Filed by Energy Transfer Partners, L.P.
pursuant to Rule 425 under the Securities Act of 1933
and deemed filed pursuant to Rule 14a-12
under the Securities Exchange Act of 1934
Subject Company: Energy Transfer Partners, L.P.
Commission File No.: 001-31219
Date: August 9, 2018
TRANSCRIPT
The following is a transcript of the Energy Transfer Equity, L.P. (“ETE”) and Energy Transfer Partners, L.P. (“ETP”) quarterly earnings conference call held at 8:00 a.m. Central time on August 9, 2018. 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. ETP believes that none of these is material.
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Operator: [Operator instructions]
It is now my pleasure to introduce your host, Tom Long, Energy Transfer Partners’ Chief Financial Officer. Thank you. You may begin.
Thomas E. Long, Group Chief Financial Officer of ETE and Chief Financial Officer of ETP:
Thank you, operator. Good morning, everyone, and welcome to the Energy Transfer second quarter 2018 earnings call and thank you for joining us today. I’m also joined today by Kelcy Warren, Mackie McCrea, Matt Ramsey, John McReynolds, Tom Mason and other members of the senior management team who are here to help answer your questions after our prepared remarks.
I’ll begin today with an overview of our simplification transaction we announced last week, followed by a discussion of our latest developments on our Rover, Mariner East 2, Permian Express 3 and other growth projects. Then I’ll turn our focus to a discussion of Energy Transfer Partners’ second quarter results, followed by a discussion on CapEx, liquidity and funding, and lastly distributions.
As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These are based on our beliefs as well as certain assumptions and information currently available to us. I will also refer to adjusted EBITDA and distributable cash flow, or DCF, both of which are non-GAAP financial measures. You’ll find a reconciliation of our non-GAAP measures on our website.
Before I provide an overview of the ETE/ETP transaction, I just want to start by saying that we are very pleased with Energy Transfer’s record second quarter. ETP’s adjusted EBITDA increased more than 30% and DCF attributable to the partners of ETP, as adjusted, increased nearly 40% over the second quarter of last year. I will provide more details later on in the call, but this increase is due to significantly higher results from the crude oil transportation and services segment as well as strong growth in several other of our segments.
Now, turning to our most recent announcement, last week, ETE and ETP entered into a merger agreement providing for the acquisition of ETP by ETE for $27 billion in ETE common units. Under the terms of the transaction, ETP unitholders will receive 1.28 ETE common units for each ETP common unit, implying a price of $23.59 per unit based upon ETE’s closing price immediately prior to the announcement of the transaction. This represents an 11% premium to the previous day’s ETP closing price and a 15% premium to the 10-day volume weighted average ETP price. The transaction is expected to be immediately accretive to ETE’s DCF per unit. We expect to maintain ETE’s distribution per unit at its current level.
In addition, the transaction will create a more simplified ownership structure, as we are eliminating the IDRs, which will improve our overall cost of capital. This will allow us to continue pursuing accretive growth capital projects and strategic M&A transactions. It also increases retained cash to accelerate deleveraging. Following the merger, we are expecting a DCF coverage ratio of 1.6 to 1.9 times, which equates to about $2.5 billion to $3 billion of annual retained cash. This greatly reduces our external common or preferred equity funding needs going forward.
We do expect the pro forma partnership to be rated investment-grade. The transaction is expected to close in the fourth quarter of 2018, subject to approval by the majority of the unaffiliated ETP unitholders and other customary closing conditions. We expect to file the S-4 early next week.
Now, moving to our growth projects, and we’ll start with Rover. On May 31st, we received authorization from FERC to commence service on the Supply Connector B and Full Mainline B pipeline segments on Rover. As of June 1st, 100% of mainline capacity, which is 3.25 Bcf per day, is in service, and we are currently collecting demand charges on approximately 80% of the contracted capacity.
Rover is now 100% mechanically complete. For our overall project restoration activities, rough cleanup is 99% complete, final cleanup is 81% complete, and revegetation is 78% complete. We expect to have all these restoration activities 100% complete this month. We submitted in-service request to FERC for Majorsville on May 7 and Burgettstown on February 13 and plan to file for Sherwood and CGT by mid-August. Our Revolution processing plant is complete and we expect it to go into service once Rover has received full approval of the remaining supply laterals.
Now moving on to ME2 and 2X, we continue to make progress on the construction of ME2 with 99% of mainline construction complete and 80% of hydro-testing complete. In addition, 100% of HDDs are completed or in process, in line with our approved HDD plan with no more drilling re-evaluation reports required from DEP.
The Pennsylvania PUC’s commissioners have overturned the prior decision that prevented continued construction in West Whiteland Township. To avoid any delays in the ME2 project schedule, we will utilize a section of an existing pipeline in the affected area for initial in-service. This plan does not require any new permits, and we have made all applicable regulatory notifications. As a result, we continue to expect to place ME2 in service by the end of this quarter. This will allow us to bring sufficient capacity online to meet all of our initial contractual commitments. Construction of ME2X also continues and we expect the pipe to be online in mid-2019.
As we announced on our last call, ETP and Satellite Petrochemical USA Corp. have entered into a definitive agreement to form the Orbit joint venture to construct a new ethane export terminal on the U.S. Gulf Coast to provide ethane to Satellite. Satellite received provincial approval for the construction of their ethane cracker in early July, and we continue to expect the export terminal to be ready for commercial service in the fourth quarter of 2020.
Also, during the second quarter, we completed an open season for the J.C. Nolan Diesel Pipeline. That will transport diesel fuel from Hebert, Texas to a newly constructed terminal in the Midland, Texas area. The pipeline will utilize existing ETP pipelines and is projected to have an initial capacity of 30,000 barrels per day.
ETP and Enterprise are in the process of expanding the jointly owned 36-inch North Texas Pipeline. The North Texas Pipeline will provide approximately 160,000 MMBtus per day of additional capacity from West Texas for deliveries into the Old Ocean natural gas pipeline once it is completed at the end of this year. The Old Ocean natural gas pipeline, which is a 50/50 joint venture between ETP and Enterprise, resumed service during the second quarter with initial capacity of 130,000 MMBtus per day, increasing to 160,000 MMBtus per day by the end of the third quarter. The 24-inch Old Ocean pipeline originates in Maypearl, Texas and extends south 240 miles to Sweeny, Texas.
Now moving to our processing plants in West Texas, the 200 million cubic foot per day Rebel II processing plant in the Midland Basin went into service at the end of April. The volumes are ramping up and we expect it to be full by year-end. In addition, construction on another 200 million cubic foot per day cryogenic processing facility, which will be near our existing Arrowhead plant, is expected to be completed in the fourth quarter of this year.
Also in West Texas, our Red Bluff Express Pipeline went into service in May. This 1.4 Bcf per day natural gas pipeline runs through the heart of the Delaware Basin and connects our Orla plant as well as multiple third-party plants to our Waha Oasis Header. We are currently expanding this project by an additional 25 miles of 30-inch pipeline, which is expected to be in service in the second half of 2019.
On our Permian Express 3, as a reminder, we successfully brought a portion of PE3 online in the fourth quarter of 2017. During the second quarter, we completed a successful open season for approximately 50,000 additional barrels per day, which represents the final phase of the approximately 140,000 barrels per day PE3 project. We expect this final 50,000 barrels per day to be online later this year.
We are also making significant progress with our new 30-inch crude oil pipeline joint venture project with Magellan and other strategic partners. This pipeline will provide unprecedented flexibility from the Permian Basin for deliveries to East Houston and to the significant market and refinery corridor in the Nederland/Beaumont areas. It will also provide shipper capacity to our storage facilities and pipeline header systems as well as to access to Bayou Bridge. Continuing with Bayou Bridge, construction of the 24-inch segment from Lake Charles to St. James continues with commercial operations expected to begin in the fourth quarter of 2018.
We are pleased to announce that Lone Star’s 120,000 barrels per day Frac V went into service in July, ahead of schedule. This brings our total frac capacity of Mont Belvieu to nearly 600,000 barrels per day. As a reminder, Frac V is fully subscribed by multiple long-term fixed fee contracts and also includes NGL product infrastructure and a new 3 million barrel Y-grade cavern. And we continue to expect the 140,000 barrels per day Frac VI to be in service in the second quarter of 2019. The majority of this frac is fully contracted under demand-based contracts.
At our Godley plant, full take-or-pay commitments on the 400 million cubic foot per day, 10-year agreement with Enable went into effect July 1st and they are already flowing near the full amount.
Now, let’s turn to our second quarter results. As I mentioned, ETP had another very strong quarter. Adjusted EBITDA on a consolidated basis was a record $2 billion. This was up more than $500 million compared to the second quarter of 2017. This increase is due to significantly higher results in the crude oil segment as a result of both the Bakken pipeline coming online as well as strong growth from several of our other segments.
DCF attributable to the partners, as adjusted, also hit a record high of $1.3 billion. This was an increase of $371 million compared to the second quarter of 2017, primarily due to the increase in overall adjusted EBITDA. ETP’s coverage for the second quarter was 1.23x resulting in excess cash flow over distributions of $249 million.
Turning to our results by segment and starting with midstream, adjusted EBITDA was $414 million compared to $412 million for the second quarter of 2017. During the second quarter of 2017, our midstream segment recorded a one-time $30 million benefit that was a result of several items. Without these non-recurring items, our midstream segment saw strong growth primarily due to higher throughput volumes and higher NGL and crude prices.
Compared to the first quarter of 2018, midstream adjusted EBITDA was up $37 million primarily due to volume growth across the majority of our regions. Gathered gas volumes totaled approximately 11.6 million MMBtus per day compared to 11 million MMBtus per day for the same period last year. This was primarily due to increased volumes in the Permian from higher producer demand and growth on the Ohio River System in the Northeast.
In the NGL and refined products segment, adjusted EBITDA increased to $461 million compared to $388 million for the same period last year. The increase was due to higher transport volumes on our Texas NGL and Mariner West pipelines, increased refined products terminal volumes, and growth at the Lone Star fractionators as well as higher results from our optimization and marketing group.
NGL transportation volumes on our wholly owned and joint venture pipelines were 967,000 barrels per day compared to 835,000 barrels per day for the same period last year mainly due to increased volumes out of the Permian Basin and on the Mariner West pipeline. Year-over-year, average daily fractionated volumes increased to 473,000 barrels per day compared to 431,000 barrels per day last year due to increased volumes from the Permian producers.
Now moving on to the crude oil segment, adjusted EBITDA increased to $548 million compared to $228 million for the same period last year. The increase was primarily due to placing our Bakken pipeline in service in the second quarter of 2017, increased throughput on existing pipelines primarily from Permian producers, and higher ship loading and throughput fees at our Nederland terminal due to an increase in exports as well as an increase from the crude oil acquisition and marketing business related to favorable basis differentials between Midland and the Gulf Coast.
Crude transportation volumes increased to 4.2 million barrels per day compared to approximately 3.5 million barrels per day for the same period last year primarily due to placing the Bakken pipeline in service on June 1st of 2017 and increased production from the Permian Basin. During the second quarter, volumes on our Bakken pipeline averaged 473,000 barrels per day.
In our intrastate segment, adjusted EBITDA increased to $208 million compared to $148 million in the second quarter of last year. This was primarily due to a $47 million increase from commercial optimization activities, due to the wider basis differentials from West Texas to the Gulf Coast, as well as the acquisition of the remaining interest in the RIGS pipeline in April. Our reported intrastate transport volumes increased primarily due to RIGS now being treated as a consolidated subsidiary as well as more favorable market pricing in the Texas markets.
In our interstate segment, adjusted EBITDA was $330 million compared to $262 million for the second quarter of 2017. This increase was due to additional EBITDA from the partial in-service of Rover. We expect earnings in this segment to continue increasing with the commissioning of the remaining Rover supply laterals. Interstate transportation volumes were 8.7 million MMBtus per day compared to 5.3 million MMBtus per day for the same period last year due to an increase of 1.7 million MMBtus per day from bringing a portion of Rover into service as well as higher utilization on Panhandle and Trunkline, increases from Tiger due to production increases in the Haynesville Shale, and increases on Transwestern as a result of favorable spreads across the pipeline.
Moving on to the all other segment, which includes our equity method investment in limited partnership units of Sunoco LP consisting of 26 million units, representing 32% of Sunoco’s total outstanding common units.
Subsequent to our contribution of CDM to USA Compression in April 2018, the “All Other” segment also includes our equity method investments in USA Compression consisting of 19 million USAC units and 6 million Class B units, representing 27% of USAC’s limited partner interest.
Adjusted EBITDA was $90 million compared to $107 million a year ago due to a $44 million decrease in earnings from our investment in Sunoco LP primarily due to Sunoco LP’s sale of retail assets to 7-Eleven, as well as its repurchase of 17 million common units in February 2018 and a decrease of $12 million due to the contribution of CDM to USAC in April of 2018. This was partially offset by increases in adjusted EBITDA related to unconsolidated affiliates due to our equity method investment in USAC as well as higher EBITDA from our investment in PES.
Now, for a CapEx update, for the six months ended June 30, 2018, ETP funded approximately $2.2 billion in organic growth projects primarily in the NGL and refined products, and midstream segments. For full year 2018, we expect to spend approximately $4.5 billion to $4.8 billion in organic growth projects, primarily in the NGL and refined products, midstream and interstate segments. The increase is primarily due to new growth projects.
Taking a look at our funding activities for the quarter as well as our liquidity position, in July, ETP issued $445 million of its 7.625% Series D fixed-to-floating rate cumulative redeemable perpetual preferred units. Once again, these securities provide an extremely cost effective means of raising equity capital, and ETP used the proceeds to repay amounts outstanding under its revolving credit facility for general partnership purposes.
Like our other recent preferred unit offerings, these securities also received 50% equity treatment from all three rating agencies. In June, ETP issued $3 billion aggregate principal amount of senior notes in a four-tranche offering, the proceeds of which were used to redeem approximately $1.65 billion of outstanding senior notes and for general partnership purposes.
In addition, during the second quarter, ETP bought out the remaining interest at RIGS and paid off the RIGS credit facility. As of June 30, 2018, total liquidity under ETP’s revolving credit facility was approximately $3.6 billion. And as of June 30, 2018, ETP’s leverage was 3.87x per the credit facility. In July, ETP announced a distribution of $0.565 per common unit for the second quarter or $2.26 per common unit on an annualized basis. This distribution is flat compared to the first quarter of 2018 and will be paid on August 14th to unitholders of record as of the close of business on August 6th.
So now, let’s move on to ETE, for the second quarter, distributable cash flow, as adjusted, totaled $407 million. ETE’s coverage for the second quarter was 1.15x resulting in excess cash flow over distributions of $53 million. In July, ETE announced a quarterly distribution of $0.305 per unit. This equates to $1.22 per unit on an annualized basis and will be paid on August 20th to unitholders of record as of the close of business on August 6th. ETE continues to have a healthy liquidity position and ended the quarter with a debt to EBITDA ratio of 2.79x per our credit facility. As of June 30, 2018, ETE had approximately $544 million available under its revolving credit facility.
So before opening the call up to your questions, I just want to say that we are once again very pleased to have reported another strong quarter. Contributions from Bakken crude oil pipeline and Rover were big components of this growth in earnings, and we also continue to make great progress toward improving ETP’s leverage metrics. We are also very excited to have announced a simplification transaction that provides a premium to current ETP unitholders and is expected to be immediately accretive to ETE’s distributable cash flow per unit. With this transaction, ETE will have an approximately $100 billion enterprise value with a simplified structure, enhanced financial flexibility, and a lower cost of capital.
Our new financial structure is expected to greatly strengthen our balance sheet and credit profile and position the combined company for continued growth. Looking ahead to the rest of 2018, we are excited for the expected DCF growth as we complete Rover, ME2, and other key projects.
With that, operator, that concludes our prepared remarks. Please open the line up for questions.
Q&A SECTION
Operator: Thank you. [Operator Instructions] Our first question is coming from the line of Shneur Gershuni with UBS. Please proceed with your question.
Shneur Z. Gershuni, Analyst, UBS Securities LLC:
Hi. Good morning, guys. I recognize that you can’t say much about the simplification projections. I’ll just keep my questions to some project questions. Specifically, I was wondering if you can expand a little bit on your prepared remarks with respect to Mariner East 2. I’m trying to understand how using this legacy pipe will help the project advance and how does it address the PUC issues and like is the diameter large enough and so forth? I was just wondering if you can give us a little bit more color on that.
Marshall S. (Mackie) McCrea, Group Chief Operating Officer, Chief Commercial Officer and Director of ETE, Chief Commercial Officer and Director of Energy Transfer Partners, L.P.:
Okay. This is Mackie. We’ve secured pretty significant volumes for these projects: ME1, ME2, and ME2X. However, those projects ramp up over time, so the utilization of the 12-inch more than provides the necessary capacity to move the volumes that we’ve contracted and also allows us to bring ME2 online hopefully by the end of this quarter. So it was necessary, but has no impact whatsoever on our contractual obligations.
Matthew S. Ramsey, President, Chief Operating Officer & Director of Energy Transfer Partners, L.P.:
And this is Matt. Let me expand on that a little bit. So, at ME2, I guess it’s obviously the first issue with the use of the 12-inch line through there. We’re kind of repeating what we said in the earlier remarks, 99% of mainline construction is complete. The 1% that remains on mainline construction is associated with HDDs that we are completing right now. So we have 16 HDDs to complete. All those have been approved by PADEP and they’re either drilling ahead or they’re in the stage where we’re going back to PADEP when we have an inadvertent return but they’ve all been approved. So, we don’t have to have any changes approved by PADEP going forward like that. All the road bores are finished. And as Tom said in the earlier remarks, 80% of the line has been hydro-tested. So we feel confident that we’ll be finished with ME2 and in-service by the end of the third quarter of this year.
Shneur Z. Gershuni, Analyst, UBS Securities LLC:
Great. Thank you for that update. Just a couple of quick follow-ups. The ETP just posted a record quarter and has done extremely well on the crude and on the natural gas side as well. Obviously, the spread environment has largely contributed to that. Has there been any talk internally or in terms of thought process about potentially to lock in some of those spreads into some longer term contracts and so forth, or are you limited by walk-up or other issues? Just trying to understand kind of the ability to sort of capture this for the longer term.
Marshall S. (Mackie) McCrea:
This is Mackie again. I’ll kind of walk through each component. On NGL, it’s really not something we look at. We’re very pleased that we completed the 24- and 30-inch a little while back because there’s not a lot of capacity, so we do even see that basis or the value that transportation from West Texas to Houston going up over the next 18 months. So we’re well positioned there, but no hedging strategy is there. Around natural gas, we’ve been pretty disciplined on a prudent approach where we have gone out and hedged at healthy margins on some of our capacity. There’s a considerable amount of capacity that we have not hedged and capacity that we have brought on recently and we’ll be bringing on by the end of the year.
So our approach is kind of twofold on really natural gas and oil – is to secure as much as we think is necessary long term and also look at when will other pipelines be coming online, which very likely will shrink that basis, and to extend our contracts past that period of time. Around the oil side, we have hedged a while back a considerable amount of our capacity. However, we still have to considerable amount left. And right now, we don’t think it makes sense to necessarily lock in hedges on that capacity in light of where the environment is today with the volume growth out in the Permian Basin and the lack of capacity out in the Permian Basin.
Shneur Z. Gershuni, Analyst, UBS Securities LLC:
Great. And one final question. Are there any updates or progress with Lake Charles on the LNG side?
Thomas P. Mason, Executive Vice President & General Counsel, Energy Transfer Equity, L.P.:
It’s Tom Mason. Not really since our last quarterly call. It’s – we’re continuing to market our LNG capacity and things are progressing, but other than that, kind of what we talked about last quarter.
Shneur Z. Gershuni, Analyst, UBS Securities LLC:
Great. Thank you very much, guys. I really appreciate the update.
Operator: Thank you. Our next question is coming from the line of Jeremy Tonet with JPMorgan. Please proceed with your question.
Jeremy Tonet, Analyst, JPMorgan Securities LLC:
Good morning. Congratulations on the great results. I just want to pick up on kind of one of Shneur’s questions from a little bit different angle here. Just granted you guys are looking to kind of lock in margins as it makes sense over the next kind of year or so. But I’m just wondering how sustainable are these kind of margins – these results that we see in the crude oil segment, in the interstate segment? Is there any kind of dissipation in the environment out there where 3Q or 4Q might come in lower than what you did in 2Q or is this kind of a run-rate that you guys are able to achieve and build off of in the current environment?
Marshall S. (Mackie) McCrea:
This is Mackie again. As we’ve said in the last call, we certainly can’t predict where gas or oil price are going and we certainly can’t predict where basis is going. However, we have a team that looks at this daily, have weekly discussions on what capacity is available today, what pipelines will be completed, where volume ramp-up is headed. And then we make our decisions based on that. So, as I said earlier, we have hedged in some areas where it makes sense to hedge. We have plenty of capacity and we lock in 10-year deals. But it also makes a lot of sense to hold a lot of that capacity when we see a severe shortage of capacity in the NGL and oil segments over at least the next year and a half to two years.
Jeremy Tonet, Analyst, JPMorgan Securities LLC:
Got you. So I mean it sounds like you can’t predict exactly what’s going to happen in 3Q, et cetera, but there’s no notable headwinds to think that this was going to change dramatically.
Marshall S. (Mackie) McCrea:
Correct.
Jeremy Tonet, Analyst, JPMorgan Securities LLC:
Thank you. And then just want to touch on some of the expansions here. And I was just wondering as far as Permian takeaway, I was curious on Permian Express 1, given how Sunrise will be coming online pretty soon, it looks like it brings more than enough volumes into Wichita Falls there. And is there room in Permian Express 1 to pick up the volumes there and send it to the Coast or would it make sense to kind of expand that pipe given how much will be coming in when that project comes online?
Marshall S. (Mackie) McCrea:
I think I’d answer that a little more broadly. We’re looking at every pipeline we own in our partnership whether it’s an oil service or not to more fully utilize it and/or to put it in a service that makes more sense. So certainly, Mariner 1 is in that basket where we’re looking at every possible way of increasing capacity out of that that could benefit our revenues.
Jeremy Tonet, Analyst, JPMorgan Securities LLC:
Got it. Permian Express 1?
Marshall S. (Mackie) McCrea:
Yeah. Permian Express 1, Permian Express 2 and 3, and any of our abilities to expand those assets, we’re looking at it daily. And we will have expansions hopefully announced in the near future.
Jeremy Tonet, Analyst, JPMorgan Securities LLC:
Great, thanks. And maybe you’re not able to share more information this time, but in the same vein, Dakota Access Pipeline, seems like there’s a lot of need to expand that as well. Any thoughts you could share?
Marshall S. (Mackie) McCrea:
You bet. This is Mackie again. Like I just said, we’re looking at everything that we own, how do we create more capacity and hence more revenue. We have run a lot of testing on that system recently. We do expect to be able to increase that capacity. We’re not really, for competitive reasons, saying what that will be. But it’s something that we’re moving forward on and we will increase our capacity as much as efficiently possible to be able to move growing barrels out of the Bakken.
Jeremy Tonet, Analyst, JPMorgan Securities LLC:
That’s all for me. Thanks for taking my questions.
Operator: Thank you. Our next question is coming from the line of Jean Ann Salisbury with Bernstein. Please proceed with your question.
Jean Ann Salisbury, Analyst, Sanford C. Bernstein & Co. LLC:
Hi. Good morning. You may have answered this with the last question, but can you do any more with drag-reducing agents on your current Permian pipelines or is that pretty much maxed out at this point?
Marshall S. (Mackie) McCrea:
Can you do more – what?
Jean Ann Salisbury, Analyst, Sanford C. Bernstein & Co. LLC:
Can you get any more capacity on your Permian pipelines with drag-reducing agents at this point or is that pretty much maxed out?
Marshall S. (Mackie) McCrea:
Yes, we can. As I mentioned earlier, we can expand. We’re looking at expanding Permian Express 1. We’re looking at what we can do on Permian Express 3. We probably have a Permian Express 4 expansion. And then we’re also looking at other pipelines we possibly could put into oil transportation service.
Jean Ann Salisbury, Analyst, Sanford C. Bernstein & Co. LLC:
Okay. And those are mainly coming from drag-reducing agents I guess or...
Marshall S. (Mackie) McCrea:
Oh, yeah. Everywhere we possibly can use DRA across the country. We’re using it on every one of our pipelines
Jean Ann Salisbury
Analyst, Sanford C. Bernstein & Co. LLC:
You already are. Okay. Okay, thank you. And then, would it be possible to get your current estimate of how much more you’re expecting to make and create marketing this year than last after you account for the hedges that you have in place for the rest of the year?
Marshall S. (Mackie) McCrea:
Talking about hedges – this is Mackie again. Tom may add to it, but as we’ve mentioned, we have hedged more heavily in the fourth quarter and first quarter of next year. And then it falls off pretty significantly on our hedges throughout the remainder of 2019.
Thomas E. Long:
Yeah. And listen, I will add a little bit to that. I mean as you all know, we don’t really give guidance. Of course, we’re looking at coming out with an S-4 shortly with some projections. But I just echo what Mackie just said. We’ve got some upside, but we’re not quantifying that at this time, so…
Jean Ann Salisbury, Analyst, Sanford C. Bernstein & Co. LLC:
Okay. Fair enough. Thank you. That’s all for me.
Operator: Thank you. Our next question is coming from the line of Darren Horowitz with Raymond James. Please proceed with your question.
Darren C. Horowitz, Analyst, Raymond James & Associates, Inc.:
Good morning, guys. Mackie, if I could, I wanted to go back to the discussion around PE3, PE4 and then that new 30-inch line that you guys are considering. How do you think about the scale of what PE4 could look like, whether or not it’s 80,000 barrels or 100,000 barrels or maybe a little bit more? And then more specifically, when you guys think about the scale and scope of this possible joint venture 30-inch line, how does the thought process – once Bayou Bridge comes into service and the ability to move barrels from Nederland East to St. James – how does the thought process shift with regard to physical barrels ending up in the East Houston ship channel versus Beaumont, Nederland or even further East to St. James? Where do you want those barrels to go?
Marshall S. (Mackie) McCrea:
Wherever our customers want them to go. We’ll let them guide us. But as I mentioned, we are looking at expanding Perm Express 3, which would be Permian Express 4. You’re right on it. Once we do that, that’ll probably be between 80,000 barrels and 100,000 barrels. That’s probably kind of the limit of the efficient capacity that we can add. And then, of course, with our 30-inch pipeline that we’re moving forward with in our discussions and negotiations and feel very good about, that would add at least another million barrels and to continue on, certainly a lot of folks we’re talking to would like to go further down the stream and we’re talking to some of the producers and shippers out of West Texas that not only want to go to Nederland and East Houston, but also want to go further into St. James. So, as you know, we have the ability to provide wherever a piece of that service including storage and export that our customers are looking for, but we let them guide us.
Darren C. Horowitz, Analyst, Raymond James & Associates, Inc.:
Mackie, do you think the next step for that then would be something of significant scale with regard to export capabilities either at Lake Charles or St. James?
Marshall S. (Mackie) McCrea:
We certainly have seen our export capacity grow. We think it can continue to grow throughout the country, and we have the ability to have pretty significant growth at Nederland and we are certainly proceeding down that path.
Darren C. Horowitz, Analyst, Raymond James & Associates, Inc.:
Okay. And then last question for me. As you guys think about the opportunity to provide the best economic netback return for your customer, it seems like barrels clearing the dock especially given the supply push that we see makes the most sense. What’s more advantageous for you, incremental capacity at Nederland or something new at Lake Charles or St. James?
Marshall S. (Mackie) McCrea:
New for us to acquire or build?
Darren C. Horowitz, Analyst, Raymond James & Associates, Inc.:
What makes the most economic sense? Where can you guys make the most profit and provide the best economic return to your customers?
Marshall S. (Mackie) McCrea:
Well, as it sits here today, Nederland, no doubt. And that’s one of the benefits of the 30-inch in addition to a great project that we hope to announce one day soon. We also receive upstream and downstream benefits. And Nederland certainly is a great beneficiary of that service both for header deliveries to refineries, for storage, service and also for export service which we have expanded and we’ll continue to expand over the years to come.
Darren C. Horowitz, Analyst, Raymond James & Associates, Inc.:
I appreciate it. Thanks, Mackie.
Marshall S. (Mackie) McCrea:
You bet.
Operator: Thank you. The next question is coming from the line of Keith Stanley with Wolfe Research. Please proceed with your question.
Keith Stanley, Analyst, Wolfe Research LLC:
Hi, good morning. After the merger closes, would you plan to pay down debt with some of the retained cash flow or should we think of retained cash flow as more likely to get allocated to growth CapEx and delevering plans or are mainly from EBITDA growth going forward?
Thomas E. Long:
Yeah, you bet. Keith, as you really look at of course the $2.5 billion to $3 billion of retained cash flow that we’ve talked about in the discussions over the last week or so, what you’re going to really see as much as in is you’re going to see us start managing toward that 4 to 4.5x leverage ratio. So, depending – the variables that go into that are going to be – what is the cap – what is going to be the funding needs around all these organic projects as you look out at them. But it’s also going to be then the balance of how you look at funding these things. And we’re going to try to always optimize the return to the unitholders. And so you’re going to see us kind of navigate that way. So if let’s say for example you end up with even more cash flow, yes, you would be using it to even deleverage at a faster clip. But I can’t emphasize enough to you what an already faster clip we’re going to be deleveraging as you bring these two companies together, so…
Keith Stanley, Analyst, Wolfe Research LLC:
Okay. And then just follow-ups on some of the other ones, so Mariner, what is the capacity of the interim solution using the 12-inch line in some areas?
Marshall S. (Mackie) McCrea:
No. We really haven’t shared capacities. We can look at maybe doing that in the future. But the most important aspect of the question is we have sufficient capacity to handle what we contracted.
Keith Stanley, Analyst, Wolfe Research LLC:
Okay. When would you expect the full pipeline at the 275,000 barrels a day to be completed with the remaining HDDs complete?
Marshall S. (Mackie) McCrea:
For Mariner 2?
Keith Stanley, Analyst, Wolfe Research LLC:
Yeah. For Mariner 2.
Marshall S. (Mackie) McCrea:
For Mariner 2, well, for the next segment, the last segment through what we call the GRE area, we expect that to be completed by the third quarter or in the third quarter of 2019.
Keith Stanley, Analyst, Wolfe Research LLC:
For Mariner 2 would be third quarter 2019 as originally planned?
Marshall S. (Mackie) McCrea:
Yeah. For the next segment through – yeah, the last segment of Mariner 2 will be completed in October of 2019.
Keith Stanley, Analyst, Wolfe Research LLC:
Okay. All right. One last quick one. Just crude marketing, is there any – so we think there is any lag between the time when spreads expand or compress and when you guys realize results in the crude marketing business, is there any lag there to be mindful of?
Marshall S. (Mackie) McCrea:
I’m sorry. Could you repeat the question?
Keith Stanley, Analyst, Wolfe Research LLC:
So is there any lag between when we look at kind of the West Texas, the East Texas spread on the screen? From when that expands or compresses and when you would see realized margin and results, is there a month or two lag or anything like that in the crude marketing business?
Marshall S. (Mackie) McCrea:
Yes, there is. For example, we set in for what the spread will be. I believe it’s almost $20 for September. So it is unlike the natural gas side where the spreads, for example, between WTI and Houston are already set kind of pre in advance for the most part. And so, for example, for the remainder of this year, I think the spread is $19 to $20 for September, October, November, and December. So, any unhedged volumes, that’s what the prices that we’ll move it for.
Keith Stanley, Analyst, Wolfe Research LLC:
Okay. Thank you.
Marshall S. (Mackie) McCrea:
Yeah.
Operator: Thank you. The next question is coming 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 just wanted to ask another question on Mariner East 2. When that initial tranche of capacity comes on at the end of the third quarter coming up here, will those NGLs that go on that line which we assume they’re going to be exported or are there other markets that they’re going to go to?
Marshall S. (Mackie) McCrea:
It predominantly will be exported, but certainly there’s other markets for butane and propane in domestic markets.
Michael Blum, Analyst, Wells Fargo Securities LLC:
Okay. And then can you talk about just the latest on Dakota Access Pipeline, just kind of where you stand from a volume or utilization standpoint and how that’s ramping? That will be helpful, Thanks.
Marshall S. (Mackie) McCrea:
Yeah. As we said, we’re looking at expanding it. We hope to be able to do that in the near future. In the meantime, we’re averaging close like – in the hight 400,000. We’ve transported over 500,000 barrels. And we believe that we have the ability possibly to expand at least another 100,000 barrels as we complete our analysis, but we are averaging – we have averaged close to 500,000 barrels, maybe a little bit over 500,000 barrels a day recently.
Michael Blum, Analyst, Wells Fargo Securities LLC:
Okay. And then just to clarify from an earlier question, the full capacity on ME2, when will that be available? And then the ME2X will be – I think you said the end of Q3 2019?
Marshall S. (Mackie) McCrea:
Yeah. The next tranche will be by the end of third quarter or first part of fourth quarter for Mariner 2 and Mariner 2X. And then the final pipeline completion will be completed about a year later in the third quarter of 2020.
Michael Blum, Analyst, Wells Fargo Securities LLC:
Okay. Great. Thank you.
Kelcy L. Warren, Chairman & Chief Executive Officer of ETP:
And hey, Mike, we’re already line packing to let you know. We’re beginning to fill the lines. So, that kind of gives you an idea on ME2. And of course, you don’t do that until you get there where you got visibility to completion and we’re doing that.
Michael Blum, Analyst, Wells Fargo Securities LLC:
Great. Thank you.
Operator: Thank you. The next question is coming 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 questions around Dakota Access this morning. So you mentioned the 100,000 barrels a day of potential expansion capacity. Would a larger expansion be contingent on more southbound capacity maybe in the form of a cap line reversal?
Marshall S. (Mackie) McCrea:
No. That wouldn’t have – a cap line reversal wouldn’t have anything to do with our business out of Bakken.
Colton Bean, Analyst, Tudor, Pickering, Holt & Co. Securities, Inc.:
Okay. And so, ETCOP is sufficient to handle any incremental expansion or it’s just Midwest Refining Complex?
Marshall S. (Mackie) McCrea:
ETCOP will be able to handle the volumes that we’ve contracted to transport. Some of the customers find stopping at Patoka. But whatever we contract, ETCOP will be able to handle it.
Colton Bean, Analyst, Tudor, Pickering, Holt & Co. Securities, Inc.:
Got it. Yeah. And I guess just on the NGL transportation side, so volumes up fairly meaningfully despite the ME1 outage. Could you update us on where you stand with the remaining capacity on Lone Star Express in West Texas Gateway there?
Marshall S. (Mackie) McCrea:
You bet. The NGL segment has been just phenomenal. Our teams have done such a great job ever since we bought Louis Dreyfus, and kind of similar to other areas or other segments, we are looking at our capacity and it’s concerning us in regards to one or two years. So, at some point in the near future, we will be looking at expanding our Lone Star pipeline capacity. And so both frac and Lone Star capacity, we will be looking at that very closely to make sure that we have new loops and new pipelines built in sufficient time to meet our contractual obligations.
Colton Bean, Analyst, Tudor, Pickering, Holt & Co. Securities, Inc.:
Perfect. I guess just last one here, maybe tripling down on the discussion around intrastate and then some of the hedging aspects there. So it looks like your natural gas sales margin ticked up maybe $20 million on a Q-over-Q basis. But the year-to-date margin capture has been a little bit weaker versus what we see on the screen for Waha to Katy spread. So is that attributable to the hedging? I guess should we expect any of those hedges to roll off kind of similar to what you noted on crude oil over the next year and a half or so?
Marshall S. (Mackie) McCrea:
Yeah. And one thing that hit our intrastate segment, we did have a couple of customers whose volumes fell off and/or for example CFE didn’t use as much capacity as it did a quarter before. So, that kind of skewed the results, but, yeah, any kind of hedging that we have as it falls off over the next year or two, right now the spreads are much wider than what we’ve hedged, if that answers your question.
Colton Bean, Analyst, Tudor, Pickering, Holt & Co. Securities, Inc.:
Perfect. I’ll leave it there. Appreciate it.
Operator: Thank you. Our next question is coming from the line of Dennis Coleman with Bank of America. Please proceed with your question.
Dennis P. Coleman, Analyst, Bank of America Merrill Lynch:
Yes. Good morning. I wonder if I might just get a little more update on the Orbit JV. You said that there was an approval in China. And are you seeing any opportunities for expanding that or other opportunities like that?
Marshall S. (Mackie) McCrea:
Absolutely. We have teams working daily on not only expanding the capacity there, but also expanding Marcus Hook. In fact, a number of the customers are desiring to have both – kind of a hedge due to weather potential issues. So we’d be disappointed if we’re not announcing in the next year an expansion in our Satellite area of at least 150,000 barrels more. But we are putting a lot of emphasis with our teams on expanding our ethane and propane exports at the Gulf Coast and Marcus Hook.
Dennis P. Coleman, Analyst, Bank of America Merrill Lynch:
Okay. Great. And then switching back to the 30-inch Permian line, when you first started talking about this about some commercial commitments, any updates that you can share there in terms of building enough commercial commitments to make an official announcement?
Marshall S. (Mackie) McCrea:
Yeah. Here’s how to address that. There’s kind of a new phenomenon in our industry and that’s if you get enough guys together and find a little bit of money, you can make an announcement that you can build a pipeline. So we’re going to wait until we know we’re going to build that pipeline. So we’re certainly hesitant to say how close we are. But as was read by Tom earlier, we’re very optimistic of where we stand. There’s not a pipeline out there that’s anywhere close to the value that we provide for the customers and the shippers than ours with both East Houston and Nederland. So we’re very excited about that project and hope certainly before the next earnings call to be announced. And when we announce it, we’ll be building it.
Dennis P. Coleman, Analyst, Bank of America Merrill Lynch:
Great. That’s useful. And then maybe just one more for me. I think I’ve read the increased volumes on Panhandle and Trunkline were contracted capacity. Is that new contracts? And if so, can you talk about terms and tenors there?
Marshall S. (Mackie) McCrea:
You bet. It’s interesting because in the past, we used to kind of worry about questions about when contracts run out, what are we going to do. Well, on most of our systems, Panhandle and Trunkline being two of them, the basis is actually wider now and more profitable as contracts roll off. So we have seen the transportation value on Panhandle and on Trunkline increase over the last several quarters. We anticipate that to continue to increase. And then as everybody knows, as we ramp up Rover, that also adds revenue to both Panhandle and Trunkline on a backhaul basis.
Dennis P. Coleman, Analyst, Bank of America Merrill Lynch:
Great. Anything specific on contract length or anything like that?
Marshall S. (Mackie) McCrea:
Well, for example, on Rover, those are all tied to Rover. So those are all ten-year contracts. I believe that’s 700,000 barrels or 750,000 barrels. Typically, on Panhandle and Trunkline and even TW, those are typically two- to three-year extensions.
Dennis P. Coleman, Analyst, Bank of America Merrill Lynch:
Perfect. Thanks. That’s it for me.
Marshall S. (Mackie) McCrea:
You bet.
Operator: Thank you. The next question is coming from the line of Patrick Wang with Robert W. Baird. Please proceed with your question.
Patrick C. Wang, Analyst, Robert W. Baird & Co., Inc.:
Hey, good morning, everyone, and thanks for taking my question. Just wondering if we could spend a minute on Mexico. Can you refresh us on the latest volume trends on Trans-Pecos and Comanche Trail? Just wondering have you started to see any of the congestion relief on the Mexico side of the border with some of the new infrastructure that recently started up there? And then can you just give us a general update on your overall export volume expectations over the next year or so?
Marshall S. (Mackie) McCrea:
Yeah. As we’ve said, we’re putting a lot of emphasis on export wherever the commodity is. We expect our natural gas volumes to Mexico to increase. They have been slow in coming. I believe the total systems are moving around 100,000 barrels a day; however, with some activity out of Mexico recently on some RFPs that come out, we do expect those volumes to begin to increase in the second quarter of 2019 and grow pretty significantly from there.
Patrick C. Wang, Analyst, Robert W. Baird & Co., Inc.:
All right. That sounds great. And then moving back to Orbit, have the tariff discussions impacted your thoughts on timing at all?
Marshall S. (Mackie) McCrea:
No. The uniqueness of that project is we are selling ethane at the dock to Satellite and they will handle it from there. So we don’t see any impact on our partnership from tariffs related to China.
Patrick C. Wang, Analyst, Robert W. Baird & Co., Inc.:
All right. Excellent. Thank you. That’s it for me.
Marshall S. (Mackie) McCrea:
Around ethane.
Operator: Thank you. Our next question is coming from the line of Sunil Sibal with Seaport Global Securities. Please proceed with your question.
Sunil K. Sibal, Analyst, Seaport Global Securities LLC:
Yeah. Hi. Good morning, guys. Just a couple of clarifications. The leverage metrics 4 to 4.5x which you mentioned previously on the call, I just wanted to clarify that’s based on the agency calculation or is that mainly your covenant calculation?
Thomas E. Long:
No, that’s based upon the rating agency calculation.
Sunil K. Sibal, Analyst, Seaport Global Securities LLC:
Okay. Got it. And then when you think about your credit ratings longer term, you will clearly be BBB- kind of rating post the closing of the transaction. Is there a thought process to kind of work on further improving that versus kind of managing the shareholder returns?
Thomas E. Long:
As to the last part of your question, I’m not sure if I was able to hear – clearly here. Could you repeat that on the...?
Sunil K. Sibal, Analyst, Seaport Global Securities LLC:
Yeah. No, I was just trying to understand, is BBB- kind of the toll or intended to kind of improve it further versus returning capital to the equity guys.
Thomas E. Long:
No. Listen, we feel like the investment-grade, kind of the BBB- with a stable outlook is good. I won’t deny that if we ended up with – a company of this scale with strong coverage and strong leverage that we would love to see kind of a mid-BBB kind of a Baa2-type rating, so…
Sunil K. Sibal, Analyst, Seaport Global Securities LLC:
Okay. Got it. And then one bookkeeping one for me. How much capital do you have remaining for 2018 for spending?
Thomas E. Long:
Yeah, we’ve got a CapEx funding for 2018 of $4.5 billion. We did put a range this time in, $4.5 billion to $4.8 billion. And some of that is just some new projects, smaller ones that we’ve not just talked about yet. But so you’re probably looking at somewhere in that range, so we’ve given that as we look at 2018.
Sunil K. Sibal, Analyst, Seaport Global Securities LLC:
Okay. Got it. And then just last one, a little bit big picture for me. You’ve seen a fair bit of asset packets in the midstream space out there. And you guys will obviously kind of reload from a cost of equity capital perspective post the transaction closing. I was wondering if you have any thoughts on that in terms of what’s available in the market and also asset transactions versus corporate M&A, how do you see your appetite for that kind of next year forward?
Thomas E. Long:
Just our appetite for the M&A…
Kelcy L. Warren:
Yeah. Like we said on the last call, I believe and we believe, the market should believe that to correctly run these partnerships, you should mix the correct amount of M&A with organic growth. That’s been virtually impossible for us as a result of where our equity price has been trading. So we’ve really been out of that and we regret that. However, I’ll start with this and this is how we’re going to solve your question. The first thing to solve it is we must get to the credit metrics that we’ve identified, and we’ve made commitments to do that. And we are really confident and pleased with our ability to get to the 4.5x debt to EBITDA. Should there be an odd opportunity that would come our way that we feel like was so compelling, we would need to meet with the rating agencies and get their feel for what we’re thinking and why we’re thinking. Let’s say this asset was not only accretive, but it was also very strategic.
Then we’re not saying we might do such a thing. However, we’re not seeing any bargains right now. There’s not a lot of opportunities and I bet you everybody that you talked to would say the same thing. We’ve got – gosh, we got investment bankers selling assets to investment bankers right now. I mean that’s dogs and cats living together kind of thing. So we’re just going to study it and do our jobs and hopefully resume our M&A activity in the not-too-distant future.
Sunil K. Sibal, Analyst, Seaport Global Securities LLC:
Okay. Got it. Thanks, Kelcy. And that’s all I had.
Kelcy L. Warren:
Thank you.
Operator: Thank you. We have reached the end of our question-and-answer session. So I’d like to pass the floor back over to Mr. Long for any additional concluding comments.
Thomas E. Long:
All right. Well, listen, thank you all of you once again. I think you can kind of see how much excitement we have about the performance of our existing asset base as well as all the projects that we have coming online and of course moving forward with the consolidation of ETE and ETP. So, thank all of you once again for the support, and we definitely look forward to talking with you in the near future.
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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. ETE and ETP 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 unitholder approval and the satisfaction of the other conditions to the consummation of the proposed transaction, 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 ETE and ETP with the SEC, which are available to the public. ETE and ETP 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
SECURITY HOLDERS ARE URGED TO READ THE PROXY STATEMENT/PROSPECTUS AND THE REGISTRATION STATEMENT REGARDING THE TRANSACTION CAREFULLY WHEN THEY BECOME AVAILABLE. These documents (when they become available), and any other documents filed by ETP or ETE with the SEC, may be obtained free of charge at the SEC’s website, at www.sec.gov. In addition, investors and security holders will be able to 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 ETE or ETP at: 8111 Westchester Drive, Dallas, TX 75225, Attention: Investor Relations, Email: InvestorRelations@energytransfer.com.
Participants in the Solicitation
ETE, ETP 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 ETE is contained in ETE’s Form 10-K for the year ended December 31, 2017, which was filed with the SEC on February 23, 2018. Information regarding the directors and executive officers of ETP is contained in ETP’s Form 10-K for the year ended December 31, 2017, which was filed with the SEC on February 23, 2018. Additional information regarding the interests of participants in the solicitation of proxies in connection with the proposed merger will be included in the proxy statement/prospectus.