning process. We expect to generate more than $170 million of annual run rate synergies, which includes financial savings of more than $50 million within the first year by utilizing Energy Transfer's lower borrowing cost.

As you know, in October, we entered into a $2 billion 3-year term loan A at a current rate of LIBOR plus 100. The proceeds will effectively be used to call all of the SemGroup's outstanding high-yield notes and the $600 million term loan B at the Houston Fuel Oil Terminal Company, or HFOTCO as they call it. Also, we expect operating cost savings of $40 million from the elimination of duplicative public company costs and increased efficiencies. And we also expect $80 million of commercial and operational synergies to be driven by our ability to leverage Energy Transfer's infrastructure to help drive operational efficiencies and increased utilization of assets.

This acquisition will benefit from new connectivity between Nederland and HFOTCO terminals after the construction of the Ted Collins Pipeline, which we announced in conjunction with the acquisition. This pipeline will improve our ability to fully utilize the HFOTCO docks by providing access to significant crude oil supplies received at our Nederland terminal much of which is delivered from our Permian Express and Bakken pipeline systems. And we will also replace large cost with new pipeline revenue.

Having pipeline access to the DJ Basin, a larger Cushing presence and expanded presence at St. James as well as access to Houston Ship Channel docks expands our connectivity, increases our reach and is expected to generate opportunities for other aspects of our portfolio as well.

Looking more closely at the Ted Collins Pipeline, this approximately 75-mile crude oil pipeline between the Houston Ship Channel and Nederland Texas is expected to serve as a strategic connection between 2 of the largest crude oil terminals in United States and will provide immediate access to over 1 million barrels per day of existing crude oil export capacity, with plans to expand to over 2 million barrels at these terminals. It is expected to have an initial capacity of more than 500,000 barrels per day and commercial operations are expected to begin in 2021. In conjunction with the combined companies' other oil transportation assets, this pipeline will provide Energy Transfer's customers with best-in-class access to the Houston Ship Channel, the Gulf Coast refinery complex and St. James markets. In addition, Energy Transfer's vast network of pipelines, which handles over 4 million barrels per day, will allow customers the flexibility to access its previously announced VLCC project plan from its Nederland terminal. We're advancing discussions on this project. And as this project gets closer to FID, we will provide more specifics.

Before going into a more detailed discussion around the third quarter earnings, growth CapEx and liquidity update, I want to provide an update regarding the latest developments on other growth projects.

Let's start with the Bakken pipeline capacity optimization. As we have mentioned, the Bakken pipeline received sufficient market interest during the December 2018 open season for us to move forward with plans to further optimize the system capacity. More recently, in July, we announced a binding supplemental open season to solicit additional shipper commitments for transportation service on the system. As a result of increased interest as well as the SemGroup acquisition announcement and the Ted Collins Pipeline project, we have extended and modified the current supplemental open season to include HFOTCO as a destination for shippers. The initial phase of the Bakken pipeline optimization above its current capacity of 570,000 barrels per day will be based on commitments made by shippers that we've already received as well as commitments made during the current open season. This capacity to serve the commitments received is expected to be in service in early 2021. In the meantime, and upon completion of the permitting phase, we expect to provide up to approximately 30,000 barrels per day of incremental capacity by mid-2020, utilizing our current system configuration. And as Bakken volumes and customer demand continue to grow in the future, we will be in position to efficiently increase the system capacity up to 1.1 million barrels per day over time.

Now looking at PE 1, 2 and 3 pipelines, which are part of our Permian Express joint venture with ExxonMobil, it continued to operate at capacity during the third quarter. And the PE 4 expansion, which added an additional 120,000 barrels per day of capacity to our Permian Express pipeline system from Colorado City to Nederland, Texas, went into full service on October 1 and is operating at full capacity as well.

Now looking at our Mariner East system. As a reminder, we placed the initial capacity into service December 29, 2018 and volumes continued to ramp up in the third quarter of this year.

In October, we completed modifications to ME1 and Marcus Hook to enhance the reliability of the system and allow for improved flows through the facility. Consistent with the second quarter, volumes during the third quarter remained strong across the Mariner system, reaching as much as 300,000 barrels per day of NGLs through the Marcus Hook Industrial Complex.

Additionally, inbound transportation modes, including trucking and rail, remained heavily utilized during the third quarter as well. We recently completed 2 local connections for delivery for propane and ethane to new facilities including to a new power plant in Cambria County in the Western Pennsylvania and to the Sinking Spring area. We expect more connections like this to be made in future.

We have also executed an additional agreement for butane transportation with a local NGL distribution facility in Pennsylvania. International LPG arbitrage economics remained strong in the third quarter, demonstrating the strength of this terminal and efficiently reaching the best markets for our customers. Our further expansion efforts at Marcus Hook are underway and progressing nicely with increased facility capacity expected for fall 2020.

Due to the permit bar, ME2X is now expected to be completed in mid-2020. Even with the delayed in-service date, we will still be able to meet our contractual commitments. The next tranche of volume ramp-ups on the Mariner East system are expected to occur in the spring, coinciding with the start-up of the Northeast NGL season, which drives increased customer demand. However, because of modifications we've recently completed, we do expect to ramp up additional ethane volumes this winter.

Looking at the Lone Star assets. As a reminder, the 150,000 barrel per day Frac VI went into service in mid-February and has been full since March. On Fracs VII and VIII, both of which will be 150,000 barrels per day, we continue to expect them to be in-service in the first quarter of 2020 and the second quarter of 2021, respectively. We anticipate both fracs will ramp up to full capacity very quickly. Upon completion of Fracs VII and VIII, our total frac capacity at Mont Belvieu will be over 1 million barrels per day.

And on our 24-inch, 352-mile Lone Star Express expansion, we'll add over 400,000 barrels per day of NGL pipeline capacity from the Permian Basin to the Lone Star Express 30-inch pipeline south of Fort Worth, Texas. We continue to expect be in service by or before our original estimate of the fourth quarter of 2020. In addition, we continue to further develop our storage capabilities at Mont Belvieu.

Now at Nederland, we are continuing to expand our interconnectivity to increase our competitive footprint and create the right asset foundation to ensure growth. As mentioned on our last call, we started loading our first barge with natural gasoline in July. We are looking to further expand our natural gasoline export operations at this facility and have already started building out storage at Nederland to allow us to achieve better rates of return on natural gasoline exports. In addition, our 200,000 barrels per day LPG expansion project in Nederland is progressing well and we'll further integrate our Mont Belvieu assets and our Nederland assets to expand our LPG export capabilities. We expect this expansion to be in-service in the third quarter of 2020.

On Orbit, which is our joint venture with Satellite Petrochemical for which we are constructing a new ethane export terminal on the U.S. Gulf coast to provide ethane to Satellite, construction continues to progress as scheduled. In China, our partners have made significant progress on the construction of their facilities, and we continue to expect all facilities in the U.S. and China to be ready for commercial service in the fourth quarter of 2020.

Our partners expect to have over 10,000 employees working on the cracker, tanks and related facilities in China by the end of 2019.

Now let's turn to our processing plants in West Texas. Our 200 MMcf per day Arrowhead III processing plant in the Delaware Basin went into service in early July and is projected to be full by year-end. In addition, we will bring on an additional 200 MMcf per day processing plant in the Permian Basin by the end of this year and expect it to be full by mid-2020. This plan is already fully subscribed, and once in service, will bring our total processing capacity in the Permian Basin to more than 2.7 Bcf per day.

On the Red Bluff Express Pipeline, Phase 1 went into service in May 2018 and Phase 2 was completed in August of this year, ahead of schedule. We began collecting revenues on Phase 2 during the third quarter and expect revenues on the system to grow over the next couple of years as the contractual commitments step up. For the month of October, Red Bluff Express volumes averaged nearly 500,000 MMBtus per day and additional volumes came into system this month. The majority of these volumes are also flowing through our Waha Oasis Header, thereby generating additional revenues downstream.

In late September, we completed a debottlenecking project in Central Texas that consisted of looping approximately 20 miles of existing pipe with 42-inch pipeline and provided an incremental 500,000 Mcf per day of capacity to the Katy and Beaumont markets. These volumes have begun flowing as a result of this project, which is backed by fee-based commitments.

On the product side, the J.C. Nolan Diesel Pipeline has an initial capacity of 30,000 barrels per day and transports diesel from Hebert, Texas to a newly constructed terminal in Midland Texas area. This is a 50-50 joint venture agreement with Sunoco LP. The project utilizes existing ET pipelines, which were contributed to the joint venture. The pipeline and state-of-the-art terminal were fully functional in August and already meeting our expectation.

Let's go ahead and take a closer look at the third quarter results. ET's consolidated adjusted EBITDA was up 8% to $2.8 billion compared to $2.6 billion for the third quarter of 2018. This is primarily due to another record operating performance from our NGL & Refined Products segment as well as growth in intrastate and crude oil segments.

Energy Transfer's DCF attributable to the partners as adjusted was $1.5 billion for the third quarter, up approximately $135 million or 10% compared to the same period last year, primarily due to increase in adjusted EBITDA. Distribution coverage for the third quarter was 1.9x and year-to-date coverage is nearly 2x.

In October, Energy Transfer 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 2019 and will be paid on November 19 to unitholders of record as of the close of business on November 5.

Now turning to the results by segment, and we'll start with the NGL & Refined Products segment, which had another record quarter. Adjusted EBITDA increased 34% to $667 million compared to $498 million for the same period last year. The increase was due to a record transport in frac volumes as well as increased terminal throughput.

NGL transportation volumes on our wholly owned and joint venture pipelines were 1.3 million barrels per day compared to 1.1 million barrels per day for the same period last year. The increase was mainly due to higher volumes on our Northeast assets due to start-up of ME2 pipeline in the fourth quarter of 2018 as well as increased volumes on our pipelines out of the Permian Basin in North Texas regions.

Third quarter average daily fractionated volumes increased to 713,000 barrels per day compared to 567,000 barrels per day last year, primarily due to the commissioning of our sixth fractionator at Mont Belvieu, which came online February of 2019.

Looking at our Crude Oil segment. Adjusted EBITDA increased to $700 million compared to $682 million for the same period last year. The increase was primarily due to increased volumes across the majority of the segment partially offset by $106 million decrease primarily due to the combination of spreads and inventory valuation adjustments.

Crude Oil transportation volumes increased a record 4.7 million barrels per day compared to approximately 4.3 million barrels per day for the same period last year, primarily due to volume growth in the Bakken as well as an increase in barrels through our existing Texas pipelines.

During the third quarter, volumes on our Bakken pipeline averaged over 560,000 barrels per day.

For midstream, adjusted EBITDA was $411 million compared to $434 million for the third quarter of 2018. Higher midstream throughput volumes were offset by lower NGL and gas prices, which impacted results by $65 million.

Gathered gas volumes reached a record 14 million MMBtus per day compared to 12.8 million MMBtus per day for the same period last year. This increase was due to growth from Ohio River System in the Northeast and higher volumes in the Permian and South Texas regions.

In our Interstate segment, adjusted EBITDA was $442 million compared to $459 million for the third quarter of 2018. This was primarily due to increased reservation fees from placing Rover into service as well as increased utilization of our Transwestern and Trunkline systems, which was offset by higher ad valorem in Texas, due to placing of the final portions of Rover into service and lower adjusted EBITDA from unconsolidated affiliates.

Transportation volumes were 11.4 million MMBtus per day compared to 10.2 million MMBtus per day for the same period last year due to an increase from the Rover pipeline as well as increases on Tiger due to production growth in the Haynesville Shale and increased utilization of higher contracted capacity on Panhandle and Trunkline.

Let's look at the Intrastate segment. Adjusted EBITDA increased to $235 million compared $221 million in the third quarter of last year. This was primarily due to increased transport fees from new contracts across our Texas intrastate pipes. Reported transport volumes increased primarily due to higher utilization of our Texas pipelines.

Just taking a quick look at Sunoco and USA Compression. For our investments in SUN, adjusted EBITDA was $192 million compared to $208 million a year ago. Third quarter 2018 results includes a onetime benefit to segment margin of $25 million related to a cash settlement with a fuel supplier. Excluding this onetime benefit, the year-over-year increase in adjusted EBITDA was supported by an increase in gallons sold as well as a decrease in operating expenses.

And for our investment in USA Compression, who had another strong quarter, adjusted EBITDA was $104 million compared to $90 million a year ago, driven by an increase in demand from compression services as well as decreases in operating and SG&A expenses.

Now let's move to CapEx. For the 9 months ended September 30, 2019, Energy Transfer spent approximately $3.1 billion in organic growth projects, primarily in the NGL and refined products and midstream segments, excluding SUN and USAC CapEx. And for the full year 2019, as mentioned, we have lowered our growth CapEx forecast to approximately $4 billion. And for full year 2020, we expect to spend approximately $4 billion excluding expenditures related to the SemGroup assets, primarily in our NGL & Refined Products and midstream segments. Post 2020, the backlog of approved growth capital projects is approximately $1.5 billion. We will expect additional projects to be added to this backlog. We have raised the bar on the return profiles and will continue to be disciplined as we evaluate any incremental spend.

Looking briefly at our liquidity position. As of September 30, 2019, total available liquidity under our revolving credit facilities was approximately $3.3 billion and our leverage ratio was 3.63x for the credit facility. Currently our liquidity sits at just over 5 billion post-closing of the recently issued term loan A. Our continued strong relationships with our bank group helped provide excellent liquidity and 24 out of 25 of our existing banks participated in the recent term loan. And we continue to target a rating agency leverage ratio of 4x to 4.5x.

Before opening the call up to your questions, I just want to reiterate that we are very pleased to have delivered another solid quarter. Our core segments continue to deliver strong performances while our completed growth projects are providing incremental volumes and additional fee-based earnings to our portfolio. Our business continues to generate a significant amount of excess cash flow, which is helping fund our backlog of growth projects in a credit-friendly manner and allowing us to further organically strengthen our balance sheet.

We're excited about the addition of the SemGroup assets, which we believe will drive near and long-term value by significantly strengthening our crude oil and liquids capabilities and enhancing our connectivity and footprint in key areas, but particularly along the U.S. Gulf Coast. Our integrated portfolio of assets and our operational expertise position us well to realize the full potential of the SemGroup assets and achieve incremental value of the organic growth projects. We have a supportive management team that owns approximately 14.5% of our total outstanding units, and over the last 12 months, our CEO has invested more than $135 million to purchase approximately 9.5 million units. We remain disciplined in our approach to new capital projects, while safety and project execution continue to be among our primary focuses.

Operator, please open the line up for questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question comes from Shneur Gershuni with UBS.

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Shneur Z. Gershuni, UBS Investment Bank, Research Division - Executive Director in the Energy Group and Analyst [2]

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Just -- it was good to see the 2019 EBITDA guide moved higher for EBITDA and CapEx lower for '19 and kind of a flat 2020 CapEx as well with that. I was wondering if we can sort of expand on your CapEx program for 2020. I'm just wondering if you can, sort of, walk through your expected return profiles for the projects. And I was wondering if you can -- if you're able to sort of split the budget, the $4 billion, into a group of projects. Are any of them smaller in nature and higher-return brownfield projects? Or are all of them mostly on the longer build cycle-type projects? Any color on that would be greatly appreciated.

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Thomas E. Long, Energy Transfer LP - Group CFO & Director of LE GP, LLC [3]

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You bet. Shneur, this is Tom. I think I'll kind of start with the guidance that we talked about for '20, which is approximately $4 billion. We thought it was important to also put the $1.5 billion, which is the backlog of CapEx budgets beyond. So I think you can kind of see the nature of the projects right there, meaning that a lot of what we're working on right now with going into next year. So I'd say there's obviously a very high percentage of everything we're working on, on those that are of that shorter nature we're referring to. In other words, I'd say less than 12 months, you can see from start to finish and coming online with cash flow would be majority of all of those projects. As far as the -- go ahead, I'm sorry.

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Shneur Z. Gershuni, UBS Investment Bank, Research Division - Executive Director in the Energy Group and Analyst [4]

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I was just wondering if can you comment on the return side also.

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Thomas E. Long, Energy Transfer LP - Group CFO & Director of LE GP, LLC [5]

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As far as the returns go, well, listen, these are all -- we consider very good, high-returning projects we have. Obviously, when you look at our footprint and you can see the type of projects we have as far as the size, et cetera, I think you can see these things. Obviously, they're going to vary. But when you have the integrated portfolio like ours, you get to see returns across pretty much all of your segments as you make each one of these capital investments. So we're being very, very selective and very disciplined in how we're looking at these.

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Shneur Z. Gershuni, UBS Investment Bank, Research Division - Executive Director in the Energy Group and Analyst [6]

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All right. And as a follow-up question. Through the course of late 2018, 2019, you've put a lot of projects into service. And I was thinking about a disclosure you'd made, I think it was late 2018 that your business was roughly about 10% to 14%. I think you split it up as 5-75% and 5-7%, but with respect to exposures to spreads and NGL pricing. I was just wondering given the strength of the results in the third quarter against a backdrop of following NGL prices and spreads compressing, has the percentage of non-fee business or red bar earnings fallen relatively because of all the fee-based projects you've added? And do you an updated percentage by any chance?

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Thomas E. Long, Energy Transfer LP - Group CFO & Director of LE GP, LLC [7]

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Well, they're actually staying fairly consistent. You are right, we've always said that we are -- probably that 10% to 15% is what we say is has more variability to it. And we split that. We split that 10% to 15%, half has to do with spreads, half has to do with commodity exposure. And I guess where I'd leave you with is with these projects coming on, et cetera, they've all been good fee-based projects, et cetera, but I would still say that we're in that same range right now.

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Shneur Z. Gershuni, UBS Investment Bank, Research Division - Executive Director in the Energy Group and Analyst [8]

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Great. And just one final question, if I may. As you noted, the CapEx is going to be flat year-on-year, certainly down from the spending levels that you've been at, but leverage has been a focus of investors and largely attributed for the valuation gap that you've seen with peers. Is there a process in place to also look at pruning some assets as well? I realize you have sold assets in the past. You've also acquired some as well, too, recently. Just wondering if there's a process to actually look at pruning to make sure that you've got the highest returning-type assets -- projects or assets in your portfolio.

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Thomas E. Long, Energy Transfer LP - Group CFO & Director of LE GP, LLC [9]

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Yes, is the short answer. And you're right. We have -- I think we've got a good track record, as you've seen, with some of the assets that we monetized. And we've also monetized just portions of some of them. So we've been very diligent on that. We continue to look at that. And where it makes sense, we will continue to do those. But once again, it needs to make sense for us to do it.

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Operator [10]

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Our next question comes from the line of Jeremy Tonet with JPMorgan.

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Jeremy Bryan Tonet, JP Morgan Chase & Co, Research Division - Senior Analyst [11]

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Just wanted to start off with the 2020 CapEx a bit more as well here. I guess at our modeling, we're having a tough time building into that $4 billion number. So I was just wondering if you could kind of walk us through some of the larger building blocks there to get that. And is there any part of that, that is kind of unidentified projects that may or may not happen? And if these things don't materialize, could that capital be used for buybacks? Just trying to figure out what can get the stock going here.

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Thomas E. Long, Energy Transfer LP - Group CFO & Director of LE GP, LLC [12]

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Okay. Let's start with the first part of your question. It still remains the same as far as the allocation of those capital dollars to the NGL & Refined Products segment. And some of those can -- are things like Mariner East. Like I mentioned on the call, we actually took 2019 down substantially. But some of that is due to the permitting around Mariner East that we pushed it back to mid-next year. So you have to put that in there as a piece of it. Lone Star Express Pipeline, LPG facilities at Nederlands, of course, you've got Fracs VII and VIII, we've talked about, still have the Orbit going on. But then you've got probably 25-plus projects that are all less than $50 million. And so when you look at it, it still makes up the lion share of expenditures. We've always said it's 60% to 70% or so for 2019. And really when it carries into 2020, it's broadly 75%, 3/4 of the CapEx spend. And then rest of it is going to be kind of split between Midstream, Crude Oil. So you've got the gathering projects we've talked about, obviously some compression facilities, et cetera. But once again, you've approximately 25 projects that are less than $50 million on that front. In the Crude Oil, of course, the Bakken we talked about and the Ted Collins Pipeline we talked about. So that's the material items that make it up. Like I said, it's very consistent between the 2.

I think the second part of your question, we have been very diligent in looking at projects. Any we have seen us bring our guidance down throughout 2019, and then you -- when you really look at 2020, you'll also see that we're staying -- even with the push some of the dollars from '19 to '20, we are still approximately at $4 billion. So you can see where we would have been, had it not been for that. And we thought it was important to go ahead and disclose the 2020 and beyond as far as some of the committed projects at the $1.5 billion. So we think we are well positioned. We hear you loud and clear on the last statement that you made on that, about the unit buyback. We get it also, and I think we are taking all the steps necessary to position ourselves financially to be able to do that.

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Jeremy Bryan Tonet, JP Morgan Chase & Co, Research Division - Senior Analyst [13]

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That's helpful. And then just one more for me, if I could. It seems like in the marketplace, there has been a bit of discussion on the REIT structure as it implies potentially the midstream and PLR out there regarding that. Just wondering if you guys have analyzed that or explored the potential for any of your pipelines to kind of utilize the REIT structure. Is this something that could be of interest to you guys? Or is this something that doesn't really make sense?

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Bradford D. Whitehurst, Energy Transfer LP - Executive VP & Head of Tax of LE GP, LLC [14]

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This is Brad Whitehurst. We have, we have looked at it. It is technology that's been around. It doesn't always work as well with operators. But we continue to look at it as possibly being a tool in our toolbox.

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Operator [15]

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Our next question comes from the line of Pearce Hammond with Simmons Energy.

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Pearce Wheless Hammond, Piper Jaffray Companies, Research Division - Research Analyst [16]

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So first question is, what's the latest on the permitting on the VLCC? And how is that progressing, the VLCC offshore terminal?

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Marshall S. McCrea, Energy Transfer Operating, L.P. - Chief Commercial Officer & Director of Energy Transfer Partners, L.L.C. [17]

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Yes. This is Mackie. It's progressing on plan. We are taking a number of steps both from a regulatory and from a permitting process. At the same time, we're in negotiations on the commercial side. But right now, we're expecting everything to go well and to have it in service sometime kind of late 2022 or early 2023.

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Pearce Wheless Hammond, Piper Jaffray Companies, Research Division - Research Analyst [18]

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Great. And then my follow-up. On the -- if you can provide an update on the Orbit JV with Satellite Petrochemical? And do you see other potential opportunities similar to that, that you might be able to sign up here, especially if the tariff war with China gets resolved?

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Marshall S. McCrea, Energy Transfer Operating, L.P. - Chief Commercial Officer & Director of Energy Transfer Partners, L.L.C. [19]

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Yes. Tom mentioned in his statement, it's going extremely well on our side as far as building out our assets. It's going just as well on the Satellite side. There's every expectation that the project on both sides will be complete and ready for delivery of ethane by the fourth quarter of next year.

And answer to your second question is yes. We are in dialogue with a number of companies and a number of countries. If you focus at the largest market in the world, it's China. As we know, the tariff issue has kind of put things on hold as far as finalizing deals, but it hasn't put on hold discussions, negotiations and ongoing opportunities to expand our ethane export capability and we do expect that to happen. However, we also are chasing other ethane opportunities that we expect will provide us the opportunity to expand both at Marcus Hook and at Nederland.

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Operator [20]

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Our next question comes from the line of Michael Lapides with Goldman Sachs.

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Michael Jay Lapides, Goldman Sachs Group Inc., Research Division - VP [21]

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Actually I have a couple of them. First, can you talk about, especially on the gas and NGL side, counterparty exposure and counterparty risk, I mean, obviously, you've got a small customer on Rover who is going through restructuring of some kind. But can you talk about kind of across your bigger customers on some of your bigger either gas pipelines, processing, even maybe on the NGL side kind of what you're hearing from your counterparties, given the low price environment in NGLs? And kind of what that means in terms of kind of risk management and risk exposure for Transfer?

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Thomas E. Long, Energy Transfer LP - Group CFO & Director of LE GP, LLC [22]

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You bet. It might be helpful for me to kind of start off with a higher level look, but I will say that over 80% of our just normal credit exposure, et cetera, when you look at it, is all at large investment-grade companies. And then when you get into the rest of them, there's no single one that even rises to a 1% type level. It makes up hundreds of counterparties. So we do a very, very good job here of spreading our risk and managing our risk from a credit standpoint, et cetera. Then on top of that what we'll do is, obviously, we'll -- depending on various customers, et cetera, we will always get various security from that standpoint. And we'll also take a lot of other steps that mitigate risk, whether it's master netting agreements, et cetera. So we feel very comfortable, I think, from an overall credit exposure out there and the way that we manage that. So none of that, I guess, I would say is keeping us up at night right now. So...

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Michael Jay Lapides, Goldman Sachs Group Inc., Research Division - VP [23]

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Got it. Okay. Also, what are your producer customers large and small? I mean, we've seen some of the Permian producers bring down production or provide production guidance that have disappointed. Obviously, it's playing out with a number of the Marcellus guys as well. How are you thinking about the flow-through of that on kind of your intrastate and midstream businesses for 2020?

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Marshall S. McCrea, Energy Transfer Operating, L.P. - Chief Commercial Officer & Director of Energy Transfer Partners, L.L.C. [24]

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This is Mackie again. Whether it's the Northeast or down south we do keep hearing that -- and seeing that there are struggles in certain areas, but we're just not seeing it in our pipes. Quarter after quarter including this quarter, we are increasing our volumes on our systems. If you look at the Permian Basin, both Midland and Delaware Basins, it's such good rock, it's some of the best rock with the most prolific formations in the world. As long as oil and gas prices don't just collapse, they're going to continue drilling. We are positioned very well to take advantage of picking up production at another area, if one producer starts falling off. So we think we've built a company and kind of strategy to kind of mitigate from impacts that we might have from certain producers in certain areas. But we, as Tom mentioned, we feel really good about the mix that we have of producer-customers in our systems.

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Michael Jay Lapides, Goldman Sachs Group Inc., Research Division - VP [25]

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Got it. Much appreciated. One last thing though, any update on Lake Charles?

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Thomas P. Mason, Energy Transfer LP - Executive VP, General Counsel & President – LNG of LE GP, LLC [26]

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Yes. This is Tom Mason. We're continuing to make good progress on the project. We -- as you know, we signed a project framework agreement with Shell in the spring and set a number of milestones for progressing the project, and we're on track, things are going well. We're in the EPC bidding process right now, and we're also actively marketing. And we think our project is highly competitive. So we are pleased with the progress.

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Operator [27]

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

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Keith T. Stanley, Wolfe Research, LLC - Research Analyst [28]

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On the ME2X and going to the middle of 2020 in service, is it mainly delays in getting permits from the DEP? Or are there any changes in the scope of the project at this point?

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Marshall S. McCrea, Energy Transfer Operating, L.P. - Chief Commercial Officer & Director of Energy Transfer Partners, L.L.C. [29]

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Yes. This is Mackie again. Yes, that's primarily it. We've got all hands on deck. We're doing everything we can to accommodate what we're being asked to do. But certainly, we've got to get to a point where we get the permit limit listed -- I mean, lifted. And we're pushing to make that happen, but certainly that has made difficult to meet some of our time lines to get it to [Exxon] by the end of the year.

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Keith T. Stanley, Wolfe Research, LLC - Research Analyst [30]

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Is there anything specific that the DEP is still looking for to start giving permits again?

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Thomas P. Mason, Energy Transfer LP - Executive VP, General Counsel & President – LNG of LE GP, LLC [31]

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Yes. We're working on -- a series of documents have been submitted for the Revolution project. In fact, have another review of those documents scheduled for next Tuesday in Pennsylvania. It appears that we're getting really close to reaching an agreement and hopeful that we'll see a permit bar lifted in the reasonably near future.

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Keith T. Stanley, Wolfe Research, LLC - Research Analyst [32]

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Okay, great. And then just a clarification on the CapEx discussion. So sounds like most of the reduction in 2019, which is a pretty good sized reduction is Mariner spending getting pushed out. I guess the $4 billion for 2020, the Ted Collins Pipeline is included in that. So that's not included on the SemGroup side, that's included on the Energy Transfer side of the CapEx?

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Thomas E. Long, Energy Transfer LP - Group CFO & Director of LE GP, LLC [33]

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That is correct. That is on the Energy Transfer side of the CapEx.

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Operator [34]

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Our next question comes from the line of Christine Cho with Barclays.

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Christine Cho, Barclays Bank PLC, Research Division - Director & Equity Research Analyst [35]

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So your CapEx is $4 billion next year and 2019 dropped by $700 million at the fair point. Is it fair to say that most of the drop is tied to the ME2X play? And that non-ME2X spending is closer to $3 billion? And is there any possibility that some of that $1.5 billion that you mentioned you're evaluating can creep into 2020 CapEx as things firm up?

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Thomas E. Long, Energy Transfer LP - Group CFO & Director of LE GP, LLC [36]

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Yes. Let's say, it's about half of it of the reduction is associated with the ME2X, the first part of your question there, Christine. And really the rest of it is, everything from some efficiencies to just various projects that, once again, we continue to evaluate as to what we're doing.

Now as far as the second part of your question, I guess I would say that is there a way for some of that to creep up? I think that the way we've laid it out is the best estimate we have as we sit here right now. I don't see a high probability of that occurring. So...

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Christine Cho, Barclays Bank PLC, Research Division - Director & Equity Research Analyst [37]

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Okay. And then just moving over to the acquisition. One of the segments that don't really fit in with your asset footprint from SemGroup is SemCAMS. And I think there is several hundred million of spending that still needs to be done there next year. How do you balance on spending money on an asset that you probably ultimately will sell anyway versus just selling it sooner than -- and having the proceeds to allocate towards your own CapEx and deleveraging process?

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Marshall S. McCrea, Energy Transfer Operating, L.P. - Chief Commercial Officer & Director of Energy Transfer Partners, L.L.C. [38]

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Yes. This is Mackie again. One thing we're extremely excited about SemGroup and very anxious to close and get that started. We're not looking at Sem Canada or anywhere else to sell. What we're looking at is, how do we best deploy our capital and get the best rate of return for our unitholders. And those assets are just tremendous assets up there, in regards to the foothold they have, the competitive advantage they have. And we're very anxious and excited to work with Mr. Gosse on growing those assets out. So at this point in time, we're not looking at selling those assets. We're looking at buying those assets and building them up. It'll be a great growth -- revenue growth vehicle for our partnership.

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Christine Cho, Barclays Bank PLC, Research Division - Director & Equity Research Analyst [39]

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Okay. And then one more, if I could. The MEP that came due and was repaid. And I'm just curious, do you guys include that paydown for any of these your pipelines as growth CapEx? And do you have any debt coming due in 2020 on such assets that you would expect to have to make contribution?

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Thomas E. Long, Energy Transfer LP - Group CFO & Director of LE GP, LLC [40]

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No. First off, we don't include it in the CapEx for sure. That's all part of the liability management, if you will, piece of it. Gosh, as far as any others, I mean I know we've got -- there's really none in 2020.

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Operator [41]

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Your next question comes from the line of Danilo Juvane with BMO Capital Markets.

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Danilo Marcelo Juvane, BMO Capital Markets Equity Research - Analyst [42]

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On DAPL, I believe that you have an expansion hearing next week on the 13th. Does the timing now change, given the modified open season, to include HFOTCO?

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Marshall S. McCrea, Energy Transfer Operating, L.P. - Chief Commercial Officer & Director of Energy Transfer Partners, L.L.C. [43]

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This is Mackie. No, nothing changes. We are taking all the necessary steps from a regulatory and right-of-way standpoint to get everything in line to have the permits to build it. From an open-season standpoint, we have extended the open season on DAPL really to accommodate the opportunity to offer HFOTCO and the Houston Ship Channel market to our customers. And once again, we're extremely pleased with how this open season has gone and look forward to our expansion in 2021.

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Danilo Marcelo Juvane, BMO Capital Markets Equity Research - Analyst [44]

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My next question is for Tom. The Crude Oil segment had lower OpEx. And I think you cited some sort of an inter-segment transaction as a driver for that. Firstly, is the lower OpEx now the good run rate to use forward? And can you expound on what that inter-segment transaction was?

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Thomas E. Long, Energy Transfer LP - Group CFO & Director of LE GP, LLC [45]

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Yes. Well, let me make sure I understand your question completely. But I'll -- let's start with kind of the first part of it. So for the Crude Oil segment this quarter, I want to first say that we did have some of the operational inventory, that was approximately $30 million, $35 million. But it really was about, I think you're saying something on the OpEx, I think OpEx was really, really wasn't relevant there. Majority of the swing -- let's just say the swing from quarter-over-quarter was you had a $14 million positive last year compared to, like I said, about a $34 million negative this year. So I'd say, it's a little less than $50 million swing quarter-over-quarter. But very good run rate is what I would tell you on that. Nothing unusual in those numbers.

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Operator [46]

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Our next question comes from the line of Colton Bean with Tudor, Pickering, Holt.

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Colton Westbrooke Bean, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Midstream Research [47]

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So just to follow up on the discussion around intrastate credit risk, if you were to see some capacity turn back on pipelines like Tiger or Rover, how do you see the current market there in terms of re-letting that capacity?

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Marshall S. McCrea, Energy Transfer Operating, L.P. - Chief Commercial Officer & Director of Energy Transfer Partners, L.L.C. [48]

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This is Mackie again. What we're seeing in North Louisiana on our Tiger system is significant volume growth. Several years ago it fell below 1 Bcf, we're now flowing over 2 Bcf. Because of the size of those wells, we do see those volumes increasing. We also see that Tiger can offer the opportunity to both forward-haul and also backhaul into our intrastate network, getting in some of the premium markets in the Houston Ship Channel and the Gulf Coast. So we feel like Tiger is well positioned to compete at fairly decent rates as contracts roll off in the coming next couple, 2 or 3 years.

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Colton Westbrooke Bean, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Midstream Research [49]

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Got it. And just on Rover if you were to see some of that capacity return to you?

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Marshall S. McCrea, Energy Transfer Operating, L.P. - Chief Commercial Officer & Director of Energy Transfer Partners, L.L.C. [50]

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Well, on Rover, 3.1 Bcf is sold term. If some of that comes back to us, there is a -- well, let me restate. That system was built to flow about 3.25 Bcf a day. We now have the ability through experience of moving about 3.5 Bcf a day through it. We are, on any given day, flowing 3.2 to 3.3. Certainly everything above the 3.1 of demand charges is lower, but there's a tremendous amount of volume growing in the Northeast. Our ORS system is at record levels. So there will continue to be a need to get gas out of those areas. Where exactly rates will fall in the event some of that capacity came back to us? We don't know but we do know that -- we do believe the volumes will continue to grow. And that one of the most valuable and best assets to get gas out of there as far as netback to producers will be Rover -- or is Rover.

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Colton Westbrooke Bean, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Midstream Research [51]

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Got it. Appreciate that. And then just on Dakota Access. So one of the key Cushing to Gulf Coast Pipelines just announced an open season for additional light capacity at $1.25 a barrel. Does that change the competitive dynamic at all for DAPL versus other Bakken takeaway options that route through Cushing?

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Marshall S. McCrea, Energy Transfer Operating, L.P. - Chief Commercial Officer & Director of Energy Transfer Partners, L.L.C. [52]

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No. This is Mackie again. DAPL, if we could snap our fingers and have 400,000, 500,000 barrels a day today available, we think people would step up forward immediately. Nothing really competes with DAPL. All these new projects, when you look at the stacking of fees and where those markets are and the timing to get there, nothing really compares to a project that can deliver to the vast majority of the Mid-Continent refineries and then bring it down to the Gulf Coast getting to all the refineries in Texas and then through Bayou Bridge getting through the St. James markets. And so we're pretty pleased with our competitive advantage with DAPL.

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Operator [53]

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

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Michael Jacob Blum, Wells Fargo Securities, LLC, Research Division - MD and Senior Analyst [54]

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I think in the prepared remarks, Tom, you talked about raising the bar as -- when evaluating new CapEx projects. I wonder if you can maybe quantify that in anyway. Kind of type of returns you've historically been targeting versus how that might be changing going forward?

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Marshall S. McCrea, Energy Transfer Operating, L.P. - Chief Commercial Officer & Director of Energy Transfer Partners, L.L.C. [55]

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You bet. This is Mackie again. You go back a number of years and you look at some of our processing plants and we were targeting 12% to 13% just to be competitive. We have not looked at a deal that we can't -- in the last 12 to 18 months, we haven't looked at, for example, a processing opportunity at less than a 18% rate of return. And remember, I know you know this, Michael, but when we do that on our processing plants, which we build 1 about every 6 months out in West Texas, we don't put any of the synergistic revenues, none of the liquid revenues downstream, none of the residue revenue downstream. So it's stand-alone. So that's our bottom threshold. There are some areas where maybe we don't see as many synergies and the threshold is as high as 20%. So we are being extremely selective on where we put our capital. And we are targeting high-rate-of-return projects with synergistic benefits added to them.

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Michael Jacob Blum, Wells Fargo Securities, LLC, Research Division - MD and Senior Analyst [56]

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Great. That makes sense. And then I guess my second question and Mackie, you talked earlier about, you're not -- in spite of some weakness and slowdown in drilling that we're hearing from the E&P community, you're not really seeing it on your pipes. Have any shippers on your pipelines or producers in your G&P segment approached you for rate relief? And is that anything that you'd be open to?

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Marshall S. McCrea, Energy Transfer Operating, L.P. - Chief Commercial Officer & Director of Energy Transfer Partners, L.L.C. [57]

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Yes. It's kind of a broad question and kind of specific. But it's fair to say that in any given year whatever is happening in the industry, we may have people approach, and say, hey, can you work with us on rates here, if we can work on some other areas. So certainly we have conversations from time to time and where it is necessary to accommodate it and makes good business sense for our partnership, we're certainly looking at helping them where we can when it makes sense.

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Operator [58]

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Our final question comes from the line of Elvira Scotto with RBC Capital Markets.

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Elvira Scotto, RBC Capital Markets, Research Division - Director & Chief Analyst [59]

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A couple of quick follow-ups. On ME2X, so what's your confidence level now in hitting that mid-2020 in-service date, meaning when do you need to get the permit by to hit that date? And then in terms of meeting your volume commitments, can you just provide a little more detail as to how you're able to do that?

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Marshall S. McCrea, Energy Transfer Operating, L.P. - Chief Commercial Officer & Director of Energy Transfer Partners, L.L.C. [60]

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Yes. This is Mackie again. We're highly very confident that we'll have it in by the middle -- latest at the middle of next year. As part of our contract mix, we -- for example, Marcus Hook, we're filling up a lot of our capacity at Marcus Hook just through the other pipelines, truck and rail. So we're making a portion of our revenue today and we'll keep that pretty full as we complete 2X. But we've had no issues whatsoever of living up to the obligations we have under all of our contracts to transport barrels that are committed to us on the Mariner complex. Once we complete some expansions at our chilling and tank for propane and butane by the middle of next year, it will be perfect timing as we bring on more capacity on 2X, which we will be a huge shot in the arm for us from a revenue standpoint.

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Elvira Scotto, RBC Capital Markets, Research Division - Director & Chief Analyst [61]

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Okay, great. And then going back to the CapEx question. So for 2019, is part of the reduction in the growth CapEx decision to not move forward with certain projects because they don't meet your return threshold?

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Marshall S. McCrea, Energy Transfer Operating, L.P. - Chief Commercial Officer & Director of Energy Transfer Partners, L.L.C. [62]

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No, this is Mackie again. No, what we did was we've -- on post-2020, we explained what we've already committed to, and these are projects that Tom mentioned a while ago, are fairly quickly built compared to some other projects we've been working on and there are much higher rates of return. So anything about those projects, it needs to meet the threshold. It need to be the 18% to 20%. And it need to have synergistic benefits or at this point in time, it just doesn't make sense for us to deploy capital. Our focus right now is that we've built a lot of pipe where we feel extremely good on where we sit in the United States to be able to move different products to different areas, gas, oil and refined products, and we're focusing on completing out the projects that we're building but also maximizing the capacity through our facilities and through our pipelines to the biggest extent that we can. So yes, we'll continue to look at new projects, very accretive projects, at the same time, we're maximizing the value of we've already built.

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Elvira Scotto, RBC Capital Markets, Research Division - Director & Chief Analyst [63]

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Got it. And just the last one for me, just a follow-up on the SemCAMS question. So understanding that you see Canada or those assets as a growth opportunity, but in terms of just how they fit in with the overall Energy Transfer portfolio, I mean do you see synergistic opportunities there as well longer term?

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Marshall S. McCrea, Energy Transfer Operating, L.P. - Chief Commercial Officer & Director of Energy Transfer Partners, L.L.C. [64]

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There's nothing that just jumps out from a synergistic standpoint. But as you know, in Transfer, we're certainly looking at everything. How the liquid is getting out there? What other opportunities there are. But it's a pretty solid asset and project just stand-alone on -- as I mentioned earlier, its competitive advantage in the area, the contracts that they already have and we're pretty excited about kind of the built-in growth, revenue growth that's already there.

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Operator [65]

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Ladies and gentlemen, I'd now like to turn the floor back to Tom Long for closing comments.

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Thomas E. Long, Energy Transfer LP - Group CFO & Director of LE GP, LLC [66]

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All right. Once again, thank all of you for joining today. We really appreciate it. And as you've all seen, we're obviously, very, very excited about the performance of our existing asset base as well as all the projects that we've talked about today that are coming online. I thank all of you for your support, and we look forward to talking to you in the near future.

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Operator [67]

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Thank you. Ladies and gentlemen, this concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.

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Thomas E. Long, Energy Transfer LP - Group CFO & Director of LE GP, LLC [68]

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Thanks.