Energy Transfer LP (ET) 2017 Q1 法說會逐字稿

Greetings, and welcome to the Energy Transfer Partners first quarter earnings conference call. (Operator Instructions) As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Tom Long, Energy Transfer Partners' CFO. Thank you, sir. You may begin.

Thank you, operator. Good morning, everyone, and welcome to the Energy Transfer and Sunoco Logistics First Quarter 2017 Earnings Call, and thank you for joining us today. I'm also joined today by Kelcy Warren, Mackie McCrea, Matt Ramsey and John McReynolds as well as Mike Hennigan and Pete Gvazdauskas from SXL 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 update on the merger between ETP and SXL as well as a discussion on the latest developments on our Rover, Bakken, Mariner East II, Permian Express III and other growth projects. Then I'll turn our focus to a discussion on Energy Transfer Partners' and Sunoco Logistics' first quarter results, followed by a financing and liquidity update and lastly, a distribution discussion.

As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These are based on our beliefs as well as certain assumptions and information currently available to us.

I'll also refer to adjusted EBITDA and distributable cash flow, or DCF, both of which are non-GAAP financial measures. You'll find a reconciliation of our non-GAAP measures on our website.

First, turning to an update on our merger with SXL. On April 26, 2017, ETP unitholders voted to adopt the merger, providing for the acquisition of ETP by SXL in a unit-for-unit transaction. Based on the results, 88% of the units that voted, voted in favor of the merger. The merger closed on April 28, and the common units of the combined company, which is named Energy Transfer Partners, began trading on the NYSE under the ETP ticker symbol on May 1. Under the terms of the transaction, ETP unitholders received 1.5 common units of SXL for each common unit of ETP they owned. As a result, in the transaction, SXL issued approximately 845 million units to former ETP unitholders. This issuance, combined with the cancellation of approximately 67.1 million SXL units previously owned by ETP, leaves us with a current unit count of approximately 1.1 billion total units outstanding.

We are very excited about these 2 partnerships coming together. As we have previously mentioned, this combination expands our strategic footprint, adding scale and scope, and further diversifies our basin and product exposure.

We will now have the ability to capitalize on commercial synergies between the businesses and realize cost synergies not available as separate entities. Integration teams from both partnerships are fully engaged in the integration process, which we will provide more details on at the appropriate time. We remain confident that we will be able to exceed our targeted G&A and commercial synergies of approximately $200 million that we laid out in the proxy statement. In particular, we continue to expect significant commercial opportunities related to our Permian Basin, Marcellus, Utica Shale and Gulf Coast liquids platform.

Now let's move to our growth projects, where we have several projects completed and ramping up and others still under construction. On our Waha to Mexico export projects, we are pleased to say that the Comanche Trail and Trans-Pecos pipelines went into service in the first quarter as scheduled, and we are collecting demand fees on both pipelines. In addition, we began flowing gas to Mexico on the Comanche Trail pipeline last week. These 2 pipes will greatly alleviate takeaway constraints from the Waha hub.

Next, moving to the Bakken Pipeline project. Construction on our Dakota Access Pipeline is mechanically complete. We now expect to conclude line fill next week and are scheduled to begin the first month of service under the committed transportation service agreements on June 1. We close the latest open season May 1, and are pleased to announce that we have signed new TSAs for an additional 50,000 barrels per day. We reiterate our commitment to continue to protect all cultural resources, along with the environment and the safety of all those in the area.

As a reminder, in February, we successfully completed the project financing for the Bakken Pipeline as well as the closing of the previously announced sale of a 36.75% interest in the Bakken pipeline to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Partners LP. As a result of this closing, ownership in the Bakken Pipeline is now as follows: ETP holds 38.25%; MarEn, 36.75%; and PFX 25%.

On Rover, we completed tree clearing by our March 31 deadline and we remain on schedule to be in service to the Midwest Hub near Defiance, Ohio, in July and to markets in Michigan and the Union Gas Dawn Hub in November of this year.

In West Texas, the 200-million-a-day Panther processing plant, which is in the Midland Basin, came on line in January and added an average of 100,000 MMBtus per day in the first quarter. We expect volumes on the plant will continue to ramp up throughout 2017. And the 200-million-a-day Arrowhead processing plant in Reeves County in the Delaware Basin is still expected to come online in the third quarter of 2017. We are working to get this plant online as quickly as possible as our assets in the Delaware are running at near capacity, and this plant will help fill a critical need in the region. Our Revolution project is still on schedule to be in service in the fourth quarter of 2017.

Next, on Bayou Bridge, on the 30-inch segment from Nederland to Lake Charles, we transported an average of nearly 83,000 barrels per day in the first quarter. On the 24-inch segment of Bayou Bridge from Lake Charles to St. James, construction continues to move along as scheduled, and we anticipate that deliveries to St. James will commence in the fourth quarter of 2017.

Lone Star's 120,000 barrels per day Frac V, which will also include NGL product infrastructure and a new 3-million-barrel Y-grade cavern, is fully subscribed by multiple long-term fixed fee contracts. It is expected to be in service in September of 2018.

And now looking at a couple of new projects, we are pleased to announce a new long-term fee-based gathering and processing agreement with Enable to begin fully utilizing idle pipeline and processing capacity in North Texas. We have several secured firm agreements on 400 million cubic feet per day beginning in the second quarter of 2018. Additionally, the natural gas liquids will ramp up for transportation and fractionation on Lone Star, and the residue volumes will be transported on our intrastate system.

And in West Texas, we are pleased to announce that we will be constructing another 200-million-cubic-foot-per-day processing plant near the existing Rebel plant with NGLs going into Lone Star's pipes. Rebel II is expected to go in service in the second quarter of 2018.

Looking at SXL's current growth projects, we are planning to launch an open season for the first phase of our Permian Express III pipeline expansion in the next couple of weeks. Overall, we expect to be able to expand by 300,000 barrels per day, with the first phase targeted at approximately 100,000 barrels per day. We are also very pleased to report that construction is continuing on our Mariner East II project throughout Pennsylvania after receiving the Pennsylvania DEP Chapter 102 and 105 permits. We continue to target an end of the third quarter completion, pending the construction progress on the pipeline portion of the project.

The NGL tanks at the Marcus Hook Industrial Complex will be completed in the summer, and we have given the 6-month operational notice to our shippers. Having the project in service ahead of the 2017 and '18 winter will ensure the adequate supply of propane to local markets.

Now let's turn to our first quarter results. With the closing of the merger between ETP and SXL, results reflect the consolidated results of Energy Transfer Partners. For purposes of clarity, references made to legacy ETP will be for the historical ETP prior to closing of the merger, and references made to legacy SXL will be for the historical SXL prior to the closing of the merger. And references made to post-merger ETP will refer to consolidated results of legacy ETP and SXL.

Legacy ETP's adjusted EBITDA on a consolidated basis totaled $1.41 billion, which was up $2 million compared to the first quarter of 2016. Lower operating results from the legacy SXL crude oil acquisition and marketing activity segment was partially offset by significant growth in ETP's midstream and liquids transportation and services segments. The lower adjusted EBITDA from the crude oil acquisition and marketing activities was due to approximately $50 million of unfavorable impact from LIFO inventory accounting, which are expected to reverse in future periods.

On a pro forma basis, for the ETP/SXL merger, DCF attributable to partners, as adjusted, total $907 million compared to $950 million for the first quarter of 2016, primarily due to the unfavorable impact from LIFO inventory accounting and an increase in net interest expense, partially offset by better results for midstream and liquids transportation and services.

Looking at the individual segment results. I'll start with the legacy ETP, and then we'll go into the legacy SXL. Starting with midstream, adjusted EBITDA was $320 million compared to $263 million for the first quarter of 2016. This increase was primarily due to higher NGL and crude prices as well as increased throughput volumes. Gathered gas volumes totaled 10.2 million MMBtus per day compared to 9.9 million per day for the same period last year. This was primarily due to increased volumes in the Permian from the ramp-ups of the Orla and Panther processing plants, growth on the Ohio River system in the Northeast as well as the acquisition of PennTex and certain DCP assets in North Louisiana.

NGL production totaled 445,000 barrels per day compared to 431,000 barrels per day for the first quarter of 2016. Equity NGLs were 26,000 barrels per day for the first quarter of this year compared to 30,000 barrels per day for the same period in 2016. The Permian Basin continues to be one of the primary growth drivers for our midstream business, and we are well positioned to meet producers' growing needs for both gas and liquids services.

We also continue to see excellent growth on our Ohio River system in the Northeast as we continue to see great results from our anchor shippers on this pipeline in the dry Utica. In the liquids transportation and services segment, adjusted EBITDA increased to $259 million compared to $227 million for the same period last year. The increase was due to higher throughput at the Lone Star fractionators, higher NGL and crude transportation volumes and increased storage margin.

NGL and crude transportation volumes on our wholly-owned and joint venture pipelines increased more than 35% to 740,000 barrels per day due to increased volumes out of the Permian Basin, North Texas, Louisiana and the Eagle Ford as well as the startup of the Nederland to Lake Charles segment of the Bayou Bridge pipeline, which averaged nearly 83,000 barrels per day during the first quarter, and the startup of certain other West Texas crude assets in Reeves and Loving Counties.

Year-over-year, average daily fractionated volumes increased nearly 20% to 433,000 barrels per day due to the startup of our fourth fractionator at Mont Belvieu, which was commissioned in October of 2016 as well as increased producer volumes.

In our Intrastate segment, adjusted EBITDA was $169 million compared to $179 million in the first quarter of last year. The decrease was due to lower transportation and storage margin, partially offset by growing fees related to exports to Mexico and higher results related to our commercial optimization business. Transported Intrastate volumes decreased slightly due to lower production in the Barnett Shale, partially offset by increased volumes to Mexico as well as the addition of new short-haul transportation pipeline delivery volumes into our Houston pipeline system.

We continue to expect volumes to Mexico to grow, particularly with the startup of Comanche Trail in January of '17 and the startup of the Trans-Pecos pipeline in March of '17, which should result in increased demand for our transport services through our existing pipeline network.

In our Interstate segment, adjusted EBITDA was $265 million compared to $292 million for the first quarter of 2016. We did see an impact from the contract restructuring on Tiger as well as lower rates on some of our pipelines due to weaker basis spreads and mild weather.

Moving on to the all other segment, which includes our equity method investment in limited partnership units of SUN LP consisting of 43.5 million units, representing a 43.7% of SUN's total outstanding common units, adjusted EBITDA was $123 million compared to $102 million a year ago, due to an increase in adjusted EBITDA from PES and lower transaction-related expenses, partially offset by a reduction in the management fee paid by ETE.

Now moving to legacy SXL results for the first quarter. Adjusted EBITDA was $278 million for the first quarter of 2017, including a negative $50 million LIFO impact. Looking at SXL's results by segment and starting with the crude oil segment, there were several market anomalies that occurred in the first quarter, detracting from crude earnings. First, WTI Midland traded above WTI Cushing at approximately $0.60 per barrel premium. As a result of the Midland premium to Cushing, the WTI Midland to LLS spread declined to its lowest level in many years, trading at approximately $0.75 per barrel. This phenomenon was unexpected as Permian production is increasing, which should lead to Midland discount. We still expect that the balance between production and takeaway capacity will be tightening by the second half of 2017, resulting in wider differentials between Midland and Cushing. It's currently trading at approximately $0.75 to $1 per barrel discount, and the Gulf Coast arbitrage has widened to approximately $2.50 per barrel.

In addition, we again experienced negative LIFO accounting impact at a very significant level of approximately $50 million. As we discussed in the past, this negative accounting impact occurs when there is contango market structure and a rising absolute price of crude. Ultimately, the accounting zeroes itself out over time as the inventory is liquidated. And we expect any positive accounting impact would be seen as the year progresses.

We reported $147 million of EBITDA in the crude segment, which would have been $197 million if there was no negative LIFO accounting impact. Even with the severely depressed spreads, volumes in the system were up approximately 100,000 barrels per day compared to 2016. This demonstrates strong earnings potential in our strategic crude platform.

Despite the noise in the results this quarter, we still feel very good about the growth potential in our crude segment. We remain bullish on Permian production as the rig count continues to increase, and we anxiously await the startup of the Bakken Pipeline to contribute to earnings. We see tremendous upside with our joint venture with ExxonMobil and have been very pleased with the early results of our acquisition of the Vitol terminal and gathering system in the Midland Basin.

Turning to legacy SXL's NGL segment. We generated $82 million of earnings in the quarter compared to $88 million last quarter. The drop was attributable to a customer shutdown on the Mariner system. However, this customer is under a take-or-pay contract, so the earnings will be recognized in a later quarter. The ME 1 system ran full in the quarter, averaging 72,000 barrels per day, and Mariner South continues to run at consistent levels. The refined product segment contributed $49 million of earnings in the quarter, bringing the total EBITDA to $278 million, including the $50 million in negative LIFO accounting impact. With the absence of accounting noise, strengthening crude differentials and the Bakken Pipeline startup this quarter, we would expect results in the second quarter to be materially better than the first quarter.

Without the accounting noise, the SXL DCF coverage would be 0.9x as we await contributions from the Bakken and Mariner East II projects that have been delayed from our original startup date of the end of 2016. Had those projects started up at that time, our coverage would have been in the 1.1x range. So we are anxious to get those up and contributing to earnings and distributable cash flow.

Going forward, we will be realigning some of the legacy business segments. The legacy ETP Midstream, Interstate, Intrastate and all other segments will remain unchanged. The legacy ETP liquids transportation and services segment will be split into 2 new segments. The crude oil segment will include the legacy ETP crude oil assets like Bayou Bridge and the Bakken Pipeline, along with the legacy SXL crude oil assets. And the new NGL and refined products segment will include the legacy ETP noncrude liquid assets, including all of the Lone Star along with the legacy SXL natural gas liquids and refined products assets.

Now moving on to a CapEx update. For the first quarter of 2017, ETP and SXL invested approximately $1.2 billion in organic growth projects, with the majority allocated to the ETP Interstate, Midstream and liquids transportation and services segments and SXL's NGLs segment. This includes capital expenditures related to Bakken, Rover and Bayou Bridge. For the first quarter of 2017, ETP and SXL spent $60 million on maintenance capital expenditures.

As we can now officially bring these 2 partnerships together, there is extensive work being done around commercial opportunities, CapEx spend and discussions around the possibility of bringing in strategic partners on several large projects. As a result, we will be coming out with a combined 2017 capital forecast with second quarter earnings.

Now let's take a quick look at our liquidity position. In the first quarter, ETP and SXL collectively brought in over $5 billion in cash from the Bakken equity and debt financings and the equity and senior note issuances. During the quarter, ETP issued $568 million of equity in a private placement to ETE, $196 million under the ATM and $71 million under its DRIP program, for a total of over $800 million of equity in addition to the $2 billion Bakken equity sale. Post-close, both the legacy ETP $3.75 billion credit facility and the legacy SXL $2.5 billion credit facility will remain outstanding while we work to combine these into a new facility later this year.

As of March 31, 2017, the legacy ETP credit facility had $389 million of outstanding commercial paper borrowings, and the legacy SXL credit facility had $740 million outstanding, which includes $128 million of commercial paper. In aggregate, the combined partnerships have borrowing capacity of up to $6.25 billion, and total liquidity under these 2 facilities at the end of the quarter was approximately $5 billion.

Next, I'd like to touch on our recent distribution announcement. Last week, post-merger, ETP announced a distribution of $0.535 per common unit for the first quarter, or $2.14 per common unit on an annualized basis. This is the first distribution announcement for the combined partnership following the merger of ETP and SXL. This was an increase of $0.015 compared to legacy SXL's fourth quarter 2016 distribution and will be paid on May 15 to unitholders of record as of the close of business on May 10. We continue to expect to achieve near-term distribution growth in the low double digits.

Before moving on to an overview of ETE's results, I want to touch on PennTex's first quarter results. Adjusted EBITDA totaled approximately $20 million compared to $15 million for the first quarter of 2016. The increase was due to a higher minimum volume commitment. DCF attributable to the partners of PTXP, as adjusted, totaled $19 million compared to $13 million a year ago, primarily due to the increased adjusted EBITDA. Processing volumes averaged 235,000 MMBtus per day during the first quarter of 2017, and minimum volume commitments under PennTex's gathering and processing agreements with its primary customer were 460,000 MMBtus per day for the quarter. On April 26, PennTex announced the distribution of $0.295 per common unit for the first quarter, or $1.18 per common unit on an annualized basis.

Now moving on to ETE. I'll begin with first quarter results, followed by liquidity and financing updates. For the first quarter, ETE's distributable cash flow, as adjusted, totaled $215 million compared to $349 million for the first quarter of 2016. The decrease was due to the additional $105 million IDR subsidy granted to ETP for the first quarter of 2017 and lower post-merger distributions from ETP. ETE's coverage for the first quarter was 0.86x. And just briefly touching on ETE's distribution, last week, ETE announced a quarterly distribution of $0.285 per unit. This equates to $1.14 per unit on an annualized basis. It will be paid on May 19 to unitholders of record as of the close of business on May 10.

Now let's turn to a liquidity and financing update. ETE continues to have a healthy liquidity position and ended the quarter with a debt-to-EBITDA ratio of 3.88x for our credit facility. As of March 31, 2017, there was $1.15 billion in outstanding borrowings under the credit facility. Therefore, at the end of the first quarter, the overall ETE stand-alone debt was $6.6 billion with a blended interest rate of approximately 4.9%. During the quarter, ETE closed on a new $1.5 billion revolving credit facility, with a 5-year tenure and similar covenants and pricing to ETE's existing facility.

In January, ETE raised approximately $580 million through a pipe transaction, using the proceeds to purchase 15.8 million newly issued ETP common units. This transaction was both accretive to DCF and deleveraging for ETE. On February 2, ETE closed on a $2.2 billion institutional term loan, which effectively extends the maturity of its existing term loans from 2019 to 2024 at similar pricing. And in March, ETE invested $300 million in SUN through a preferred equity transaction. This transaction provides SUN with a near-term equity infusion while further demonstrating ETE's support of the underlying partnership.

Before opening the call up to your questions, I would just like to say that we are pleased to bring the ETP and SXL businesses together. The post-merger ETP entity is in a great position for growth. We're excited about the future for this newly combined partnership and the commercial opportunities that we will capitalize on.

As we look back over the last 12 months, our construction and engineering groups have done a great job of safely bringing online 2 200-million-cubic-foot-per-day processing plants in the Permian, our fourth fractionator at Mont Belvieu, the Lone Star Express Pipeline, Phase I of Bayou Bridge, 2 export pipelines to Mexico and 2 Permian crude projects.

These groups remain very focused on safely and responsibly bringing other projects, including the Bakken, Rover, Mariner East and Permian Express projects, into service according to their current schedules. These projects are expected to generate future fee-based EBITDA growth.

We continue to place emphasis on maintaining a strong balance sheet by lowering our leverage while also increasing coverage and liquidity and feel we have made great strides in the first several months of this year. At ETP, we remain firmly committed to our investment grade rating. And at ETE, our priority remains supporting its core operating subsidiaries. As you can see, ETE executed on approximately $1 billion in transactions in the first quarter to support the underlying partnerships and will continue to do so in the future as needed.

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

(Operator Instructions) Our first question comes from Kristina Kazarian with Deutsche Bank.

Tom, starting off, you started off talking about significant opportunities. And I know last time, I asked about how many more fracs to come, so maybe let me try another one this time. How much more Permian infrastructure opportunities do you think there are over the next 2 to 3 years? Maybe how many more processing plants you guys think you can do? Do you try a residue gas pipe? Are there more crude pipes on top of PE III? Could you just frame that up for me?

You bet. This is Mackie, and we probably don't have enough time to talk about what we see over the next 2 or 3 years, but we certainly can talk about what's happening now and what we expect to happen over the next 12 months. By far, that most active area, certainly for our partnership and for many in the country, we just brought on, of course, Panther is ramping up, our Panther cryo. We recently announced our Rebel II cryo, which will be on about this time next year. Arrowhead will be on in about 2 or 3 months, another cryo out in the Delaware Basin, Southern Delaware Basin. And we would be surprised if we weren't bringing another 200,000-a-day cryo on every 6 to 9 months for the next probably 2 or 3 years. Certainly haven't announced anything further than Rebel II, but it is a main area of focus for us on the gas side and also, as well, on the crude side. We're real excited to have the merger close so that we can work close with Mike Hennigan's team to go to customers and not only gather oil but gather oil, transport it, store it and then put it on export. So to answer the question, we will put a lot of capital and a lot of time in every facet of our business, on gathering, processing, even some intrastate opportunities that we hope to announce soon and certainly around the crude and NGL segments.

Kristina, this is Mike. Let me just add a few comments on the oil side. We're a week or 2 away of announcing our PE III open season launch. We see that as about 300,000 barrels a day with the first phase being about 100,000. Our expectation is we'll be launching subsequent phases pretty quickly after that. And I just want to remind you from previous discussions, we're really excited about the JV with ExxonMobil. As everybody knows, they bought the acreage out in the Delaware Basin, and we're having great meetings with them on looking at how they're going to advance their production in that area. So I think there's a lot of growth, obviously, in the Permian, and I think we're in a great position.

Perfect. And my follow-up will be in Rover. Those tree-clearing numbers were definitely impressive. Can you remind me what the key dates left are to hit on Rover completion? And maybe more importantly, when Phase II comes online in November, how are you thinking about utilization level out of the gate and time frame to reaching full capacity?

This is Mackie again. We haven't changed that for a long period of time. Our estimated time, we still are saying July 1, 2017. In several months, we'll bring on Phase I to Defiance, and then we'll complete the project in November of 2017. Couldn't say enough about our project team. Everything that they've gone through and the delays on getting the certificate, they have done a fabulous job, and we're very excited about that. As far as volumes go, of course, these are demand based. I think it's 97% demand based. So it isn't critical to our revenues on what exactly flows, but we do anticipate probably lesser volume Day 1, and it will ramp up. We expect to be pretty full probably within 12 months for the full at least 3 Bcf or more. So there will be a ramping period through 2017 and 2018.

Our next question comes from Brian Zarahn with Mizuho.

As 2017 expansion CapEx was fine-tuned, can you elaborate a bit on how you're thinking about potential financing options?

Yes, Brian. As you know, our practice has always been to manage toward leverage. Clearly, we have a lot of liquidity, as I laid out. So we're going to, as we go through the year, we're going to continue to look at where -- kind of a quarter by quarter as to how we fund that. And I guess what I can say on that one is it will be something we call -- we'll call that shot at the time.

And then -- and maybe a little bit more color on how you're thinking about JVs or somewhat of what you did with DAPL.

This is Mackie. Yes, I'm sorry, this is Mackie again. We have so many great assets coming online that it really doesn't make sense to bring partners in unless, like you just said, in a situation like DAPL, where you promote, you get a nice fee above what the costs are and you bring significant business, long-term business to the project. With everything we've got going on, we're certainly open-minded to any potential partner like that.

And then related to DAPL, you mentioned 50,000 barrels a day of new contracts. Can you remind us what the total contracted capacity is now? And for that new -- the new MVCs, is there a ramp or does that start Year 1?

Yes, this is Mackie again. Yes, we won't get into specifics about how customers' contracts come on, but we're very pleased with how the open season turned out. We have added 50,000 barrels. We will say that 50,000 doesn't come on Day 1, but it does come on relatively quickly. And that will bring our total capacity, with walk-up capacity, of about almost 530,000 barrels a day.

And then last one for me, you reaffirmed the distribution growth rate, but given where the cost of equity capital is for ETP, is there a consideration to potentially adjust that? The market really isn't giving you any credit for that type of growth.

Yes, listen, Brian. That's -- I mean, I know that's what we came out with when we, of course, announced the merger. That is clearly our plans right now. We feel like once we -- all these projects that we've got in front of us, how we're executing on them, and just watching how they're all starting up this year, et cetera, I think we feel very strong that we'll be able to continue to navigate through the year and looking at this cost of capital, that we have enough flexibility and opportunities in front of us that we will be able to hit that low double digits.

Our next question comes from Shneur Gershuni with UBS.

I was just sort of thinking about the conclusion of your prepared remarks, Tom. You basically talked about a ton of capital that you've put into service. And at the same time, you've got a lot of projects on to come, with Rover, Mariner East and so forth. In fact, you actually announced a processing plant as well, too. How should we think about your earnings growth potential and your cadence through the end of 2017 and into 2018 versus kind of your current run rate of the pro forma results that you just reported?

Yes. And listen, Shneur, as you know, we've got the proxy that we put out, which had the 3-year projections. So I think that's probably the first time in a good while that we've put out some numbers. So I would always kind of guide you toward that. But those weren't guidance; those were projections. But that -- I think that would be the answer to the first part of your question. And so you can kind of see how those projects are coming on within those projections that are out there right now. One thing that I -- on the previous question, I probably should have highlighted, along the lines of thinking what you're asking here right now, too, is as far as deleveraging, clearly, we're going to still target a 4.5x leverage ratio. But a big part of hitting that 4.5x is the fact that these projects are starting up, EBITDA is growing, like I was just talking about with those forecast numbers in the S-4. So it's a -- that's where your deleveraging is going to come from. It's going to come from that EBITDA growth that you see there. I think the other thing that I did not necessarily point out earlier in my prepared remarks was the -- was kind of where the leverage ratio is from a credit facility standpoint. And you're right at about 4x. I think we're just slightly over, just a few bps over 4x on that leverage ratio. So you can see that we've got a lot of flexibility in how we're going to fund that with this -- with managing this with the EBITDA growth.

Tom, you kind of stole the thunder from my next question, which was about leverage. With respect to how we should be thinking about the equity, and I think you kind of answered it with Brian's question, but should we sort of be thinking about you sort of hit the ATM or do reverse inquiries from time to time and sort of look at like $1 billion worth of type of equity over the next 2 years? Just trying to understand kind of your thought process, if it's equity or if it's really EBITDA growth, as you just discussed, as being the primary driver. And then there's also been some question marks about consolidated leverage of the entire entity. Does the recent SUN acquisition -- sorry, disposal of assets, once it closes, does that sort of contribute towards helping reduce your consolidated leverage as well, too?

Yes, let's start with the first part on the ATM. Clearly, ATM is going to be an option that we have in front of us. We're going to stay, like we have been, opportunistic on how we issue under that. But we are, as you look out and you kind of see where we are and you see where the growth is, we don't want to try to guide to any set a number on that equity. I know that's going to continue to be a common question. But we are going to manage that throughout the year, I will assure you, in order to keep a strong balance sheet, keep our leverage at that 4.5x target, or moving toward that. And that's how we're going to navigate through this. But the ATM clearly is going to be a key component of that for sure. I think as far as the second part of it, as far as the SUN, clearly that's a deleveraging on a consolidated basis. Obviously, as that -- as those funds come in, we will be utilizing to, as stated in the announcement that day, to target a 4.5x on that. I think we actually said 4.4x is where we anticipate that landing. But 4.5x is where the target is going to be on that, from that standpoint. So when you look at a consolidated level, clearly that does bring down the leverage by a few notches. Obviously, that's a smaller entity within ETE, but it still moves the needle as far as bringing down the consolidated leverage.

And a follow-up question, just I think it was a follow-up to Kristina's question, just with respect to where Waha pricing is right now and the concerns that producers have out there and so forth, if I remember correctly, a bunch of years ago, the Energy Transfer system in Texas was able to earn a lot of money on those different spreads and so forth. Is that a pending opportunity for you? And then do you see incremental opportunities to add capital as well to just sort of address some of the producer questions?

This is Mackie again. Yes and yes. We have been through a painful era over the last 5 or 6 years, with little to no basis spread between Waha and Katy, and we certainly are the largest company that can provide that service. And over the last 2 or 3 months we've seen basis blow out 4 or 5x, 6x where it's been. We're very excited about that as we look at what the shippers are looking for. We are looking at opportunities to expand out of that area. We certainly can do a lot with Oasis to handle some of the growth. As you know, and as Tom mentioned, we just brought on 2 pipelines that'll be able to move 2.5 Bcfs out of the Waha area. So we'll continue to be kind of the leader to provide transportation service out of those areas. And we'll also be a good listener, as we always try to be, on what the shippers are looking for and where they want to go with their volumes in the future.

And Mackie, when you talk about the difference between now and versus 6 years ago, I mean, what kind of EBITDA potential are we talking about versus what you used to earn versus what you just did, for example, in the last quarter?

I think we've said in the past, and it varies on where exactly the transportation goes, but for example, from Waha to Katy, for every dime, you're looking at the ballpark of about $45 million or $50 million. It depends on how much capacity is available at the time each year. But it is significant. I mean, as we have more capacity come available, and this -- we'll make this known here soon, in 2 or 3 years, we could have 700,000 or 800,000 a day, at least, available. So if you add that up, it is significant revenue that we haven't seen for years.

Our next question comes from Jeremy Tonet with JPMorgan.

Congratulations on overcoming all these regulatory and operational obstacles to get so much accomplished in the past quarter. I just wanted to come at the question as far as what a combined entity could do what the priors couldn't before. Especially in the Permian, I was wondering, Mackie and Mike and Pete, if you could just talk a bit more as far as some of the opportunities that you couldn't capture before, but now, now that you're under one roof, what you could do, and also just having an integrated service offering, what -- how that positions you going forward?

You bet. This is Mackie again. Yes, we are so excited. Even though we have kind of similar ownership and control, we work through different partnerships, and it's extremely difficult to go out and contract business through the full spectrum of services when you have 2 partnerships kind of with their own incentives and their own unitholders. So we're real excited. We've already, prior to the merger, started working towards some of these synergies. We actually are already achieving some of those synergies, where we can offer such a wide range like we do on the gas side, we can now on the oil side, as I mentioned a little earlier. Not only gather, not only deliver to Sun (inaudible) and store and blend. We also can transport to Nederland, put it on ships, send it to many, many markets and refineries along the Gulf Coast. And hopefully soon here, latter part of this year, we'll be able to deliver all the way to St. James. So we're real excited about our teams being able to go in and offer whatever service the shipper or the customer is looking for, like we've been able to do on the gas side.

Great. And Tom, I just wanted to follow up a little bit on the balance sheet. And not to beat a dead horse here, but just as far as you talking about the delevering process naturally occurring with all this EBITDA coming online, it seems that you wouldn't necessarily need to rush into any big amounts of equity issuance, that you have flexibility there. Just wanted to see if that's correct.

And also, in the process of combining your revolvers from the 2 entities, are you planning on putting cross-guarantees in place between the debt of SXL and ETP?

Yes, let's start with the first one. As far as the equity goes, you're right, we do not have any necessarily sense of urgency there. Clearly, the ATM, I'm going to stay focused on that still, as far as my answer on that. But I will say that we are going to -- we are always going to try to be opportunistic. We're always going to, as we look out through the year, we're going to play it the what we think is the optimal way for the unitholders to create the most value as we look at funding these projects. But like I laid out, we've got a -- we do have a lot of different options, like what Mackie was just talking about on strategic partners. Clearly, that's another component. And so we're going to evaluate as we go through the year on that part of it. So -- and I'm sorry. The second part of your question real quick?

Cross-guarantees between the 2?

Oh, yes. Yes. I'm sorry. Yes, listen, we're working on that right now. You can see that in pretty short order, how we're going to kind of structure that. I will tell you that's also blended in, something I didn't necessarily touch on a lot. The revolvers, both the credit facilities, we are looking at combining those into one. So all of that's going to kind of happen at the same time. As we look out, we wanted to go ahead and get the transaction closed. We were able to structure all this in a way that we didn't have to do it pre-closing, but our plan is to kind of do it post-closing.

Great. And then just wanted to touch on the liquid segment real quick here, where revenue was up $60 million but EBITDA was down $22 million. And I'm just wondering, were there any issues here as far as kind of mark-to-market noise with derivatives or other things that we should think about, given you would expect the EBITDA and revenue didn't quite move in the same direction?

No, you nailed it. There was some, clearly, some derivatives mark-to-market activity. And we do expect to see that to reverse throughout the year, real similar to the LIFO that we talked about on the Sunoco Logistics. So -- but you're exactly right.

Do you have a sense of how much that was, just so we could model that right?

Yes, that was probably about $20 million.

Okay, great. And then one last one. Just as far as great strides towards simplification within the family. Just wondering, is there anything left out there as far as PennTex and SUN, as far as any strategic moves that still need to be done there or further simplification that we should be thinking about?

This is Kelcy. I would say we're exploring a lot of things. We're back looking at -- as I've said before, we believe that the correct mix of M&A with organic growth is the only way to run -- successfully run these partnerships. So we're exploring that. But PennTex is doing very well, and we're coexisting very well. SUN, as we've stated before, we really like the new -- after the asset sales close, we really like the new SUN a lot, and we think it's going to be positioned well for growth. We see that as coexisting quite well with -- as an existing MLP in the refined products business, primarily terminaling, pipelining and what other opportunities may be derived from that. So -- and then, of course, we're -- as I've said before, we are looking at other assets that would be complementary. And we're not having much success right now, but we're charting a lot.

When you say assets that are complementary, are you talking about things in ETP that could fit in SUN or vice versa? I'm thinking kind of like the refineries...

Not -- I don't really see -- I've heard some questions about that before. I don't really see any assets that would not fit in ETP. Mackie, do you disagree?

No, I agree.

Yes, so I don't really see any drop-down opportunities per se from P to SUN. But obviously, these partnerships being, let's call them affiliates for lack of a better description, there will be opportunities that Mackie, Mike Hennigan and others see that may not fit ETP that would be a better fit for SUN, and vice versa. And so there will be open communication between the partnerships, and hopefully they'll be able to assist each other in growth.

Our next question comes from Darren Horowitz with Raymond James.

Mackie, if I could, I wanted to go back to the comment that you made on adding more West Texas processing capacity. And I realize that a lot of the Y-grade coming out of that is backstopping the frac capacity in Mont Belvieu with demand charges from producer customers. But per your comment on adding more cryos, let's just say every 6 to 9 months, how do you think about either taking title to a growing portion of those NGL barrels out of the tailgate of the cryo into Belvieu or even having more control of the downstream distributions of the purity products, leveraging storage like you talked about and maybe even getting to the point where you've got consistent supply assurance to backstop some meaningful export capacity additions?

Yes, Darren, the way we approach business, sure, we love to control as many of the molecules and in this case, as many of the barrels as we can. There's advantages all the way through the downstream. But the way we build our partnerships is to listen to our customers. So it really depends on what they want. And if they want it delivered to our frac or to other fracs, or if they want their liquids backed at the tailgate, we pretty much will listen to them. But for the most part, we do own and control a large portion of them. And there are benefits through the stream and through the frac. But as far as the second half of your question, any kind of further downstream, we're a fee-based business. We're not going to do expansions, so say whether it's propane or new projects of ethane, over to Nederland and take that demand risk on ourselves. So it will be our customer that will kind of hand the barrels back to support any kind of export projects or any opportunities downstream in our NGL segment.

Mackie, does the strategy change within the context of some large third-party NGL frac agreements expiring? And I'm not saying specifically taking more exposure to the commodity itself, but maybe just checking the boxes with regard to more fees that you can collect along the midstream value chain?

Well, I'll say again, sure. If we can structure it in such a way where we control the barrels from the tailgate of our plants, we'd certainly prefer that. I don't know of any major frac deals that are coming off other than one that we're anxious to come off so that it will fill capacity on our frac sooner than later. But I guess I'd just reiterate that we'll do what the customer is asking us to do. If they want us to control and own those barrels at the tailgate, which many of them do, of our processing plants, we certainly will do that.

Okay. And then my last question, either for Tom or Kelcy, I appreciate the detail on the balance sheet and the leverage trajectory that you guys worked into the assumptions that were in the S-4, and we can all see the cash flow ramp-up has associated risk coming. But if the market doesn't reflect that in the implied cost of capital, you've talked about strategic partner investment and a few other different things. And I think we're all well versed on what they are. My question is more from a timing perspective. How long, Kelcy, do you let this continue where you start thinking about, quantitatively, the return on invested capital over a certain amount of time having a meaningful effect on your economics before something more structural happens?

Yes, I don't know. That -- with the flexibility we have in the partnership, with ETE's ability to assist the partnerships when necessary, Darren, I don't know. The -- as I've said before, I think an ultimate consolidation is inevitable. I would certainly think that the market is smart enough to better reflect the value that ETP should trade at, the combined SXL/ETP. I just don't -- personally, I just don't see how it can't, with all this growth that's coming online, that's very real, it's quantifiable. And the timing of it is very quantifiable as well. So I can't answer your question. But yes, if there was a dire situation where the partnerships did not recover, then we would look at other alternatives. But I do like our flexibility that we have with ETE being able to step up and help ETP or SUN as needed.

Our next question comes from Keith Stanley with Wolfe Research.

On the distribution growth, I think you said this, but I just want to confirm you're still thinking low double-digit growth in 2017 at ETP? And then secondly, just any sense of how we should think about distribution growth potential and coverage looking beyond 2017 and just the current IDR subsidy roll-off schedule as it sits today?

Yes, and that's correct, as far as the low double digits that you mentioned. That's our intentions here right now. I think, as you kind of look out, we're going to still always manage kind of to that 1.1x, 1.15x coverage ratio as you look out over those years, over the next few years. And we haven't really given any kind of guidance from that standpoint. But I think you can kind of see, from all these projects coming on, of where we think we can be even over the next few years, so -- percentage growth-wise.

Okay, and one small follow-up. Just on the management fee arrangement between ETE and ETP, that a lot of which ended this year. Can you just remind me, I thought it was a pass-through arrangement, with ETP having costs and then ETE reimbursing them for services at Lake Charles. But it was cited as a negative driver for ETP in the quarter. So should we think of the end of that arrangement as a negative for EBITDA for ETP this year?

Yes. In other words, you're correct, that rolled off at 12/31. There was a small piece of it that will be rolling off at March 31 of '17 here. But that is correct. As far as your modeling go, there is no intention of really putting that back in place right now.

Okay, so ETP's costs don't go down as a result of terminating the arrangement as well?

Well, no. ETP's costs, they do go down as far as that goes.

Our next question comes from Michael Blum with Wells Fargo.

Can you talk a little bit about your thoughts on growth at ETE? Obviously, we've got the numbers now at ETP. But maybe can you talk about how you're thinking about growing the distribution there? And maybe the related question is how much coverage are you planning to maintain at ETE?

Michael, this is Kelcy. Yes, I mean, as you saw, due to the way the IDR subsidies worked, this is subpar -- below 1 coverage ratio for ETE that recovers pretty quickly. And we -- I feel that the resumption of distribution growth at ETE is short in coming. So -- but we need to be above the 1 coverage ratio. The modeling that all -- that's been made available to all of you reflects that, that occurs probably next quarter and then continues thereafter. Going back to a question we had earlier, it's the what additional subsidies are going to be required to support ETP, we'll look at that. And of course, that could affect that distribution growth. But based on what crystal ball we have in front of us today, I think distribution growth at ETE is short in coming.

Okay. But you will intend to maintain some coverage there to keep the flexibility around future subsidies? Or do you think you'll pay out the vast majority of it?

No, I think -- well, I think we will run above the 1 coverage ratio but not substantially, 1.05 to maybe 1.1. I feel very comfortable with that. There's a lot of ways ETE can support the partnerships other than just straight IDR subsidies, and we're exploring those. For example, I don't see ETE -- ETP needing a financial partner. And if it does, that financial partner probably should be ETE and not just a private equity. Unless, like Mackie said before, the partners that we really choose and assets that we prefer is classic Dakota Access Pipeline, where you not only have a partner that comes into a project but they also bring barrels, in that case. So to the extent we can find those along the way, we'll do that. But absent that, ETE may assist by temporarily being a partner in an asset until such time as the partners desire to take ETE out. So there's a lot of ways to help, and we will be exploring all those.

Okay. And then and maybe along those lines, as we think about equity financing needs at ETP, so obviously the (inaudible) path, but do you envision potentially raising equity at ETE and then using that effectively to buy ETP units and fund some of the capital that way? Is that on the table or not?

Michael, it's an option. It's not the preferred option. As you know, we've done it recently, and it is an option. And we will do that if that is the appropriate thing to do. But Tom, what are your thoughts?

Yes, that's exactly right, Michael. I think I keep using the flexibility word. We want to make sure that all the options are available to us. And that's the reason why we've kind of taken the steps that you've seen so far this year, so that we can optimize. Whatever the path -- I mean, whichever option we pull is going to be the one that we feel creates the most unitholder value for all the partnerships.

Okay. And then my last question is, just as it relates to the timing of a potential JV announcement, and I'm assuming that we're mostly talking about Mariner East II here, should we assume that if something happens, it will happen effectively between now and the next earnings call, since that's when you'll be providing 2017 CapEx guidance?

Michael, this is Mike. We continue to have conversations with strategic partners along that project. Right now, our focus is on execution. As you know, we've waited a long time to get in construction, and we're doing that. But at the same time, we continue to have thoughts, and once we're able to give you some more color on that, we will.

Our next question come from Eric Genco with Citi.

I was wondering if we could go back to the SXL NGL segment. I think you mentioned a customer shut-in on the Mariner South line. And I just wanted to ask, I think we've seen this before. Can you just expand a little bit and some of the EBITDA that will be coming to you, because it's a take-or-pay contract, one way or the other?

Yes, this is Mike. It wasn't on the Mariner South system. It was up in the Northeast system, in the Mariner system up in the Northeast. It was an unexpected shutdown. A small impact, though, about $6 million, $7 million that will be coming back later because of the take-or-pay.

Okay, but is there still EBITDA on the Mariner South system? I was looking back at some notes, and it was like 2Q last year where one of the customer contracts was -- they didn't utilize. And I think there's a period of time where they have to either use the capacity or you charge them anyway. I'm just wondering if there's more to come on that?

Yes, there will be at a later date. So the customers have a little bit of time to make up when the -- as you know, when the arb was really challenged a little while ago, there was a little bit less in the throughputs. But lately, it's been relatively consistent, and those arbs have come back from those lows that we've seen before. So there will be a little bit of a recovery there. But overall, Mariner South has been relatively consistent as far as the throughputs.

Okay, great. And then just one quick one. I'll try a different angle on this. In terms of PennTex, have you added it all? Can you tell us where your investment in PennTex stands at the end of the quarter? Have you added it all since the initial?

Yes, we're at 65%, but that includes the subunits. And so that 65% is split about evenly between subunits and common units. But we did have, totally unsolicited, with one of the banks came in during the quarter, where we bought a very small amount. I won't say that it moved it more than to maybe 65.5% or so.

Our last question will be from Ethan Bellamy with Baird.

Gentlemen, what about Lake Charles?

This is Mackie again. Here's where we're at on Lake Charles. We continue to have dialogue with Shell. They have implemented a little different strategy that we mentioned last time. Some of us believe they still will get there. The door is open. We have the framework of a deal ready to move forward. However, in the meantime, we have aggressively and are continuing to put together a team. We've already been out in the market. And we actually feel like we have a little bit momentum. We're pretty excited about it. And we will be pursuing not only our own LNG opportunities, but also fully maximizing the footprint and advantages there at Lake Charles, both with the land and with our docks, with possibly other commodities, ethane and ethylene. So we are -- we have kind of shifted focus. And Kelcy has kind of asked us to do this for a while. Some of us kept thinking Shell was going to get there. They still may. But we're not waiting around anymore, and we're going to do everything we can to maximize that facility for the benefit of our unitholders.

Mackie, that's helpful. And then Tom, or maybe Kelcy, there's obviously been a steady cadence of politically driven divestitures and pressures on lenders and financial relationships, I think, related to Dakota Access. How, if at all, do you anticipate that trend is going to impact financing rates and availability long term and maybe the diligence process that the lenders go through?

Yes. Ethan, listen, we have had just a few banks associated with the financing around the crude oil pipe. But I will tell you that we have not seen absolutely any impact. Kind of as I went through on some of the remarks, we've redone the credit facility at the same terms and conditions. We did -- and something I didn't even include in the $5 billion at the ETP level was, up at the ETE level, we went out with $2.2 billion and pushed that out. Well, I'm sorry. I did mention it in the ETE notes. So I can tell you at this point -- and that was at actually slightly better pricing than what we saw as we extended out those 2019 maturities to 2024. So I guess what I would tell you is, is we've not really seen -- I think our bonds continue to trade well, and we feel very good about our access to the debt capital markets.

At this time, I would like to turn the call back over to Tom Long for closing comments.

All right. Thanks. And once again, we really appreciate all of you joining us today. As I've mentioned, we're very excited about all the projects we have coming online as well as the merger between ETP and SXL. And once again, I thank all of you for your support, and we look forward to talking with you in the future.

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