Energy Transfer LP (ET) 2018 Q1 法說會逐字稿

Greetings, ladies and gentlemen, and welcome to Energy Transfer's First Quarter 2018 Earnings Conference Call. (Operator Instructions) It is now my pleasure to introduce your host, Mr. Tom Long. Please go ahead, sir.

Thank you, operator. Good morning, everyone, and welcome to Energy Transfer's First Quarter 2018 Earnings Call. And thank you for joining us today. I'm also joined by Kelcy Warren, Mack McCrea, Matt Ramsey, John McReynolds and other members of the senior management team, who are here to help answer your questions after the prepared remarks.

I'll begin today with an overview of our most recent announcements, followed by a discussion of our latest developments on Rover, Mariner East 2, Permian Express 3, Bakken and other growth projects. Then I will turn our focus to a discussion of Energy Transfer Partners first quarter results, followed by a CapEx discussion, liquidity and funding update and lastly, a distribution discussion. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.

These are based on our beliefs, as well as certain assumptions and information currently available to us. I will also refer to adjusted EBITDA and distributable cash flow, or DCF, both of which are non-GAAP financial measures. You will find a reconciliation of our non-GAAP measures on our website.

Before turning to recent developments and a growth project update, I just want to start by saying that we are pleased by Energy Transfer's very strong first quarter. ETP's adjusted EBITDA increased by 30% and DCF attributable to the partners of ETP as adjusted also increased nearly 30% over the first quarter of last year, pro forma for the merger between ETP and SXL. 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 the midstream, NGL and refined products and interstate segments. I'm also pleased to say that last week, we received authorization from FERC to place additional sections of Phase 2 of Rover into service, which allows for the full commercial operation capability of the Market Zone North Segments. We expect construction of Rover will be complete this month.

As on ME1, last week we received a unanimous vote from the Pennsylvania Public Utilities Commission to resume operations on the pipeline. As a result, ME1 is back up and running. I will provide more detailed updates on our growth projects a bit later on the call.

Now turning to our most recent developments. We are pleased to say that on April 2, we closed our previously announced sale of our contract compression business to USA Compression Partners for approximately $1.7 billion, consisting of $1.232 billion in cash, 19.2 million USAC common units and 6.4 million Class B units. ETP used the cash proceeds to reduce the leverage, thereby strengthening ETP's balance sheet. At the same time, ETE acquired all the equity interest in USAC's general partner and approximately 12.5 million USAC common units in exchange for $250 million in cash. As a part of the transaction, pursuant to an equity restructuring agreement, the IDR's in USAC were canceled and the general partner interest in USAC was converted into a noneconomic interest in exchange for the issuance of 8 million new USAC common units to ETE.

Moving on to our growth projects. We have recently announced a few new projects that I will touch on first, then I'll provide an update on other major projects. In March, ETP and Satellite Petrochemical USA Corp. entered into definitive agreements to form the Orbit joint venture to construct a new ethane export terminal on the U.S. Gulf Coast to provide ethane to Satellite.

At the terminal, Orbit plans to construct an 800,000-barrel refrigerated ethane storage tank, a 175,000 barrel-per-day ethane refrigeration facility and a 20-inch ethane pipeline originating at our Mont Belvieu facilities that will make deliveries to the export terminal as well as domestic markets in the region.

ETP will be the operator of the Orbit assets, provide storage and marketing services for Satellite and provide Satellite with approximately 150,000 barrels per day of ethane under a long-term, demand-based agreement. In addition, ETP will construct and wholly own the infrastructure required to supply ethane to the pipeline and to load ethane onto carriers destined for Satellite's newly constructed ethane crackers in China. Subject to Chinese government approval, the export terminal is expected to be ready for commercial service in the fourth quarter 2020.

In April, we launched a binding open season for a pipeline that will transport diesel from Hebert, Texas to a newly constructed terminal in the Midland, Texas area. The [J. C. Nolan] diesel pipeline will utilize existing ETP pipelines, including the Lone Star 12-inch line, and is currently projected to have an initial capacity of 30,000 barrels per day. Minimal incremental capital is required to convert this line from NGL to diesel service, and it is anticipated that the pipeline will be in service in the third quarter of 2020.

And last week, ETP and Enterprise announced the formation of a 50-50 joint venture to resume service on the Old Ocean natural gas pipeline. The 24-inch pipeline, which originates in Maypearl, Texas and extends south 240 miles to Sweeny, Texas, has an initial design capacity of 160,000 MMBtus per day and resumed service in the second quarter of 2018. ETP is the operator of this pipeline.

Additionally, ETP and Enterprise are in the process of expanding our jointly owned 36-inch North Texas Pipeline, which will provide approximately 160,000 MMBtus per day of additional capacity from West Texas for deliveries into Old Ocean. The North Texas Pipeline expansion is expected to be completed by the end of this year.

Now for an update on our other projects, and starting with Rover. As a reminder, Phase 1a was placed into service on August 31, 2017, and Phase 1b was placed into service on December 15, 2017, allowing Rover to transport up to 1.7 Bcf per day. And last week, as I mentioned, we received approval from FERC to place additional Phase 2 facilities into service. This approval allows for the full commercial operational capability of the Market Zone North Segments, inclusive of delivery into Vector for delivery to the end users throughout Michigan and the Dawn Gas Hub. These latest approvals by FERC allow for approximately 75% of Rover capacity to be in service. Construction of the full project is nearing completion, all HDD crossings have been completed and we are progressing with final hydrostatic testing and tie-in work to achieve mechanical completion and expect to ask FERC to place the rest of the 3.25 Bcf-per-day project into service by June 1.

Now moving on the ME2 and 2X. We continue to make progress on the construction of ME2, with 98% of mainline construction complete and 93% of HDDs completed or underway. At this time, we expect to place ME2 into service in the third quarter of 2018. Construction on ME-2X also continues and we expect the pipe to be online in mid-2019.

Our Revolution processing plant is complete and we expect it to go in service once Rover has received full approval of all facilities.

Now moving to West Texas. The 200 million cubic foot per day Rebel 2 processing plant in the Midland Basin went into service at the end of April, and the plant is expected to ramp up through the remainder of 2018. Due to continued strong demand in the Permian, we are nearing capacity in both the Delaware and Midland Basin. As a result of this demand, we are building a second 200 million cubic foot per day cryogenic processing plant near our existing Arrowhead plant. And this plant is expected to be in service in the fourth quarter of this year. Also in West Texas, our Red Bluff Express 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, providing residue gas takeaway. We are expanding this project with an additional 25 miles of 30-inch pipeline, supported by a new long-term, demand-based contract we recently signed with an investment-grade counterparty. This new agreement effectively doubles the size of the commitments on the pipe. Red Bluff Express will now consist of approximately 100 miles of 30-, 36- and 42-inch pipe, and we will have a capacity of at least 1.4 Bcf per day with guaranteed fee-based, long-term commitments supporting the project.

Our anchor shipper is Anadarko, and their affiliate, Western Gas, has an option to buy into this project. Even with this addition, the project is still expected to cost just under $400 million. Red Bluff Express is expected to be online this month, with the expansion expected online in the second half of 2019.

On Permian Express 3, as a reminder, we successfully brought Phase 1 online in the fourth quarter of 2017, with additional volumes ramping up later this year. We continue to evaluate an additional expansion of PE3. We're also making significant progress with our new 30-inch crude pipeline from Midland to Nederland, which will now have extensions to more road and the Houston Ship Channel. We're developing an agreement with a strategic partner. The project is expected to initially transport up to 600,000 barrels per day of capacity, easily expandable to 1 million barrels per day. This new pipeline will provide unprecedented flexibility to the expansive ship channel markets, as well as to significant markets 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 deliveries into Bayou Bridge.

Next, on Bayou Bridge. On the 30-inch segment from Nederland to Lake Charles, we transported an average of 160,000 barrels per day in the first quarter. And build-out of the 24-inch segment on Bayou Bridge from Lake Charles to St. James continues. We expect commercial operations to begin in the fourth quarter of 2018.

Our Bakken Pipeline project went into commercial service under the committed transportation and service segments on June 1, 2017. We're very pleased to have this pipeline online, delivering domestic crude production to refineries in the Midwest and along the Gulf Coast.

Our earnings are already seeing a significant increase as a result of demand fees we're collecting. Q1 volumes continue to average over 400,000 barrels per day and we have already seen solid growth in the beginning of the second quarter, with peak volumes transported now reaching over 500,000 barrels per day. Lone Star's 120,000 barrels per day FRAC V is still expected to be in service in the third quarter of 2018. It 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 FRAC VI is expected 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, we expect significant volumes under an interruptible agreement to begin flowing later this month. Full take-or-pay commitments on the 400 million cubic foot per day 10-year agreement with Enable are expected to go into effect July 1. This will allow us to utilize idle pipeline and processing capacity in North Texas.

Now let's turn to our first quarter results. As I mentioned, ETP had another very strong quarter. Adjusted EBITDA on a consolidated basis totaled $1.88 billion, which was up $436 million compared to the first 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 in all our major segments. DCF attributable to partners as adjusted totaled $1.22 billion, an increase of $278 million compared to the first quarter of 2017, primarily due to the increase in adjusted EBITDA. ETP's coverage for the first quarter was 1.15x.

Turning to our results by segment, and we'll start with midstream. Adjusted EBITDA was $377 million compared to $320 million for the first quarter of 2017. This increase was primarily due to higher throughput volumes and higher NGL and crude prices. Gathered gas volumes totaled approximately 11.3 million MMBtus per day compared to 10.2 million MMBtus per day for the same period last year. This was primarily due to increased volumes in the Permian from the ramp-ups of both the Orla and Panther processing plants and growth on the Ohio River system in the Northeast. NGL production totaled 503,000 barrels per day compared to 445,000 barrels per day for the first quarter of 2017. Equity NGLs were 28,000 barrels per day for the first quarter of this year compared to 26,000 barrels per day for the same period last year.

In the NGL and refined products segment, adjusted EBITDA increased to $451 million compared to $381 million for the same period last year. The increase was due to higher transport volumes on our Texas NGL and Mariner West pipelines, increased throughput at the Lone Star fractionators and higher results from our optimization and marketing group. NGL transportation volumes on our wholly owned and joint venture pipelines were 936,000 barrels per day compared to 816,000 barrels per day for the same period last year, due to increased volumes out of the Permian Basin and on the Mariner West and Mariner South pipelines, partially offset by decreased throughput on ME1 due to the system downtime in March.

Refined products transportation volumes on our wholly owned and joint venture pipelines were 620,000 barrels per day compared to 624,000 barrels per day for the same period last year, primarily due to lower volumes from Midwest and Northeast refineries, partially offset by increased throughput from the Southwest region. Year-over-year, average daily fractionated volumes increased to 472,000 barrels per day compared to 433,000 barrels per day last year, due to increased volumes from Permian producers.

Now looking at the crude oil segment. Adjusted EBITDA increased to $464 million compared to $187 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, an increase from the crude oil acquisition and marketing business related to favorable basis differentials between Midland and the Gulf Coast and higher ship loading and throughput fees at our Nederland terminal due to an increase in exports.

Crude transportation volumes increased to 3.8 million barrels per day compared to approximately 3 million barrels per day for the same period last year, primarily due to placing the Bakken pipeline and Phase 1 of Bayou Bridge into service as well as increased production from the Permian Basin. Crude oil terminal volumes increased to 1.9 million barrels per day compared to 1.8 million barrels, primarily due to growth at Nederland.

In our intrastate segment, adjusted EBITDA increased to $192 million compared to $169 million in the first quarter of last year. This was primarily due to an increase from commercial optimization activities due to wider basis differentials from West Texas to the Gulf Coast.

Transported intrastate volumes increased due to higher demand from exports to Mexico as well as the addition of new pipes to our intrastate system and more favorable market pricing. Although we continue to expect volumes to Mexico to grow, volume growth is anticipated to be slower than originally anticipated, but all capacity is contracted under firm transportation agreements. In the meantime, we have seen an increase in third-party activity on both of these pipes, mostly via backhaul services we are providing to the Trans Pecos header.

In our interstate segment, adjusted EBITDA was $323 million compared to $265 million for the first quarter of 2017. This increase was primarily due to additional EBITDA of $49 million from the placement of a portion of Rover into service. We expect earnings in this segment to continue increasing once the remaining sections of Rover are in service and we're able to efficiently provide end-user customers with Marcellus and Utica gas. Interstate transportation volumes were 8.2 million MMBtus per day compared to 5.7 million MMBtus per day for the same period last year due to an increase of nearly 1.5 million MMBtus per day from bringing a portion of Rover into service as well as an increase from the Tiger pipeline due to production increases in the Haynesville Shale.

Moving on to the all other segment, which includes our equity method investment in limited partnership units of Sunoco LP. On February 7, Sunoco repurchased approximately 17.3 million Sun LP units from ETP for $540 million. As a result, our current ownership of Sunoco LP consists of 26.2 million units, representing 31.8% of Sunoco's total outstanding common units. Adjusted EBITDA was $74 million compared to $123 million a year ago, due to a $30 million decrease in earnings from our investment in PES and a $25 million decrease from our investment in Sunoco LP, primarily due to the Sunoco LP sale of retail assets to 7-Eleven as well as its repurchase of 17.3 million common units in February 2018, partially offset by an increase from commodity trading activities.

Now moving on to a CapEx update for the 3 months ended March 31, 2018. ETP funded approximately $1.2 billion in organic growth projects, primarily in the NGL and refined products segment. For full year 2018, we expect to spend approximately $4.5 billion on organic growth projects, primarily in the NGL and refined products, midstream and interstate segments.

Taking a look at our liquidity position and funding strategy. In April, ETP issued $450 million of its 7.375% Series C fixed-to-floating rate cumulative perpetual preferred units. The securities provide an extremely cost-effective means of raising equity capital, and ETP used the proceeds to repay amounts under its revolving credit facilities and for general partnership purposes. Like the Series A and B perpetual preferred units issued in the fall, these securities also received 50% equity treatment from all 3 rating agencies. As of March 31, 2018, total liquidity under ETP's revolving credit facility was approximately $2.09 billion. As of March 31, 2018, ETP's leverage was 3.89x for the credit facility. Pro forma for the $1.232 billion in cash received from the USAC transaction, which closed on April 2, and the preferred unit offering of $450 million, which also closed in April, liquidity would have been approximately $3.8 billion.

Next, I'd like to touch on our recent distribution announcement. In April, ETP announced a distribution of $0.565 per common unit for the first quarter or $2.26 per common unit on an annualized basis, which we paid on May 15 to unitholders of record as of the close of business on May 7. This distribution is flat compared to the fourth quarter of 2017. Even with ETP's great first quarter and the contribution from our major projects coming online, we felt that with ETP's current cost of equity, it was prudent to continue to hold the distribution flat compared to prior quarters in order to retain excess cash flow to fund the equity component of our growth projects and continue to reduce our leverage.

Before I turn to ETE's results, I want to briefly touch on the recent FERC tax proposals. As we have previously stated, FERC's proposal to no longer allow interstate pipelines owned by MLPs to recover an income tax allowance in the cost of service is not expected to have a material impact to our earnings and cash flow. The vast majority of our rates are negotiated arrangements, rate settlements or discounted rates that are below maximum tariff, which we believe would not be subject to adjustments or impacted by change to the maximum tariff rate.

Regarding our crude systems, a substantial portion are subject to long-term contracts, including index-based contracts with protected settlement rates. We are encouraged by the current conversations with FERC. Although there is a potential for these rates to be challenged and it is early in the process, based on the information we have today, we still do not expect any material impact to ETP's earnings.

Now moving on to ETE. I'll begin with ETE's first quarter results, followed by a liquidity and financing update. For the first quarter, ETE's distributable cash flow as adjusted totaled $395 million. ETE's coverage for the first quarter was 1.48x, which will allow ETE to pay down over $125 million in debt with the excess coverage. And just briefly touching on ETE's distribution, in April, 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 May 21 to unitholders of record as of the close of business on May 7. Our decision to hold the distribution flat represents ETE's commitment to improving our consolidated leverage metrics.

Briefly looking at liquidity and the financing update. 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 March 31, 2018, there was $873 million in outstanding borrowings under ETE's revolving credit facility.

Before opening the call up to your questions, I just want to say that, once again, that we're very pleased to have kicked off 2018 with a strong first quarter across all our major segments. The contributions from the Bakken crude oil pipeline and the portions of Rover that are now in service contributed to the strong first quarter results, and we continue to make progress toward improving ETP's leverage metrics.

Our continued strong results are accelerating our deleveraging and further reducing our need for outside equity. Looking ahead to the rest of 2018, we are excited for the additional growth expected as we complete Rover, ME2 and our other growth projects. Our recent growth project announcements further demonstrate the strong position of our assets and our strength in generating both domestic and export projects going forward.

Our construction and engineering groups remain committed to working closely with FERC, the PA PUC, PA DEP and other regulatory agencies. We are focused on safely and responsibly starting up and operating Phase 2 of Rover, ME2, Bayou Bridge and all of our other projects.

At ETP, we remain firmly committed to our investment-grade rating, and at ETE, the priority remains supporting its operating subsidiaries.

With that, operator, that concludes our prepared remarks. Let's go ahead and open the line up for questions.

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

I was wondering if we can start off with a rating agency question. Clearly, they've been the gating issue on the simplification process. I was just wondering if there's been any conversations about, once the projects are fully up and running with Rover and Mariner East 2, will you be able to get trailing credit for the EBITDA that's in service, so that you can simplify earlier?

Yes. Listen, Shneur, that is probably one of the very commonly asked question, and absolutely, we continue to have discussions with the rating agencies. And that's not one of those that's necessarily an exact science as to how that will work. I will tell you that when you have the ramp-up we have in EBITDA, in other words the EBITDA catching up with all the funding we've been doing on these projects, clearly it is one that we will always talk to the agencies about, meaning taking the current quarter and annualizing it. Because remember the nature of these projects, they are good fee-based-type projects. They're -- good contracts on them, et cetera. So all those are very positive, and that's the reason why you can take a current quarter and annualize it. But absolutely, answering your question very directly, we do continue to have conversations with the agencies and we will continue to look at how we can accelerate the process. So...

Okay. Fair enough. Just switching to CapEx expectation. So it seems like you're kind of leaving it flat for 2018, but at the same time you're talking about a greenfield project. Once you FID this big crude project, would there be any spend in 2018? And is there any sense of the size of spend that we could be talking about?

No, there'll be -- if there's any, it's going to be a very immaterial amount. So that's the reason you see us keep the spin number, the funding number at $4.5 billion. So very little in 2018.

In terms of the total spend, once you FID it?

Yes. This is Mackie, and we'll talk about this probably a little later with other questions. But we're really excited about that project. It has kind of taken a turn for the good in that it doesn't -- will not provide only Nederland, but will provide access to the ship channel market. So we're still finalizing the exact nature of it. Of course, the customers -- and there's a tremendous amount of interest in kind of a new project. And once we have finalized that and are contracting with customers, we'll be able to finalize the CapEx.

Okay. And one final question. I was wondering if -- I'm not sure if you're able to, but is it possible to discuss your interest in NuStar and how you see this strategic operational fit into the Energy Transfer family.

Yes, this is Kelcy. As you know, we sent a letter offering to acquire NSH, and as you know, the company responded saying that they were not interested in that, and then we followed up to provide some more clarity in a letter. We think the assets fit us extremely well and we think more money could be made from those assets, not a reflection on anybody's management team, but rather just the complement of the assets with ours across the family. We have made it very clear to management of NuStar that we would not do anything hostile, but we did want to strongly express our interest and we have done so. They don't agree with us that this is a better alternative for them, which I respect their right to that opinion, and that's where we are.

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

I was hoping just to start off on the midstream side. The results came in just a little bit below what we were looking in quarter-over-quarter there. So I was wondering if you could provide a bit more color as far as producer activity behind your systems and kind of the really big growth you see in the Permian versus some of the legacy areas that don't see quite as much activity and kind of how you see that balancing out over the balance of the year here.

Okay, this is Mackie, again. Yes, if you look at midstream, quarter-over-quarter, we're up 1 Bcf and our EBITDA's up $58 million, so not a bad quarter-to-quarter. Our volumes are down a little bit from the fourth quarter, mainly because we had pretty significant weather that affected our -- that affects our G&P business more than anything else. And we've had also in South Texas some slow down with a few of our larger producers. But, by and large, our volumes are growing, they're growing significantly out of the Permian. We're just trying to stay ahead of it, and it's difficult to stay ahead of the volume growth. And so we're really pretty pleased with how the quarter went considering some weather impacts and looking at the results.

Got you. And then, if you think about Permian production growth here and the wider differentials, both on the gas side and the oil side, I was wondering if you could provide some kind of goal posts or any rules of thumb as far as a differential spread, a certain amount, what that can translate into your business. Or just anymore color as far as what -- how these benefits could shape up for you guys over the balance of the year?

Okay. It is a Mackie, again. Yes, it's interesting because for the last 4, 5, 6 years and even as much as a year ago, we've had capacity both on the gas and the crude side across the state and it hasn't been a lot of fun. The spreads have been 0 to very little and we've kind of weathered the storm. And so we couldn't be more pleased with where we sit today. We have not only available capacity that we've been selling and aligning with customers that need it, but we're also aggressively expanding not only Oasis by over 100,000 a day, but the announcement on Old Ocean and NTP by another close to 100,000, our share. So we're doing everything we can to not only maximize our margins and revenues on our existing capacity, but also increasing our capacity where it makes sense.

That's helpful. And then maybe just last one, as far as the structure and anything new you could say there or refresh us per your thoughts as far as how you see eventual family simplification down in the future. And I guess, most importantly, do you see a C corp as something that could really be additive to the family and open up kind of the shareholder base there?

Yes, this is Kelcy. I'll start with the second part of that question. We are evaluating a C corp structure within our partnership. We are very, very carefully evaluating that. We do not want to do something that is irreversible and something that we would regret. So that is something we are studying. As far as the simplification that you referred to, it would most certainly be a structure whereby ETE acquires ETP. There's -- we've looked at every scenario possible to us, and we don't see any mathematical scenario that makes any sense other than that one.

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

Just following up on the Midland-to-Nederland project, when do you anticipate having an update on the size and scope of the project? And do you anticipate it to be part of your Permian JV?

This is Mackie again. Certainly, on a daily basis, we're looking at expanding our Permian Express system. We're -- fourth quarter this year, we're bringing on another portion, as everybody knows, that's demand-based. And as part of that, we also have a fairly sizable volume that we'll go out for an open season on here in the next month or so. That'll start in October, November. In addition to that, we evaluate constantly expanding Permian Express 3, even as of today, we have kind of some updates that it may make sense to move quicker on that, to provide capacity quicker than any new project, even our 30-inch. And we're looking at that. It wouldn't be a material amount of capital to create some capacity, so we are continuing to work with Exxon, our partners, to expand that partnership. But at the same time, we're certainly focused on getting this 30-inch. There's a lot of projects out there, but, golly, look on paper and look at what our 30-inch is offering. We'll be very pleased to announce a strategic partner, we hope, in the very near future. And we do anticipate there possibly could be some other equity partners. But if you look at the project, it's just, golly, you get to anywhere in the Houston Ship Channel, south of Houston, all the refineries markets, Nederland. Like Tom already said, it's just unprecedented market access and flexibility and we're really excited about the new project.

Appreciate the color. And just to verify, you expect as of now, the project destinations to be the Houston Ship Channel as well as your Nederland terminal?

Yes.

Okay. And then on time frame, would this be more of a 2020 project?

Yes.

Okay. And then moving on to Mariner East 1, looks like the impact was about $6 million of EBITDA in March. Is that sort of a reasonable assumption for April? And how do you anticipate volumes ramping back up in the second quarter?

Yes, in answer to your question. In other words, you can see kind of the monthly impact there. So I think you could probably see that about the same from that standpoint.

Let me add. Yes, we are ramping up Mariner 1 now and we are going to be testing kind of the upper limits on it as time goes on. So we think the volumes will actually increase in the future, higher than where they were when they went down.

And then on Mariner East 2, any -- can you elaborate a bit on when in the third quarter you expect the project to enter service, and has the delay impacted costs?

Well, I think -- this is Matt. I think the delay certainly impacts cost, as it always does. But I don't think it's materially impacted the cost.

And then in the third quarter, early, mid, late, is your expectation?

Yes, sir. Oh, I'm sorry, I thought you said mid to late. Yes.

Mid to late, okay. And then the last one for me on the distribution. Certainly pausing distribution growth at ETP makes a great deal of sense, as you've done. For ETE, curious if you expect the pause to continue for the rest of the year. Or is it just more of a quarter-by-quarter decision?

You know that -- we always want to say that's a quarter-by-quarter decision. I can't highlight enough the fact that preserving cash and deleveraging, how important that is, but that is one of the factors that goes into the discussion every quarter as we look at it. But -- so let's -- we're not trying to give any type of guidance here today or anything else, but it is -- let's leave it at as a quarter-by-quarter decision.

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

I'm wondering if you can just clarify one thing. So as it relates to this Permian pipe project that you're developing, which seems like a large project. And then you've got Permian Express 3 Phase 2 potential. Are those -- is there any connection between them? Meaning, can you -- can we still move forward with Phase 2 on Permian Express 3, regardless of this larger project? And I guess, given where the spreads are, is there a reason that, that isn't moving forward?

This is Mackie again, Michael. Yes, they absolutely both can go forward. And probably the way we'd separate them out is the -- expanding Permian Express 3 to the next phase is much quicker. It's probably half as long as the large pipeline will take. So kind of just speed to market is important. There is a massive just difficulty of getting barrels out of West Texas. Most of the big producers now are looking at rail and truck over the next year to 2 years until another big project comes online. So Permian Express 3 expansion has become a much more important quicker, so we do see those both as moving forward. But we'll continue to evaluate the timing, cost and the size of the next Permian Express 3 expansion. But we do anticipate it will happen.

Okay. And then do you have an estimate of the cost of this ethane export project that you announced this quarter? And is that already reflected in the $4.5 billion CapEx number?

Yes, this is Tom. I'll answer that, definitely the second part of that. But yes, it is included into -- in the $4.5 billion funding for this year. So...

Okay. And then, I guess, last question for me. As it relates to simplification, when it happens, can you just comment on kind of where Sun fits into all that? Does that also get rolled up? Or how do you see that?

Michael, this is Kelcy. No, it does not. Sun -- we're very pleased with what we're seeing at Sun as far as what -- the growth that they will be directing that MLP into. And as you know, Sun is younger in the IDR life. And they will get the support from ETE -- or the merged ETE and ETP, they will continue to get that support. But for the reasonable future, we don't see that being rolled up, no.

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

Mackie, if I can go back to the Permian. As you guys look at leveraging your scale and putting more barrels into Colorado City and then to hit Corsicana, with or without NuStar, does it never make any sense for you guys to start thinking about moving those barrels from Colorado City, staging them and moving them south into Corpus or possibly Corsicana south, so that way you're offering producers a slightly different downturn optionality, maybe hitting the water at a different point and just having more of a path-of-least-resistance-type scale footprint?

Yes, great question, Darren. Absolutely we're looking at that. As we've always said, we don't go out and say, okay, this is what we're going to do. We ask our customers, where do you want to go? And certainly, there is desire. Some of the projects have already been announced, they're going. A lot of the projects may or may not go. There is a desire to get to Corpus and the Gulf Coast. And we are not only looking at new lays that direction, but also possible utilizing existing pipelines and repurposing them for those -- for that business. Our focus right now though is the 30-inch to Nederland and Houston. We think it has the most viability, the most flexibility and the best kind of netbacks for the producers with the market access. But we will continue to look at, listen to our customers and very likely look at doing something to the Gulf Coast, to the Corpus area.

Okay. And then if I could switch over to Red Bluff Express. With that connecting Orla into Waha, I think Red Bluff brings what, like 1.4 Bcf into the header. I know that you guys can add more compression. So how do you think about, as we've talked, the gas converging on Waha, maybe scaling Red Bluff up further and possibly different outlets for that gas versus moving it just west?

Yes. Another project, Luke Fletcher did a great job on expanding it. Originally it was smaller. It was expanded, as we said, to -- now we're up to 1.4 Bcf. That kind of ramps up through time, so there's plenty of capacity for others that we're chasing. Tremendous volume growth and we don't really have an answer right now to what happens downstream. With the other project that's coming online in 1.5 years, that's going to help alleviate it. But I guess what we love about the project is, not only are we making accretive rates on new capital to Waha, but also we provide the most flexibility into Waha. We can go back in the TW to the West United States. We can go to Katy. We can go to, of course, Mexico. We can go to multiple pipelines, intra and interstate, at Waha. So who knows where that gas will ultimately go and how jammed up it will be over the next year or 2. But we'll certainly play a big role, both getting it to Waha and getting it out of Waha.

Okay. And then last question for me. Kelcy, just back on simplification for a minute. Was it ever in the thought process of consideration, when you're thinking about evaluating a C corp structure in the family of companies, that you would look at ETP's depreciated asset basis, and from a taxable perspective, obviously, any sort of step-up with ETP would create a significant amount of tax depreciation that could be amortized for many years? Or is it simply more of a partnership equity and equity swap with ETE, and there is no taxable liability coming from that simplification?

Both. You are correct. We have looked at -- we've -- just every way we know to look at a C corp-type solution for us. And we've not just said that we will not be doing that. It's just that this time, that does not appear to be the superior solution for us. So we have looked at that, to answer your first part of the question. And of course, in the next part of your question, taxes influence our decisions here. They're a very big component for our unitholders to deal with. So that is a reason that we've ended up where we've ended up. I say ended up, that's not fair. Today, if we had to make a decision today, we believe a simple purchase by ETE of ETP would be the structure. That could change by the time the rating agencies give us the green light to go forward.

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

So you noted some hedges in the crude oil segment as partially offsetting some of the marketing gains there. Can you just provide a little bit of disclosure on the nature of those hedges and maybe the term as well?

Yes, listen, this is Tom. I'll start off here and then we can be expansive. But clearly, we have hedged a portion of the -- kind of the basis that we've all seen. Those are really at various prices on both the gas and the crude oil side. You'll probably see some mark-to-market, because those were done kind of earlier in the quarter. But we still have significant upside that we've not locked in on some of this during Q2. So we're going to continue to look at that as we move forward, as far as what level really makes sense there as far as hedging.

Okay. So you mentioned Q2 you've got some capacity available. So does that imply that the hedges are really short term in nature and don't necessarily extend through 2018 and 2019?

This is Mackie. No we have hedges that extend. It's very difficult to hedge crude as compared to other commodities. But no, we do have volumes hedged for the next year, 1.5 years. But it's more heavily hedged this year and the first quarter of '19 and then less hedged out. But we have -- we're trying to be prudent. We're trying to lock in where it makes sense, but we're also looking at the market and where we think the market may go and where basis may go, and we're basing our decisions on future hedging with those analyses.

Got it. And just a related question there. So Trans Pecos and Comanche Trail arguably have the most spare capacity headed out of the basin. What are you guys seeing in flows currently? And is there any likelihood of that actually stepping up before year-end here?

Those volumes have been low compared to where the capacities are. There are volumes going to Mexico. It varies. It could be 100,000, 100,000-plus a day. Some days it may be that much or more backhaul back into it. But we do see slow volume growth. We see more of an opportunity of backhaul growth to the header system, and of course, ultimately a lot of that getting into our intrastate, interstate markets. But that's a demand-based business, so any incremental volumes backhaul is, of course, incremental revenue, but we're guaranteed the revenues on all the forward-haul regardless of what flows or not.

And I guess just to switch gears over to Old Ocean. The 24-inch diameter would seem to imply a significantly larger capacity than the 160. So is that constrained primarily by North Texas? And then I guess, you mentioned projects like Wildcat. I mean, is there any potential for some of that MidCon gas to find its way down to the Gulf on Old Ocean?

The pipeline, yes. It's 24-inch and it's limited by the MAOP. So there's operating conditions that we have to operate under based on the diameter and the type of steel and all that. So we're somewhat limited there regardless of the size. As far as the origin of the volumes, any volumes that can reach the Fort Worth Basin, our Maypearl or Cleburne points or other points in the Fort Worth Basin will be able to access Old Ocean, and then, of course, ultimately through Old Ocean to Katy and the ship channel through us.

Great. And I guess just a final one. So Rover, you highlighted an EBITDA contribution of about $50 million on the partial in service. Given the existing operating expense and G&A, and then you've started up Market Zone North here, which my understanding is that has the highest tariff on the system, should we see an expanding market or -- sorry, expanding margin over the balance of the project?

Absolutely. Our volumes will continue to grow as we get the phases approved or, as we've said, we hope all phases are approved here in this month, and we're fully online June 1. In addition to that, we've been flowing limited volumes south down into our Trunkline system. Once Rover is fully up and running, we'll be flowing instead of a couple of 100,000 a day, up to 750,000 a day. And that's demand-based new margin for our partnership. So absolutely, as Rover comes to completion, our revenues will appreciate significantly.

Okay. And so in terms of G&A, probably a more muted increase there versus what you're seeing on the revenue front?

Yes. That's correct. This is Tom.

Our next question comes from the line of Dennis Coleman with Bank of America Merrill Lynch.

I want to maybe take another swing at Orbit, and just make sure we have all the details we can get. I guess it's -- don't have an official JV yet, is that -- do I still have that right? Has there been any progress on that? And should we think about this as a 50-50 joint venture? Or I guess, any additional details you can add there?

Yes, this is Mackie again. What -- another project we're really excited about. As the country, especially Texas, continues to grow ethane at astronomical levels, there's got to be markets outside of just the U.S., and so we're really excited about the project. We're also excited to team up with such a large company as Satellite, who already has a lot of business lines around cracking, and we're very pleased to be teamed up with them. The partnership, the way it works is that we will have a JV on the chiller and the tank and the pipeline. That's the approximately 53% that we will own. And then outside of that, we also have fee-based business related to Mont Belvieu, storage and through terminaling in our dock. So the partnership just owns the pipe, chiller and tanks. And then we have other fee-based parts of that business that are downstream and upstream of that system.

Okay. That's helpful. And then the Chinese government approvals, can you just explain a little bit about what they need to approve? Or I guess that's on the Satellite side?

Yes, it's interesting because when we went to China and actually signed the deal, we were told that they thought they'd get expedited approval. And then our president kind of lofted in some tariffs. So that's kind of changed things a little bit. We still think it's going to be approved. Things can take a little bit longer as everything kind of gets worked at around tariffs, but we believe in the next 60 days that will receive approval. And our understanding is there's going to be 3 or 4 that will receive it, and they're certainly in the top 3 or 4.

Great. Great. I guess, maybe if I can switch gears a little bit to the simplification and just dig a little bit in terms of -- Kelcy, maybe what you have mentioned about not viewing the C corp as the winning strategy right now. I wonder, just one angle on that with all the FERC action lately, there's been a real seeming come back to C corp trend in the industry. So how does that -- how do you factor that in? And how do you still end up sort of with the more simple ETE, ETP strategy?

Yes, well, fundamentally, I just don't -- it's hard. You start with a problem and you identify the knowns and you solve for the unknowns, and one of the knowns here is you pay taxes twice. So you're disadvantaged in a C corp structure. What is the advantage? Well, there's many advantages of being in a C corp, including a broader market that you could offer your equity into. That's the part that we are really studying hard. If it appears that when you weigh in those factors, when you weigh in the tax drain that you would ultimately have, not just the first couple of years as many partnerships state -- I mean, life goes on past 2 years. You got to think about it long term. When we weigh all those in, it's right now, I don't like the answers we're getting. But again, this is something that Tom Long, Brad Whitehurst, Tom Mason, many others have that they -- this is something that every day in our office, we are modeling and looking at every alternative, as you might expect. We have banks that are doing that for us as well. Unsolicited, by the way. And so we're not absolutely punting on a C corp structure, we're just saying at this time, if we have to pull the trigger today, it would be a more simple-type structure of E buying P.

Okay. Thanks for that additional color. Then just the last one for me. Volumes on Tiger out of the Haynesville really got a nice pop. Can that continue to grow there? Or do you expect a continued volume strength there?

Yes, absolutely. Well, some of our biggest shippers have called recently and asked how much of the capacity is available and at what rates it will be. So as you know, forward haul, we sold that out for a term, a lot of that, but we are looking at volume growth -- significant volume growth in the Haynesville, both with a desire to go east on Tiger and a desire to come west back into Texas.

Our next question comes from the line of Jean Ann Salisbury with Alliance Bernstein.

How much Lone Star NGL capacity will be removed from doing the diesel project that you mentioned on the call?

How much Lone Star capacity will be removed -- I'm sorry, could you ask that again? I'm sorry.

You said that you were doing a conversion, maybe I misunderstood, but to do the diesel project on Lone Star. Does that mean that Lone Star NGL capacity is going away?

I'm sorry. I didn't hear diesel. No, it's the 12-inch pipeline that we're very excited for finding a purpose with in the open season, going exceptionally well. That's a project that when we built the 24-inch across Texas, the 24- and 30-inch, we idled the 12-inch pipe. We continue to look for uses for that pipe, because it's in great shape and we can use it for any number of commodities. And we decided to put it into diesel service. So that's an idle pipe that's creating no revenue that we hope, a year from now, it's creating significant revenues.

Great. That helpful. I believe on the last call, you mentioned something that Energy Transfer was marketing some of the Lake Charles cargoes. Did I hear that right and does that mean that Shell is paused on the marketing them at the moment?

On the LNG project?

Yes.

Yes, this is Tom Mason. We're continuing to work with Shell, and -- but we are not marketing yet, I mean, in terms of -- we are in the marketing process, if that's what you're asking. But yes, we're very excited about the project. We have an MOU, as you know, with Kogas and Shell. We continue to work with them. I think you know that the market dynamics are shifting. The studies have shown that the supply and demand lines will cross, and beginning in 2023 and '24, there should be a storage in long-term LNG supply as compared to projected demand over the next 10 to 15 years. So if you think about the construction time of 4 years or so to build a project like this, we're really in the right position now over the next 12 months to seriously market the project. And we had a team that was over in Korea and China 2 weeks ago, and we had a very positive response to our project. They liked it. We've got 2 really good partners. Kogas is the second-largest importer of LNG in the world and Shell is the largest worldwide marketer of LNG. So we think our project is going to be very cost competitive. And just primed to really commence the -- move forward on the marketing in earnest. So we're very excited about it.

Really helpful. And then one last quick one. Is there any customer walkaway or renegotiation point in 2018 for Mariner East 2 if it's not in service by any certain date?

Yes, we typically don't get into the kind of the heart, for competitive reasons, of what our contracts say.

Our next question comes from the line of Eric Genco with Citi.

I just want to come back to the NuStar issue for a quick minute. I think you said in your comments that you weren't interested in sort of taking on a hostile sort of situation. But I thought I read somewhere in their filings that you had expressed an interest in doing the deal without support of their major shareholder. So I guess my -- a couple questions would be also, I guess, a few months ago we had asked and talked about your appetite for deals unless the perfect opportunity fell in your lap. So I was just trying to better understand that. Is there something I'm missing in terms of, would a hostile deal still be on the table somewhere? And what kind of comments you can give us on that front?

No, no hostile deal would not be on the table. What we did in our letter -- our subsequent letter, that was a follow-up to a letter we received from NuStar stating that we had asked for support of a major shareholder and -- in our letter. And so we sent a letter back clarifying that, that would not be required, that this was open for all the unitholders to decide if in fact they chose this alternative. But I want to just emphasize, we made this clear to NuStar management as well. We -- again, we will not be pursuing any kind of hostile action on NuStar.

Okay. And then I guess, one other one, and maybe this is just kind of taking a step back overall, but you talked in the past about sort of the persistent discount that some of the -- that ETP, in particular, has kind of received in the market. We'd done a report a while back that was that -- on corporate governance and seeing a pretty strong correlation to a handful of metrics. And the top 3 or 4 things that kind of generally push for better performance of the units were no IDRs, total shareholder return metric tied in, incentive compensation, return on capital targets rather than EBITDA growth, and the ability to vote the board. I think your comments on the potential collapse and how that might look -- obviously, that's a huge thing, and thank you for those. But I was just curious, is there any sort of interest or thought about addressing some of these issues? Or maybe adjusting corporate governance going forward, if the discount persists?

Yes, on the compensation you referred to, yes, we have our Head of HR that is reviewing that now. Return on capital, all these things are being examined. We're studying what other people are doing. And I think it's safe to say that we will be modifying our compensation to our management. On the governance issue, absolutely not, under no circumstances ever. This will not be a wishy-washy answer. You will not see our governance change.

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

Sorry to beat a dead horse on simplification, but do you -- under the structure you're seeing as more likely with ETE buying ETP, do you see it as more difficult to get the rating agencies to upgrade ETE to investment grade if it's structured that way? Or is that different than if it went the other way and you just had to maintain investment-grade ratings at ETP?

Listen, this is Tom. It's probably a little bit early to give you a definitive answer on that. But I'll go ahead and give you -- at least give you my opinion here on this. Our opinion, as we look at it here, is that it's not. In other words, from a rating agency standpoint, going this path, we feel like is probably the most favorable from a rating standpoint. Obviously, keeping investment-grade rating. I'm being repetitive on that, but that's obviously very, very important to us, so...

Okay. And then one quick one on the crude marketing. So crude marketing was up, I think it was $85 million year-over-year, and spreads were only a few dollars better, if you look and compare the periods. Can we apply that type of ratio over the balance of the year in terms of looking at what the difference was in spreads and the magnitude of the uplift you saw in Q1? Or was there anything unusual in the quarter that led to results being that good?

This is Mackie. We typically don't give guidance, but let's just say that we're -- we couldn't be more excited about where spreads have gone, where WTI Midland has gone and the widening of that basis is just -- almost historical widening of basis will certainly help improve our margins in the coming quarters.

Our next question comes from the line of Ethan Bellamy with Baird.

How long do you expect the Permian differentials to remain wide? And relatedly, Kelcy, you said in the past that the industry always overbuilds. Is that likely to happen in the Permian in a few years, based on all the projects that are in development?

If we can find a person that can answer that question, we'll have a new probably CEO of our partnership. Yes, I'll tell you, it's -- who would've thought a year ago, when there was a spread from Midland to Nederland of $0.25, that, that would be some days as much as $12 to $14. And it's only going to exacerbate itself with the tremendous volume growth of crude in the Permian and Delaware the coming 12 months. So we don't know where it's going to go. As you can imagine, Greg Mills and his team and Jim Malott and Luke and their teams are constantly analyzing with our financial people and doing all kind of studies on where do we think bases are going. Truly, the market believes there's going to be a shortage of gas and crude space over the next 2 years. You see it in the basins. There are some that believe it could extend out 5, 6, 7 years. By the time you get 2 years down the road, the volume's already grown to such a degree that it continues to be a problem. So as long as commodity prices stay up, we're excited about where the base is now, where it will be for at least the next couple of years. And who knows? But we certainly look at that daily and constantly and make decisions based on where we feel the basis will go.

And let me add. Mackie, he just answered the previous question about corporate governance.

With a potential go-private transaction in the works at Boardwalk, do you have any interest there?

We have actually looked at that several times. We will continue to look at a go-private move. It never makes the cut. It doesn't -- we just can't seem to make the math work, but those are some of the things that we're constantly analyzing.

Okay. And then lastly, should we expect a monetization of a portion of ME2 when it gets done?

ME2? I would say more likely not. Well, I'd say we continue to look at any opportunity that will -- that's the best decision for our partnership with that asset and for our unitholders.

And Mackie, let me add. We -- it is safe to say that any monetization of ME2 would be a strategic partner. It would be somebody that would be bringing barrels to make that project more successful. So it would not be a financial partner at all, but rather a strategic.

Our next question comes from the line of Chris Sighinolfi with Jeffries.

It's Corey filling in for Chris. Just one quick follow up on the capacity for your crude acquisition remark. And maybe just if I can ask more directly, how much capacity do have that is not hedged that you expect to benefit from, given the [Y] dips?

Yes. Yes, this is Mackie again. We just typically do not answer those kind of questions. It varies from month-to-month and quarter-to-quarter, kind of across-the-board, so we don't really disclose that. But Tom's already alluded that we've made prudent decisions on hedging out some of the volume this year and into '19, and we will continue to evaluate that and do what we think makes the most sense for our partnership.

Got you. Okay. And then maybe just a follow-up on the Permian. Given that we expect production to keep rising from current levels, we're already tight capacity. What do we expect to happen in that basin, to the extent that there's not actually evacuation capacity right now? At least, that's what the market's telling us. What's the expectation for wells? Do you expect to be shut in? Do you expect those trucks to evacuate?

Our understanding is that a lot of the larger producers are out trying to acquire more trucks, trying to lock up more rail. So there certainly is a growing concern over at least the next year or 2 of crude outlets from that area as well as the gas outlets. So who knows? I think there is some in our group on our gas side that believes there will be a time potentially in the next 6 to 12 months where there will be a no-bid at Waha. In other words, nobody's buying gas for, say, a weekend or something, just because there's no outlets. With gases shut in, of course, oil will be impacted as well because a lot of the gas is flowing just to produce the oil. So certainly, there's some tough times probably coming if volumes continue to grow as they are now and as they're projected to grow. But we and the industry are doing everything we can to alleviate that as quick as we can.

Got you. Okay. And then -- and maybe just one quick one on PE3, I know it's still in the process of ramping up. Can you quantify how much it ran in 1Q?

PE3?

Yes.

Well, it was a couple hundred thousand a day. We're ramping that up. The largest customer on that ramps up again in November this year and in November of next year. And in addition to that, we have approximately 50,000 barrels that will be going out for an open season in the very near future.

Okay, and then one last one for me. On ME2, any update to the contracts on the pipeline with respect to both NGL and refined products?

This is Mackie again. The update is we just need to get in. It's one of those things, build it and they will we come. And once we're in and flowing, it is absolutely the most viable, the most profitable, the most efficient way to get propane and butane out of Eastern Ohio or West Virginia and Western Pennsylvania. So we're very excited about what will come, in addition to what we already have signed, but we need to get it flowing and we're pushing hard to get there.

Ladies and gentlemen, at this time I would like to turn the floor back to Tom Long for closing comments.

All right. Well, listen, thanks again, fantastic quarter across all of our segments. So clearly, you can see the excitement in what we're seeing. Kudos to the entire team here on getting these projects, continue to ramp-up, coming on and we're very excited about the future as you look out over the remainder of this year and where we're headed. So thank all of you once again for joining the call today, and we look forward to talking more with you.

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