Greetings and welcome to the Energy Transfer Second Quarter 2015 Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. I would now like to turn the conference over to Mr. Tom Long, Chief Financial Officer for Energy Transfer. Thank you, Mr. Long. You may now begin.

Thank you, operator. Good morning, everyone, and welcome to Energy Transfer Partners and Energy Transfer Equity second quarter 2015 earnings call. And thank you for joining us today. I will be providing comments for Energy Transfer Partners and then hand the meeting over to Jamie Welch, who will discuss Energy Transfer Equity's second quarter earnings and other highlights at ETE. I'm also joined today by Kelcy Warren, Mackie McCrea, John McReynolds, and other members of our senior management team who are here to help answer your questions after our prepared remarks. Not surprisingly, we had an extremely active second quarter. I'll begin with discussing our second quarter results, followed by recent developments, new growth initiatives, a financing and liquidity update, and concluding with a distribution discussion and a brief Regency integration update. 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. Now for our Q2 results, please note, as a result of the Regency merger which was a combination of entities under common control, ETP's financial results have been retrospectively adjusted to reflect the consolidation of Regency. ETP had a very good quarter overall. Adjusted EBITDA on a consolidated ETP basis totaled $1.49 billion, which is up $95 million compared to the second quarter of 2014. DCF attributable to ETP Partners, as adjusted, totaled $894 million, an increase of $149 million from a year ago. Now let's go over the individual segment results. In the midstream segment, significantly higher volumes…

Thank you, Tom. Good morning, everybody. We will first discuss the ETP, ETE, SUN GP/IDR exchange that Tom alluded to earlier in the call, then provide a liquidity financing update, then a brief update on Lake Charles LNG, to be followed by second quarter results, before concluding our prepared remarks with an update on ETE's proposal for Williams. We'll then take your questions. We were pleased with second quarter results for SXL and ETP. As Tom mentioned, SXL had its strongest quarter ever as a result of project start-ups and increased volumes, which continued to demonstrate the strength and resilience of that business. ETP had a solid overall performance for the quarter from all segments, including midstream. We're very pleased with the progress made to-date on the integration of ETP and Regency, which has exceeded our expectations and is a testament to the hard work of all of our employees. Tom has already gone over the details for the ETP, ETE, SUN GP/IDR exchange, as well as the strong benefits to ETP the transaction provides. So I will just summarize the rationale for ETE. The exchange is expected to be accretive in 2017 and beyond, whilst it is modestly dilutive to ETE's DCF for the balance of 2015 and 2016. The transaction reinforces ETE's clearly articulated strategy to become a traditional GP within the Energy Transfer family. We are confident that SUN GP will continue to grow in value. That said, the increasing cash flow and value in the underlying SUN GP creates incremental upside to ETE. Along the same lines, ETE will benefit from third-party growth at SUN. And it is our intent to focus even more on third-party accretive growth since the dropdowns will be completed by year-end 2016. And, finally, we expect continued upside from ETP IDRs…

Thank you. Our first question is from Brandon Blossman of Tudor, Pickering, Holt. Please go ahead.

Good morning, guys.

Hey, Brandon.

Jamie, this may be off limits, but I'll try anyway. Any update on the timing for the creation of the ETP Equity's FERC – or not FERC, SEC filings or otherwise?

It's a good question, Brandon. I think, in all fairness, it is so wrapped up right now as we on the whole Williams side that we want to see the realization of that process and then we'll go from there.

All right. Fair enough, and probably as expected. How about this? Conceptually or philosophically, share repurchases versus share count and longer term distribution growth, how does that thought process work, particularly in light of the structure performance recently?

Look, I would say, from just a traditional buyback standpoint, looking at obviously the cost of your debt capital to support a buyback versus the embedded cost – the yield that you're buying back the units at, it's pretty much a push. In fact, I would say, it's probably near-term slightly dilutive to our current cost of debt capital given somewhat of a move in rates, but obviously much longer term benefit. We, of course, have such ample amount of distributable cash flow right now that we've got this flexibility to think about the levers. So it's just something that, look, we sit down. We run through a bunch of math between Kelcy and myself. And he then calls the play on what we want to end up doing. But we do look at it on the basis of there is a trade-off, near-term versus longer term. And we've got to manage that.

Okay. Fair enough. And then just really quick, Lake Charles, can you give some color on where you are in terms of understanding exactly what the EPC cost will be here? And then just directionally have you been surprised with the outcome over the last six months to nine months?

Look, I think, we originally said last year when we did the November 18 presentation that we thought was all-in cost, including contingency, was slightly over $9 billion. As one would expect with obviously a slowdown in overall infrastructure spending in a lot of the large energy-related projects now being either shifted to the right or, in fact, frozen out entirely, we're seeing some significant concessions as it relates to labor and costs. We're seeing that also in a lot of our ETP projects where we're seeing some net benefit as well. So, it's hard to say exactly what the percentage decline will be relative to our original – versus our expectation last November. But it will be meaningful. And since we earn a rate of return on whatever that amount is, that will obviously we see translate into net benefit to Shell/BG.

Great. Perfect color. Thank you, Jamie. And I'll jump back into the queue at the end. Thank you.

Thank you.

Thank you. The next question is from John Edwards of Credit Suisse. Please go ahead. Mr. Edwards, your line is live. John Edwards - Credit Suisse Securities (USA) LLC (Broker) Yeah. Good morning. Can you hear me?

We can, John. John Edwards - Credit Suisse Securities (USA) LLC (Broker) Yeah. Jamie, just in light of some of the comments made by some of your peers regarding overbuild as it will and you had seen pretty bullish on all your projects. Maybe if you can give us a little bit of your insight on what you're seeing in terms of the areas that you're developing. Are you seeing that kind of thing or is it just kind of isolated to certain areas?

Just, so we understand the question. The question is, are we seeing any concern about overbuilding in any of the regions in which we serve? John Edwards - Credit Suisse Securities (USA) LLC (Broker) Yes.

Look, I'll let Kelcy and Mackie answer certainly some elements of that. I want to say, by and large – I mean we listened to Mike Hennigan's call earlier. I think our projects – when you have a philosophy that says you need this thing to be – any project that we go forward with needs to be close to 90% plus completely demand fee-based with very little commodity element, retained fuel revenues or anything else that basically run an IRR that allows us to determine whether in fact to move forward with the project, we are in the very early innings of pretty much most of our projects. And that gives us tremendous runway benefit over the next almost decade as we look out across. As we continue to see new opportunities come, we come with the same philosophy, right. We are very much, as you've seen with Rover. We have 15-year, 20-year contracts, right, Mackie? I mean this is the way we run.

Yeah. I mean really to reiterate what Jamie said, it doesn't really matter on the base project that we build, because we have accretive projects, as Jamie said, with demand charges. So really, where we're limited is the upside on the overbuild on any additional volumes, on any capacity we may have on an IP basis. But, fortunately, the way we're focused over the years and especially on these bigger projects are they're 100% demand-based projects with guaranteed returns.

John, this is Kelcy. Let me add to that. The pipeline business will overbuild until the end of time. I mean that's what competitive people do. We've done it. Others have done it around us. And then you find yourself – you must scavenge a product from others when you see volume declines. Then how do you do that? Well, you provide more services than your peers do. You provide more optionality. So this is something we'll always live through. But I'll tell you, people that give guidance and then turn around and have a bad financial reporting period and then throw all of us under the bus. Hey, by the way, don't focus on us, focus on the industry. This is an industry problem. That gets a little frustrating for me. John Edwards - Credit Suisse Securities (USA) LLC (Broker) Okay. That's helpful. And just – I'll just keep it to one more question. So in terms of – I put the same question to Mike Hennigan, in terms of your overall opportunity set looking forward. Are you seeing it now about the same, say, as the quarterback or do you see it actually continuing to increase a bit or do you see it falling off a bit?

John, this is Mackie. We're really going the opposite way of some comments that Kelcy just alluded to. If you line up our projects, it's beyond belief of what upstream synergistic value we have with even projects we announced. For example, we announced just a moment ago or mentioned just a moment ago from Tom that our West Texas – our CFE projects out in West Texas delivering gas to Mexico, we only have 16% ownership but we will be the operator, both commercially and operationally. But what we see on those projects is significant upstream revenue opportunities on our extensive intrastate and interstate pipeline networks. So not only do we have great projects, but we have significant revenue that we will definitely play a part in that has not even been recognized yet. And then if you move around the country and you go to Northeast, with our Regency acquisition, there's a significant fit right off the bat with the Utica Ohio 36-inches coming online this year to deliver additional volumes into Rover to make it even a better project. And then you look at all of the projects and processing plants that we're building out in West Texas and the additional residue volumes into our intra and interstate pipelines and the additional liquid volumes into our Lone Star facility. So we couldn't feel better about how we're set up both on the projects that we're building and the synergistic revenues related to the projects that we haven't even recognized yet in any of our economics. John Edwards - Credit Suisse Securities (USA) LLC (Broker) Okay. Thank you very much. I appreciate the color.

Thank you. The next question is from Michael Blum of Wells Fargo. Please go ahead.

Thanks. Good morning. I am wondering if on Lake Charles LNG, you talked about FID in 2016. Can you put a finer date on that or a rough date and then talk about when would be the sequence of a potential equity component to the financing?

Sure. Michael, we would love to put a finer date on it, if we actually could. We do have this little merger between our counterparty right now that's going on. And I think we're just trying to calibrate when, in fact, that is likely to close. And, I think, in all fairness, given this will require the sanctioning of our expectation right now, the Shell board, there's a period of time post the closing of that merger that they will need to, in fact, be fully – while they will be fully informed, but I will have the opportunity to make sure that their people in fact reaffirm everything they've been told and they have obviously looked at and evaluated. So I imagine it will take sort of 60 plus days, maybe 60 days to another 90 days after they close. I think, at its earliest, it would be quarter two. And at its latest, I think, it's probably the beginning of quarter three. So it's really, I think, in that sort of straddle period because otherwise, I think, from a construction timetable standpoint, they'll lose as a slippage of too much time. The other question around equity, as we've always said, there is no equity coming into Lake Charles from either ETP or ETE. Any external equity requirements needed to finance the project will be sourced from third-party sources. So we'll give them a piece of the future cash flow when the project comes online. So hopefully that is at least clearer now as to the overall sources and uses and requirements.

Okay. Thank you. And then, on Revolution, do you have any updates on further commitments beyond the anchor shipper?

No, we don't, Michael, at this time. However, we're very optimistic that we will be making announcements in the fairly near future about potentially expanding that project. But, in the meantime, that project couldn't be going better from a construction perspective, from a cost perspective. And we're very confident that we will not only add to that project, but also add to the Mariner East expansion projects.

Okay. Great. Thank you.

Thank you. The next question is from Jeremy Tonet of JPMorgan. Please go ahead.

Good morning.

Hey, Jeremy.

Congratulations on the strong quarter there. Great to see. I was just wondering, Kelcy, if you could provide some thoughts for us. I mean, ETE hasn't been immune from the weakness in the space. But still it seems like the currency has held up much stronger than other peers out there. And The Williams process is obviously a very large initiative. But would ETE look at this period of weakness as a chance to acquire other GP peers that have fallen on hard times?

Yeah, Jeremy, absolutely. I mean, at any given time, we have multiple models that we are analyzing. Not to suggest that we're preying on the weak, but there's some assets that fit us very, very well that we believe consolidated into the Energy Transfer family would make more money. And that's just reality. Mackie's point he made a minute ago, projects in certain areas feed other distributable cash flow of other assets. And that we work very hard to create this and we're not done by a long stretch. So to answer your question, absolutely, we are modeling a lot of consolidation at this time.

That's great to hear. And, I think, at points in time, there is maybe then some concern in the marketplace as far as ETP and equity needs are concerned. And, by our math, given the recent transactions that have been done within the family, it feels like those needs could be quite modest, especially given PES and the potential there. I was wondering if you could share any thoughts on that.

Yes. Jeremy, this is Tom Long. And you're exactly right. I think you stated that very well. We clearly have taken a lot of steps here to be able to fund the CapEx program that we have out in front of us. I mean, as you look at our balance sheet today, I mean, as far as our credit facility, no balance drawn on that. You heard me talk about the leverage with where we are, which rating agencies are very comfortable. And then you saw what we really pushed out with the ATM program, the $493 million during the second quarter. So, as you look out, you look at the continued drop potential with SUN, and you look at, like I said, the various options we have – and we are sitting with that cash on our balance sheet right now also from the announcement with the SUN – with the transaction with SUN that we just closed on July 31. So you can see that we do have a lot of flexibility here, from that standpoint, not to have to put pressure on our equity side of our capital raise.

Great. That's it for me. Thank you.

Thanks, Jeremy.

Thank you. The next question is from Darren Horowitz of Raymond James. Please go ahead.

Hey, guys. Good morning. Mackie, a quick question for you on that Bakken line. You all had mentioned that it was at 470,000 barrels per day. I know you want to get to 570,000 barrels per day. But I'm just curious with what's going on regarding regional differentials? What are you hearing from producers with regard to committing volumes? Is it just specifically an economic netback issue or is it a situation where they're not necessarily willing to commit necessarily to the duration, or maybe a mix of both? Or is it just purely based on reduced CapEx for the drill bit?

Darren, the way to answer that is that certainly the fall or collapse in oil prices have slowed down the interest of potential shippers to jump onboard to 10-year or 15-year contracts. However, we are continuing to have significant dialogue. We do expect to increase the commitments on that project. And with our announcement of the Bayou Bridge Project, even is enhanced and probably made that much more likely sooner, because the access not only to the SXL Nederland terminal, but also to the St. James and Lake Charles markets, which are some of the biggest refining markets in the world. So we will be diligent. We'll remain working very hard to fill that capacity. However, it's a fantastic project if we don't sell another barrel.

Okay. And then if I could just jump back to Revolution for a minute. As you talked about with that Utica Ohio 36 feet of gas into Rover and obviously the benefits of liquids going into the Mariner projects, and I recognize that, like you said, you guys are hoping to talk about expanding that project pretty soon. But it seems like the line – at least that 100-mile line could maybe be 30-inch, if not a little bit bigger. And it sounds like the line that could be going to the cryo plant in Western Pennsylvania could possibly be a little bit bigger. So is it possible at this point to put a rough estimate on ultimately where you think CapEx for the aggregate project could be?

No. As busy as we are up there, we have two kind of major focus areas in our midstream United States, of course, Permian and the Delaware Basin and Marcellus and Utica. And we, of course, can't talk on this call or publicly of all the things that we have going on. But we have huge aspirations for growth in the Northeast. It'd be hard to kind of even to guess a number, but we're very optimistic of the projects that we announced, building those projects out, adding to those project, and expanding our footprint up in one of the biggest shales in the country.

Okay. And then last question from me, Jamie, more of a housekeeping question on the synergy side pro forma the Regency integration. You guys had talked about reoccurring annual synergies of $160 million to $225 million a year. I think at last quarter when that was discussed, a lot of that was commercial and operational. And to Tom's comments earlier about redeeming that legacy Eagle Rock debt, there is obviously, at least the way we look at it, significant financial synergies. So I'm just curious in total is that still the target or has any widening of bond spreads out there in the market altered that expectation?

Hey, Darren. I suppose – just to correct you. When we said the cost savings are actually much more than the real cost, they weren't so much commercial. Not a lot of operational. It was actually much more, I want to say, back-office and more consolidation. There was some financial that was in there. So there were some assumptions. But I'll hand it over to Tom to talk to you about how we feel about the overall range and where we think we are.

Yeah. Like I probably mentioned a little bit earlier, the range we've given, we actually feel very good about, as we continue to find more opportunities on the cost side. I will say on the – I think one part of your question was even about going forward some additional opportunities. We did make, of course, a redemption notice on some 8.3/8%. These were all associated with some of the PVR bonds, as well as some 6.50%. So that's nearly $800 million of additional redemptions that will be coming in on August 13. And I think, you're going to see us continue to stay really active as far as we look at some of the other indentures out there, as far as some of the other bond issuances, et cetera. So we – and I know I am focusing more on the financing side of it. So it's not just the financing that we still see a lot of opportunities, but it's likewise on the cost side we continue to see more opportunities.

Thank you.

Thanks, Darren.

Thank you. The next question is from Helen Ryoo of Barclays. Please go ahead.

Thank you. Good morning. Just a couple of questions. I'll start with a follow-up on Mike Blum's question. So, Jamie, you mentioned doing a third-party equity on Lake Charles funding, but has your thought changed around whether you would do ETE NGL, a publicly-traded MLP versus going with a private investor?

No. I think what we said back in November, Helen, is that we're open to both. We're just looking from where we can get the best return and what's the most attractive cost of capital. This is not going to be a significant capital raise from our standpoint on the equity side. So I suppose we don't have a predisposition one way or the other. Also, we will have ETE LNG. We want that to be a separate vehicle, I think, in large part because we want the debt encapsulated in that vehicle and create some separation of almost church and state, if you will, for ETE consolidation purposes. I think also, if we're going to grow anything on the LNG side, having that separate vehicle will allow us to do more things going forward. So, I think, that's certainly first and foremost in our minds. But, as we look to raise the capital and, sort of, how we source that and from where we source it, we will just look at where we, in fact, can get the most attractive return.

That's helpful. And then your comments about your projects – that they're all pretty much backed by long-term demand charges. And, therefore, even with some concerns of overbuilding, you're really not anticipating any of these projects to not go forward. And I know that Rover and Bakken, those projects have more than 10-year take-or-pay with very good counterparty. Could you talk a little bit about other projects like the NGL and crude pipeline out of Permian, your frac projects, what are the sort of the terms and duration of those contracts there and the quality of the counterparty there?

Yeah. Helen, this is Mackie Just on the fracs, as we've stated before. When we built those fracs, they're fully contracted at somewhere in the neighborhood of 85% demand charges. So regardless of whether the gas shows up or not, those do come from a whole lot of different producers, primarily out in West Texas and also along the Eagle Ford. So we don't have any kind of significant exposure to any one producer to those frac capacity. And, in fact, any frac capacity that's available, we can sell it the day that becomes available. So that's how we're set up at Mont Belvieu. Out West on our new crude system, we haven't announced kind of who are foundation shipper is and who the additional shipper is – we anticipate signing up. We do have a very strong company to support that project and we do have a lot of interest in completely filling up that project once we complete the open season.

So the crude project is also 10 plus years of take or demand charge type of contract you have?

Yes. Well, it's – probably a better terminology is true-ups – volume truly-ups. But, yes, they are demand charges, guaranteed revenue for the capacity on that project.

And then your comment about the frac project, it goes up to the Frac IV, about 84% plus contracted. It applies to Frac III and IV as well?

Yes.

Oh, it's not. I think III and IV are actually even higher.

Yeah. We have III 100,000 day frac. The IV one is 120,000 day fracs. All four of them have been sold at 100% at approximately 85% demand charge.

Okay. Great. And then just, lastly, your Delaware Crude Gathering Pipeline Project that was just announced, just curious about doing this kind of a project at SXL versus ETP. Maybe what was the thought process doing it at ETP?

I think Mike Hennigan described it very well in his call this morning. We work together so well where we have assets, where we can feed both their crude system and also their NGL systems, where we can work together on assets we have, for example, at Mont Bellevue and connect the dots over to Nederland. So we work together very well counting our family of assets to utilize them in a manner that makes it the most efficient and the best returns we can have for our unitholders.

So is it safe to assume going forward crude gathering type of project will probably be done at ETP and will probably link into maybe SXL's takeaway or long haul pipe? Is that sort of how you guys think about dividing projects between the two?

We really don't do that. We look at all the assets we own. We look at repurposing assets for different types of uses. We look at analyzing what we have and how it might fit into the family of assets, in this case, into SXL. So, no, we don't have any ironclad rules that we do certain thugs and they'll do certain things. We're separately run limited partnerships. And where it makes sense to utilize our assets in one manner we do it. Same with SXL, where it makes sense to team up we'll do that.

All right. Thank you very much.

Thanks, Helen.

Thank you. The next question is from Ross Payne of Wells Fargo. Please go ahead.

How are you doing, guys?

Hey, Ross.

Nice quarter there. Also, it looks like on a combined basis the leverage did tick down, if I combine ETP and Regency last quarter and what happened this quarter. We're calculating about 4.9 times leverage for the quarter. I know you've got 4.5 pro forma for your growth projects. Do you expect to kind of move that GAAP EBITDA down – that EBITDA number down over time from the 4.9 level we're seeing today, or what level of comfort do you have at looking at that number? I know rating agencies may give you some benefit for construction, but historically they kind of stuck to debt to EBITDA?

Yeah. I'll take that, Ross. First starting, when you have the, for example, the $11 billion worth of growth projects we have out in front of us, obviously, it's common in all these facilities to be able to have the material project adjustment that occurs here. I will say, in even talking with the rating agencies, what they do in all of our dialogue is they look at what kind of pro forma adjustments that we put out there and then they see how we perform against those. And we've done a very good job of hitting all of our numbers. So, I feel like we do get a lot of credit for those with the agencies. And that they are very comfortable with where our leverage is right now. I think the first part of your question was do you see that gap narrowing a bit? I guess, that's a tough one – I think it's a tough one for us to say that you're not going to always have those out there. Just going back to Mackie's comments of the continued projects that we see and the opportunities we see, I think, you're going to see those projects remain out there as you look out, which is always going to have a gap. And that's the dialogue we have with the agencies. And, once again, they're very comfortable with what we see. So, our target is to always look at that 4.5 times. And so, obviously, we were very pleased when we saw it tick down a bit to the 4.59. And then I'd like to add that we've got some of the liability management that I went over a little bit earlier that will continue to bring some of the higher coupon debt back in. So, hopefully, that answers your question there. But, I think, as we look out, we feel comfortable with where the balance sheet is and the funding flexibility that we have.

Okay. Thanks so much, Tom.

Thank you. The next question is from Shneur Gershuni of UBS. Please go ahead.

Hi. Good morning, guys.

Hi, Shneur.

Most of my questions have been asked and answered. I was just wondering if we can just focus on the Regency assets a little bit and not specifically about the synergies. But we've been hearing, as earnings season has progressed, that volumes have surprised many of the processors to the upside. And, at the same time, in certain regions, there seem to be contracts that are up for bid. That there's some market share changes occurring as well, too. I was wondering if you can sort of talk about the landscape across the legacy Regency footprint and how you're positioned, given these changing dynamics.

This is Mackie, Shneur. I mean what a great question. And the reason it is, after closing on Regency, we can't move fast enough to build capacity that's already been contracted. There are hundreds of thousands of acres that were dedicated to Regency assets, now ours, both from a gathering and a processing perspective. And so we're moving forward as quickly as we can to build a much bigger system in West Texas, in Delaware Basin, to add processing plant and, for example, a plant that we're building next to Red Bluff called Orla, we expect to bring that on in the first quarter of 2016. It will be full within 30 days of bringing it on. So the biggest challenge we have with the Regency acquisition is building the assets quick enough to accommodate the volumes that are committed to.

Cool. All right. Thank you very much. Appreciate the color. And good luck today.

Thanks.

Thank you. At this time, I would like to turn the conference back over to Mr. Welch for any closing remarks.

Thank you, everyone, for your time this morning. And we look forward to talking to you next quarter.

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