SEMG SemGroup Corporation

Filed by Energy Transfer LP

pursuant to Rule 425 under the Securities Act of 1933

Subject Company: SemGroup Corporation

Commission File No.: 001-34736

Date: November 7, 2019

TRANSCRIPT

The following is a transcript of the Energy Transfer LP (“ET”) and Energy Transfer Operating, L.P. (“ETO”) quarterly earnings conference call held at 8:00 a.m. Central time on November 7, 2019. While every effort has been made to provide an accurate transcription, there may be typographical mistakes, inaudible statements, errors, omissions or inaccuracies in the transcript. ET believes that none of these is material.

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Operator: [Operator instructions]

It is now my pleasure to introduce your host, Mr. Tom Long. Thank you. You may begin.

Thomas E. Long

Chief Financial Officer, Energy Transfer LP

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 and refined products segment delivered another record quarter as a result of the ramp-up of Mariner East 2 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 1.9 times, 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 II 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^st. 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^th, we announced that we entered into a definitive merger agreement to acquire SemGroup Corporation for 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^th, 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 receipt of the vote.

This acquisition is expected to be immediately accretive to distributable cash flow per 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 three-year term loan A at a current rate of LIBOR plus 100 [basis points]. 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 cost 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, an 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 two of the largest crude oil terminals in the 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 company’s 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 planned 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 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 services. 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 have 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 PE1, 2 and 3 Pipelines, which are part of our Permian Express joint venture with ExxonMobil, we continue to operate at capacity during the third quarter. And the PE4 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^st and is operating at full capacity as well.

Now looking at our Mariner East system, as a reminder, we placed the initial capacity of ME2 into service December 29, 2018, and volumes continue 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.

Additional inbound transportation modes, including trucking and rail, remain heavily utilized during the third quarter as well. We recently completed two local connections for delivery of propane and ethane to new facilities, including to a new power plant in Cambria County in western Pennsylvania and to the Sinking Spring area. We expect more connections like this to be made in the future. We have also executed an additional agreement for butane transportation with a local NGL distribution facility in Pennsylvania. International LPG arbitrage economics remain strong in the third quarter demonstrating the strength of this terminal in 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 of 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 startup of the Northeast NGL season which drives increased customer demand. However, because of modifications we 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 barrels 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 to 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 will 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 US 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 plant 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 the 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 products 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 the 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 are already meeting our expectation.

Let’s go 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 and refined products segment as well as growth in our 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 1.9 times and year-to-date coverage is nearly 2 times.

In October, Energy Transfer announced a distribution of $0.305 per common unit for the third quarter, or a $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^th to unitholders of record as of the close of business on November 5^th.

Now turning to the results by segment and we’ll start with the NGL and 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 our record transported 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 the startup of ME2 pipeline in the fourth quarter of 2018, as well as increased volumes on our pipelines out of the Permian Basin and 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 in 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 to 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 on the 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 taxes due to placing 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 to $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.

Taking a quick look at Sunoco and USA Compression, for investments in SUN, adjusted EBITDA was $192 million compared to $208 million a year ago. Third quarter 2018 results include a one-time benefit to segment margin of $25 million related to a cash settlement with a fuel supplier. Excluding this one-time 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 nine months ended September 30, 2019, Energy Transfer spent approximately $3.1 billion on organic growth projects, primarily in the NGL and refined products and midstream segments, excluding SUN and USAC CapEx. And for full year 2019, as mentioned, we have lowered our growth CapEx forecast to approximately $4 billion. And for full year 2020, we expect to expend approximately $4 billion, excluding expenditures related to the SemGroup assets, primarily in our NGL and 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 3.63 times per 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 4 to 4.5 times.

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 are 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 via 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.

QUESTION AND ANSWER SECTION

Operator: Thank you. [Operator Instructions] Our first question comes from Shneur Gershuni with UBS. Please proceed with your question.

Shneur Z. Gershuni

Analyst, UBS Securities LLC

Hi. Good morning, everyone. Just, it was good to see the 2019 EBITDA guide moved higher for EBITDA and CapEx lower for 2019 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 was 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.

Thomas E. Long

Chief Financial Officer, Energy Transfer LP

You bet, Shneur. This is Tom. I think I’ll kind of start with what – the guidance that we talked about for 2020, which was approximately $4 billion. But we thought it was important to also put the $1.5 billion, which is the backlog of CapEx projects beyond. So I think you can kind of see the nature of the projects right there, meaning that a lot are 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 those that are of that shorter nature you’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 the majority of all those projects. As far as the – go ahead I’m sorry?

Shneur Z. Gershuni

Analyst, UBS Securities LLC

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

Thomas E. Long

Chief Financial Officer, Energy Transfer LP

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 an integrated portfolio like ours, you get to see returns across pretty much all 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.

Shneur Z. Gershuni

Analyst, UBS Securities LLC

Great. And as the 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’d split it up as 5% to 7% and 5% and 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 falling 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 have an updated percentage by any chance?

Thomas E. Long

Chief Financial Officer, Energy Transfer LP

Well, they’re actually staying fairly consistent and you’re right – we’ve always said that we’re 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.

Shneur Z. Gershuni

Analyst, UBS Securities LLC

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 projects or assets in your portfolio?

Thomas E. Long

Chief Financial Officer, Energy Transfer LP

Yes, is the short answer. And you’re right - we have – I think we’ve got a good track record as you have seen, with some of the some of the assets that we’ve 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, so…

Shneur Z. Gershuni

Analyst, UBS Securities LLC

All right. Perfect. Thank you very much. Appreciate the color today.

Operator: Thank you. Our next question comes from the line of Jeremy Tonet with JPMorgan. Please proceed with your question.

Jeremy Tonet

Analyst, JPMorgan Securities LLC

Good morning. Just wanted to start off with the 2020 CapEx a bit more as well here, I guess in our modeling, we’re having a tough time building into that $4 billion number. So I was 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.

Thomas E. Long

Chief Financial Officer, Energy Transfer LP

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 and refined product segment and some of those 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 back to mid-next year, so you have to put that one in there as a piece of it. Lone Star Express pipeline, LPG facilities at Nederland, of course you got Fracs VII and VIII we’ve talked about, you 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’s 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 probably 75%, three-quarters of the CapEx spend. And then the rest of it’s going to be kind of split between midstream and crude oil. So, you’ve got the gathering projects we talked about, obviously, some compression facilities, et cetera. But once again, you have 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 and it’s, like I said, very consistent between the two.

I think the second part of your question, we have been very diligent in looking at projects and you’ve seen us bring our guidance down throughout 2019. And then when you really look at 2020, you’ll also see that we’re staying – even with the push of some of the dollars from 2019 to 2020, we’re still at approximately $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’re taking all the steps necessary to position ourselves financially to be able to do that.

Jeremy Tonet

Analyst, JPMorgan Securities LLC

That’s helpful. And then just one more for me if I could, it seems like in the marketplace there’s been a bit of a discussion on the REIT structure as it applies potentially to midstream and a 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?

Bradford D. Whitehurst

Executive Vice President & Head-Tax, Energy Transfer LP

This is Brad Whitehurst. We have, we’ve 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 a tool in our toolbox.

Jeremy Tonet

Analyst, JPMorgan Securities LLC

Got it. That’s it for me. Thanks.

Operator: Thank you. Our next question comes from the line of Pearce Hammond with Simmons Energy. Please proceed with your question.

Pearce Hammond

Analyst, Piper Jaffray & Co.

Thank you and appreciate you taking my questions. First question is what’s the latest on the permitting on the VLCC and how is that progressing? VLCC offshore terminal? Yeah.

Marshall S. McCrea

President, Chief Commercial Officer and Director, Energy Transfer LP

Yeah. 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.

Pearce Hammond

Analyst, Piper Jaffray & Co.

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?

Marshall S. McCrea

President, Chief Commercial Officer and Director, Energy Transfer LP

Yeah. Tom mentioned in his statements, 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 to answer to your second question, 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 issues 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.

Pearce Hammond

Analyst, Piper Jaffray & Co.

Thank you.

Operator: Thank you. Our next question comes from the line of Michael Lapides with Goldman Sachs. Please proceed with your question.

Michael Lapides

Analyst, Goldman Sachs & Co. LLC

Hey, guys. 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’s going through a 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?

Thomas E. Long

Chief Financial Officer, Energy Transfer LP

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 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 these master netting agreements, et cetera. So we feel very comfortable I think from an overall credit exposure out there in the way that we manage that. So none of that I guess I would say is keeping us up at night right now, so…

Michael Lapides

Analyst, Goldman Sachs & Co. LLC

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 your midstream businesses for 2020?

Marshall S. McCrea

President, Chief Commercial Officer and Director, Energy Transfer LP

This is Mackie again. Whether it’s the Northeast or down South, we do keep hearing and seeing that there are struggles in certain areas but we’re just not seeing it on 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 gas prices don’t just collapse, they’re going to continue drilling. We’re positioned very well to take advantage of picking up production in another area if one producer starts falling off. So we think we’ve built a company and kind of a strategy to kind of mitigate from impacts that we might have from certain producers in certain areas. But we, as Tom mentioned, we feel real good about the mix that we have of producer customers on our systems.

Michael Lapides

Analyst, Goldman Sachs & Co. LLC

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

Thomas P. Mason

Executive Vice President, General Counsel and President-LNG, Energy Transfer LP

Yeah. This 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 on an APC bidding process right now and we’re also actively marketing and we think our project is highly competitive. So we’re pleased with the progress.

Michael Lapides

Analyst, Goldman Sachs & Co. LLC

Got it. Thanks, guys.

Operator: Thank you. Our next question comes from the line of Keith Stanley with Wolfe Research. Please proceed with your question.

Keith Stanley

Analyst, Wolfe Research LLC

Hi. Good morning. On 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?

Marshall S. McCrea

President, Chief Commercial Officer and Director, Energy Transfer LP

Yeah, this is Mackie, again. Yeah, 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 the point to where we get the permit limit lifted and we’re pushing to make that happen, but certainly that has made it difficult to meet some of our timelines to get 2X on by end of the year.

Keith Stanley

Analyst, Wolfe Research LLC

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

Kevin Smith

Executive VP-Engineering and Construction, Energy Transfer LP

Yeah, 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.

Keith Stanley

Analyst, Wolfe Research LLC

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 size 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?

Thomas E. Long

Chief Financial Officer, Energy Transfer LP

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

Keith Stanley

Analyst, Wolfe Research LLC

Great. Thank you.

Operator: Thank you. Our next question comes from the line of Christine Cho with Barclays. Please proceed with your question.

Christine Cho

Analyst, Barclays Capital, Inc.

So, your CapEx of $4 billion next year and 2019 dropped by $700 million—that’s a fair point. Is it fair to say that most of that drop is tied to the ME2X delay 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 if things firm up?

Thomas E. Long

Chief Financial Officer, Energy Transfer LP

Yeah. Let’s say, it’s about half 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…

Christine Cho

Analyst, Barclays Capital, Inc.

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 SemCan. And I think there’s 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?

Marshall S. McCrea

President, Chief Commercial Officer and Director, Energy Transfer LP

Yeah. 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 SemCanada or anywhere else to sell. What we’re looking at is, how do we best deploy our capital to 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 revenue growth vehicle for our partnership.

Christine Cho

Analyst, Barclays Capital, Inc.

Okay. And then one more if I could. You know the MEP debt came due and was repaid. And I’m just curious, do you guys include debt paydown for any of these 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 a contribution?

Thomas E. Long

Chief Financial Officer, Energy Transfer LP

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.

Christine Cho

Analyst, Barclays Capital, Inc.

Helpful. Thank you.

Operator: Thank you. Our next question comes from the line of Danilo Juvane with BMO Capital Markets. Please proceed with your question.

Danilo Juvane

Analyst, BMO Capital Markets (United States)

Good morning and thanks for taking my question. 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?

Marshall S. McCrea

President, Chief Commercial Officer and Director, Energy Transfer LP

Yeah. This is Mackie. No, nothing changes. We’re taking all the necessary steps from the 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.

Danilo Juvane

Analyst, BMO Capital Markets (United States)

Thanks for that. 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 it the lower OpEx now the good run rate to use forward and can you expound on what that inter-segment transaction was?

Thomas E. Long

Chief Financial Officer, Energy Transfer LP

Yeah. Well, let me make sure I understand your question completely. 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 that operational inventory. That was approximately $30 million, $35 million, but it really was about – I think you were saying something on the OpEx, I think the OpEx was really – really wasn’t relevant there. The 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.

Danilo Juvane

Analyst, BMO Capital Markets (United States)

Okay. Those are my questions. Thank you.

Operator: Thank you. Our next question comes from the line of Colton Bean with Tudor, Pickering, Holt. Please proceed with your question.

Colton Bean

Analyst, Tudor, Pickering, Holt & Co. Securities, Inc.

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

Marshall S. McCrea

President, Chief Commercial Officer and Director, Energy Transfer LP

This is Mackie again. What we’ve seen in north Louisiana on our Tiger system is significant volume growth. Several years ago it fell below a 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 back haul into our intrastate network, getting to 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 next couple of – two or three years.

Colton Bean

Analyst, Tudor, Pickering, Holt & Co. Securities, Inc.

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

Thomas E. Long

Chief Financial Officer, Energy Transfer LP

Well, on Rover, 3.1 Bcf is sold term, if some of that comes back to us there is a – 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 are flowing 3.2 Bcf to 3.3 Bcf, certainly everything above the 3.1 Bcf 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 it 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 – 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.

Colton Bean

Analyst, Tudor, Pickering, Holt & Co. Securities, Inc.

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?

Marshall S. McCrea

President, Chief Commercial Officer and Director, Energy Transfer LP

No. This is Mackie again. DAPL, if we could snap our fingers and have 400,000 or 500,000 barrels a day today available, we think people would step up for it 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 Midcontinent refineries and then bring it down to the Gulf Coast getting to all the refineries in Texas and then through Bayou Bridge, getting to the St. James markets. And so we’re pretty pleased with our competitive advantage with DAPL.

Colton Bean

Analyst, Tudor, Pickering, Holt & Co. Securities, Inc.

Got it. Thank you.

Operator: Thank you. Our next question comes from the line of Michael Blum with Wells Fargo Securities. Please proceed with your question.

Michael Blum

Analyst, Wells Fargo Securities LLC

Thank you. I think in the prepared remarks, Tom, you talked about raising the bar when evaluating new CapEx projects. I wonder if you can maybe quantify that in any way—kind of the type of returns you’ve historically been targeting versus how that might be changing going forward?

Marshall S. McCrea

President, Chief Commercial Officer and Director, Energy Transfer LP

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 months to 18 months – we haven’t looked at for example a processing opportunity at less than an 18% rate of return. And remember – I know you know this, Michael – but when we do that on our processing plants, which we build one about every six months out in west Texas. We don’t put any of the synergistic revenues, none of the liquid revenues downstream, none of the residue revenues 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’re targeting high rate of return projects with synergistic benefits added to them.

Michael Blum

Analyst, Wells Fargo Securities LLC

Great. That makes sense. Thank you. 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 that 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?

Thomas E. Long

Chief Financial Officer, Energy Transfer LP

You asked a couple broad questions and kind of specific, but it’s fair to say that in any given year wherever – 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’s necessary to accommodate it and makes good business sense for our partnership, we’ll certainly looking at helping them where we can, when it makes sense.

Michael Blum

Analyst, Wells Fargo Securities LLC

Great. Thank you.

Operator: Thank you. Our final question comes from the line of Elvira Scotto with RBC Capital Markets. Please proceed with your question.

Elvira Scotto

Analyst, RBC Capital Markets LLC

Hey, good morning, everyone. 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?

Marshall S. McCrea

President, Chief Commercial Officer and Director, Energy Transfer LP

Yeah, this is Mackie again. We’re highly, very confident that we’ll have it in by the middle – at the 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 chilling and tank for propane and butane by the middle of next year, it’ll be perfect timing as we bring on more capacity on 2X, which will be a huge shot in the arm for us from a revenue standpoint.

Elvira Scotto

Analyst, RBC Capital Markets LLC

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

Marshall S. McCrea

President, Chief Commercial Officer and Director, Energy Transfer LP

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 that we’ve been working on and they’re much higher rates of return. So anything above those projects it needs to meet the threshold. It needs to be the 18% to 20% and it needs 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 we’ve built a lot of pipe. 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 what we’ve already built.

Elvira Scotto

Analyst, RBC Capital Markets LLC

Got it. And just the last one for me, just a follow-up on SemCan question, so understanding that you see Canada, 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?

Marshall S. McCrea

President, Chief Commercial Officer and Director, Energy Transfer LP

There’s nothing that just jumps out from a synergistic standpoint but if you know Energy Transfer, we’re certainly looking at everything—how the liquid is getting out of there, what other opportunities there are. But it’s a pretty solid asset and project just standalone. As I mentioned earlier, it has a 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.

Elvira Scotto

Analyst, RBC Capital Markets LLC

Okay, great. Thanks a lot.

Operator: Thank you. Ladies and gentlemen, I’d now like to turn the floor back to Tom Long for closing comments.

Thomas E. Long

Chief Financial Officer, Energy Transfer LP

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. Thank all of you for your support. We look forward to talking to you in the near future.

Operator: Thank you. [Operator instructions].

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Cautionary Statement Regarding Forward-Looking Statements

This transcript includes “forward-looking” statements. Forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may” or similar expressions help identify forward-looking statements. Energy Transfer LP (“ET”) and SemGroup Corporation (“SemGroup”) cannot give any assurance that expectations and projections about future events will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. These risks and uncertainties include the risks that the proposed transaction may not be consummated or the benefits contemplated therefrom may not be realized. Additional risks include: the ability to obtain requisite regulatory and stockholder approval and the satisfaction of the other conditions to the consummation of the proposed transaction, the ability of ET to successfully integrate SemGroup’s operations and employees and realize anticipated synergies and cost savings, the potential impact of the announcement or consummation of the proposed transaction on relationships, including with employees, suppliers, customers, competitors and credit rating agencies, the ability to achieve revenue, DCF and EBITDA growth, and volatility in the price of oil, natural gas, and natural gas liquids. Actual results and outcomes may differ materially from those expressed in such forward-looking statements. These and other risks and uncertainties are discussed in more detail in filings made by ET and SemGroup with the Securities and Exchange Commission (the “SEC”), which are available to the public. ET and SemGroup undertake no obligation to update publicly or to revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Additional Information and Where to Find It

In connection with the proposed transaction, ET filed with the SEC a registration statement on Form S-4, including a proxy statement/prospectus. SECURITY HOLDERS ARE URGED TO READ THE REGISTRATION STATEMENT AND THE PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION CAREFULLY. The registration statement on Form S-4 was declared effective by the SEC on October 30, 2019, and the definitive proxy statement/prospectus will be delivered to security holders of record of SemGroup as of October 25, 2019. These documents, and any other documents filed by ET and SemGroup with the SEC, may be obtained free of charge at the SEC’s website, at www.sec.gov. In addition, investors and security holders may obtain free copies of the registration statement and the proxy statement/prospectus by phone, e-mail or written request by contacting the investor relations department of ET or SemGroup at the numbers and addresses set forth below:

Participants in the Solicitation

ET, SemGroup and their respective directors and executive officers may be deemed to be participants in the solicitation of proxies in connection with the proposed merger. Information regarding the directors and executive officers of ET is contained in ET’s Form 10-K for the year ended December 31, 2018, which was filed with the SEC on February 22, 2019. Information regarding the directors and executive officers of SemGroup is contained in SemGroup’s proxy statement relating to its 2019 Annual Meeting of Stockholders, which was filed with the SEC on April 12, 2019. Additional information regarding the interests of participants in the solicitation of proxies in connection with the proposed merger are included in the proxy statement/prospectus.

No Offer or Solicitation

This transcript is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the proposed merger or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended.