Welcome to the Energy Transfer Partners and Energy Transfer Equity Third Quarter 2015 Earnings Conference Call. [Operator Instructions]. I would now like to turn the conference over to your host, Tom Long, Energy Transfer Partners' Chief Financial Officer. Thank you, sir; you may begin.

Thank you, operator. Good morning, everyone and welcome to Energy Transfer Partners and Energy Transfer Equity's third 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 third 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 us answer your questions after our prepared remarks. I'll begin with discussing our third quarter results, followed by a growth project update, a financing and liquidity update and concluding with a distribution discussion and a brief ETP/RGP synergy 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 will find a reconciliation of our non-GAAP measures on our website. Now for our Q3 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. Also note, effective July 1, ETE acquired 100% of the membership interest of Sunoco GP LLC, the general partner of Sunoco LP and all of the incentive distribution rights of Sun from ETP. As a result, ETP no longer consolidates Sun for accounting purposes going forward. ETP's remaining proportionate investment in Sun is accounted for under the equity method. Now for ETP's third quarter results, adjusted EBITDA on a consolidated basis totaled $1.5 billion which is up $48 million compared to the third quarter of 2014 and was slightly above consensus. DCF attributable to the partners of ETP, as adjusted, totaled $740 million, a decrease of $130 million from a year ago. Overall, we had strong performance from our NGL business and solid performance in the inter- and intra-state pipeline segments. However, DCF for the third quarter was affected by a partial reversal from the second quarter 2015 tax benefits, with $79 million of current income tax expense for the third quarter of 2015, as well as lower NGL and gas prices, continued shut-in in volumes in the Northeast and unscheduled plant outages in the Permian region. Now let's go over individual segment results. In the midstream segment, adjusted EBITDA decreased by $61 million to $318 million compared to the same period a year ago. This decrease was primarily driven by lower commodity prices and plant outages in the Permian, partially offset by higher throughput volumes. Gathered gas volumes totaled over 10 million MMBtus per day which is up 13% versus the same period last year, primarily due to production growth in the Eagle Ford, Permian and Cotton Valley regions, as well as the King Ranch acquisition. In the liquids transportation and services segment, adjusted EBITDA increased by $29 million to $192 million compared to the same period last year. The increase in adjusted EBITDA was due to higher throughput at Lone Star fractionators and West Texas NGL pipelines, as well as increases in storage margin due to the ramp up of the Mariner South and related storage fees. NGL and crude transportation volumes on our wholly owned and joint venture pipelines increased from a year ago by nearly 90,000 barrels per day to 443,000 barrels. This was, in large part, due to increased volumes out of West Texas, as producers ramped up volumes, as well as commissioning of a crude transportation pipeline at the end of 2014. The remainder of the increase was related to volumes on our NGL pipelines from our plants in Southeast Texas and in the Eagle Ford region. Average daily fractionated volumes increased approximately 10,000 barrels per day from a year ago to 237,000 barrels, due to the ramp up of our second 100,000 barrel a day fractionator in Mont Belvieu which was commissioned in late 2013. In our intrastate statement, adjusted EBITDA increased slightly year over year to $127 million. This was primarily due to increased transportation fees recently renegotiated and newly initiated long-term fixed-fee contracts for Mexico export volumes on our Houston pipeline system, partially offset by lower retained fuel revenues and lower natural gas sales. Transported volumes declined compared to the same period last year as a result of lower production in the Barnett Shale which was partially offset by a ramp up in volumes related to the new long-term contract just mentioned. We expect throughput to stabilize, as increased natural gas demand from Mexico and the Gulf Coast LNG facilities helps offset declines in the Barnett Shale. In our interstate segment, adjusted EBITDA decreased slightly to $286 million from a year ago, partially due to the removal of Trunkline's 30-inch line from natural gas service in July. This line is being converted from natural gas to crude oil service as part of the Bakken pipeline project. Transported volumes were up approximately 117,000 MMBtus per day due to the increased throughput on the Tiger and Transwestern Pipelines. Moving on to Sunoco Logistics, who had a tremendous quarter, with EBITDA of $289 million which was predominantly blue-bar. This was $43 million higher than SXL's third quarter of 2014. Moving to retail marketing and as a reminder, effective July 1, ETE acquired 100% of the membership interest of Sunoco GP LLC, the general partner of Sunoco LP and all of the incentive distribution rights of Sunoco from ETP in exchange for 21 million ETP common units previously owned by ETE. As a result of this transaction, ETP no longer consolidates Sunoco for accounting purposes. ETP's remaining proportionate investment in Sun is accounted for under the equity method. This change impacts the comparability of segment results versus prior periods. Starting this quarter, adjusted EBITDA for the retail marketing segment will be reported as ETP's 100% ownership of the assets in Sunoco, Inc. and includes adjusted EBITDA related to the unconsolidated affiliates which is comprised of our 68.4% interest in Sunoco LLC, the wholesale distribution business and our investment in Sunoco LP based upon ETP's percentage ownership of the outstanding LP units. For the third quarter, the retail marketing segment contributed $195 million of adjusted EBITDA; a really strong quarter based upon higher fuel margins and volumes, as well as solid same-store sales growth. For all other segment, adjusted EBITDA increased $32 million to $92 million versus a year ago. As it relates to the PES IPO, this has been postponed and will restart when market conditions improve. We still view this interest as an attractive near-term monetization option for ETP. Now let's move to our growth projects, where I'll provide a brief update. We will discuss these projects in more detail at our Analyst Day on November 17. Starting with the Bakken pipeline project, we remain in the process of obtaining the necessary permits and regulatory authorizations for this project. The current regulatory timetables for the applicable state agencies have those authorizations coming in late 2015 or early 2016, providing us with sufficient time to construct the project in accordance with our anticipated completion schedule of Q4 of 2016. I do want to point out that last month we closed on our previously announced transfer of a net 30% interest in the Bakken pipeline project to Sunoco Logistics. In exchange for this interest, ETP received from SXL 9.4 million class B units, representing limited partnership interest in SXL and $382 million of cash representing the reimbursements of SXL's proportionate interest of the capital spent to date on the project. With this transaction now complete, the net ownership in the Bakken pipeline project is as follows, ETP owns 45%, SXL 30% and Phillips 66 owns 25%. Next, on Bayou Bridge which is a JV we formed with SXL and Phillips 66 to develop a crude oil pipeline from the Phillips 66 and Sunoco Logistics terminals in Nederland, Texas, to St. James, Louisiana. Construction is under way on the Nederland to Lake Charles segment of the pipeline which will be 30 inches in diameter and is expected to begin commercial operations in the first quarter of 2016. The joint venture has commenced an expansion open season for service from Lake Charles to St. James to determine the pipeline diameter of this segment which is scheduled to commence service in the second half of 2017. For the Rover gas pipeline, we expect to receive the draft EIS by year end and the FERC certificate in 2Q of 2016. We anticipate being in service to the midwest hub near Defiance, Ohio, by January of 2017 and to markets in Michigan and the Union Gas Dawn hub by mid-2017. Completion of Lone Star's Frack III has been accelerated and is now scheduled to be in service by mid-December 2015 and will come in under budget. And Frack IV remains on schedule to be in service by December of 2016. The Lone Star Express NGL pipeline remains on schedule to be in service by the third quarter of 2016 and the conversion of our existing West Texas 12-inch NGL pipeline into a crude oil/condensate line remains on schedule to be completed in the first quarter of 2017. The Trans-Pecos and Comanche Trail pipelines which will expand our intrastate pipeline capacity to carry gas from the Permian Basin to Mexico, remains on track to be in service in the first quarter of 2017. And at this time, the project financing is expected to close shortly. We also began flowing gas to our Edinburg pipeline in South Texas last month and we continue to ramp up volumes to Mexico through our 36-inch Nueces pipeline. The in-service date on both the 24-inch Volunteer pipeline and the 200 million cubic foot per day cryo East Texas plant, also known as the Alamo plant, remains year-end 2015. In the Northeast, construction of the 2.1 Bcf per day Utica Ohio River expansion continues and Phase I was placed into service in mid-October. Phases II and III are expected online by the end of this year. The Delaware Basin crude gathering pipeline, when completed, will consist of three separate gathering systems with an aggregate of approximately 130 miles of pipe. The gathering system which will have approximately 120,000 barrels per day of crude oil capacity, will deliver crude oil into SXL Delaware Basin extension. Our gathering pipeline is projected to be in service by the first half of 2016. And one final update on our projects, the Revolution project, the pipeline and plant, as well as the fractionation facility, are expected to be in service in the second quarter of 2017. As a reminder, our project provides shippers with a unique end-to-end solution with significantly improved net-back economics compared to their other alternatives. Now moving to our CapEx discussion, ETP invested over $1.6 billion during the third quarter in growth CapEx projects, with the majority allocated to our liquids transportation and services, midstream and interstate segments. For the nine months ending September 30, ETP has now invested more than $4.3 billion in growth CapEx projects in 2015. For full-year 2015, CapEx for ETP is expected to be in a range of $5.7 billion to $6 billion. Before moving on to discussions on distribution, let's take a quick look at ETP's liquidity position. We ended the quarter with a debt-to-EBITDA ratio of 4.49 for our credit facility. As of September 30, 2015, there were $665 million in outstanding borrowings under the $3.75 billion credit facility. We also issued approximately $306 million of equity during the third quarter of 2015 under our ATM and DRIP programs. Now I would like to touch on our recent distribution announcement. Last week, we were pleased to announce the ninth straight quarterly distribution increase for ETP to $1.055 per common unit or $4.22 per common unit on an annualized basis. This represents a distribution increase of $0.32 per common unit on an annualized basis or 8.2% compared to the third quarter 2014. And it will be paid on November 16 to unitholders of record as of the close of business today. We continue to be pleased with the progress we have made on the ETP Regency integration. We have initiated work on most of the synergy opportunities and feel very good about achieving the upper end of our synergy range of $160 million to $225 million. And with that, I'll turn the call over to Jamie, who will walk you through ETE's results.

Thank you, Tom. Good morning, everybody. We will first touch on the ETP/ETE Sunoco GP IDR exchange that Tom alluded to earlier in the call. Then I'll provide a liquidity and financing update, then a brief update on Lake Charles LNG, to be followed by the third quarter results, before concluding our prepared remarks with an update on ETE's merger with Williams and we will then take your questions. We were pleased with third quarter results for SXL Sunoco and ETP. As Tom mentioned, SXL had a very strong quarter which continues to demonstrate the strength and resilience of that business. Sunoco also had a very good quarter and a resulting 2 times coverage ratio. ETP also had a solid overall performance, despite encountering and navigating some unexpected challenges. As Tom mentioned, effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP LLC, the general partner of Sunoco LP and all of the IDRs of Sunoco LP from ETP. So, Sunoco now appears in the consolidated financial statements for ETE on a go-forward basis. Let's look now at liquidity and financing. ETE continues to have a healthy liquidity position. We ended the quarter with a debt-to-EBITDA ratio of 3.27 times per our credit facility. And as of September 30, 2015, there were $930 million in outstanding borrowings under the facility. Therefore, at the end of Q3 2015, the overall ETE stand-alone net debt was $6.370 billion with a blended interest rate of 4.8% and with no pending maturities until almost 2019. Since June 30, we have repurchased approximately $770 million of additional ETE common units under our buyback program. Now, quickly turning to Lake Charles, progress continued to be made during the third quarter. We're awaiting our final FERC authorization which we expect in the next week. And at that time, we should also receive the approvals from the other federal agencies and that federal decision day deadline is November 12. Following receipt of these final regulatory approvals, we intend to launch our debt financing for the project and we remain on target to reach affirmative FID of the project in 2016, with construction expected to start immediately thereafter and first LNG exports anticipated in late 2020. Turning now to the financial results and as a reminder, ETE's cash flows come from the general partner and IDRs and LP interest at ETP, 90% of the economics of the GP and the IDRs from SXL through the Class H units, through the ownership of Lake Charles LNG and now, 100% of the GP and IDRs of Sunoco LP. Our distributable cash flow as adjusted for the third quarter totaled $325 million or $0.31 per unit, an increase of $91 million or 39% compared to the third quarter of 2014. Distributions from ETP accounted for 71% of ETE's total cash flow in the latest quarter. SXL contributed 16%, Lake Charles LNG approximately 11% and now Sunoco LP contributed 2%. ETE announced last month the 12th consecutive increase in its quarterly distribution to $0.285 per unit; annualized this equates to $1.14 per unit. Our distributable coverage ratio was 1.09 times for the third quarter. The quarterly cash distribution represents a 37% increase in distribution per unit compared to a year ago. It will be paid on November 19 to unitholders of record as of the close of business today. On the Williams side, we previously announced in September the merger of ETE with Williams. The combination will create the third-largest energy franchise in North America and one of the five largest global energy companies. We filed our Hart-Scott-Rodino application on October 20 and we expect to file shortly the draft S4 Proxy with the SEC. We remain very confident in completing the merger in the first half of 2016. In October, we entered into an amended and restated commitment letter with a syndicate of 20 banks for a senior secured credit facility in an aggregate principal amount of $6.05 billion in order to fund the cash portion of the Williams merger. Under the terms of the facility, the banks have committed to provide a 364-day secured loan that can be extended at ETE's sole option for an additional year. The interest rate on the facility, while floating, is capped at 5.5%. We have now finalized the respective appointments to the integration committee for the merger and we intend to actively implement the shared service model that we've talked about, with the intent to have it in effect as at closing. Before opening the call to your questions, I would just like to say that we've seen some tremendous business performances across the Group in commodity markets that have been extremely challenging. The Group is built to withstand any challenge. ETE will support its core operating subsidiaries and fundamentally believes that that is its role as the GP of the Group. We continue to be very proud of our overall performance. We have continued our distribution increases and we're determined to maintain these increases through this challenging cycle. Our overall project backlog remains without peer and is built on long-term, third-party contracts with demand fees that give us tremendous visibility and confidence in the future EBITDA growth. We're highly confident that these projects are tracking on schedule and on or under budget and there is no contract abrogation risk. Our counterparties are strong, high-quality companies or have security for performance that is well structured to mitigate risk. This growth plan sets up ETP and SXL for another period of transformation after 2016. We see the clear benefits of our diversified business model which, as we've said before, has the most strategic and financial optionality in the industry. And with Williams, the Group will be even stronger. We appreciate the continued support of our customers and our investors and we appreciate the hard work of our employees who have contributed to this strong overall Group performance. Operator, that concludes our prepared remarks. Please open the line for questions.

[Operator Instructions]. Our first question is coming from the line of Shneur Gershuni with UBS. Please proceed with your question.

Before getting to my bigger picture questions, I was wondering if you can reconcile your DCF results versus the EBITDA results at ETP? When I look at the headline EBITDA number, it was in line with the Street, but the DCF was below. In our estimation, it looked like there were some non-recurring items and the results to suggest that there's potentially a higher, cleaner number for an ongoing result. Can you walk us through the items and confirm if they are one time in nature and what was the clean number for DCF in your view for ETP?

You bet. This is Tom Long. Clearly, when we get through each one of these quarters, we do look at what we call kind of the non-recurring type items and of course, the first one is one that we talked about in the earnings release which is the tax piece of it. That's the $79 million reversal, so if you first add that one back, you can see that you're up to a coverage ratio already into the low nines, but we also, in addition, had a few, from a volume standpoint, in the Midstream. Both some of the volumes up in the Northeast, some of the shut-ins and then some operational items in the Permian. That one is, those added up to probably a little less than $20 million and then we had some maintenance capital increase that we considered a few of these items is really non-recurring in nature and those were a little bit over $20 million. So all in, if you add these up, you can see what number we were working with which was about $860 million in DCF on an ongoing basis which that gets you to just right at the one time, just maybe a couple of basis points below.

Just thinking bigger picture and looking at the proposed Williams transaction, it would appear that organic investment in Northeast is the significant part of the story. I believe you mentioned $5 billion of capital investments to generate $2 billion of EBITDA. This seems like an incredibly high return multiple and when I compare it to historical industry norms, it suggests a lot of greenfield investment. Would you be able to walk us through where you expect this greenfield high return type of investment? Which partnerships are most likely to benefit as a percentage of the capital relative to their size?

Sure, Shneur, it's Jamie. So as we said on the $5 billion, it has a lot of different components in it, in particular as it relates to the Northeast. Included in that, whether for better or for worse, from our standpoint, we included, obviously, an expectation around ME-2X and the PDH facility as part of the overall capital needs. Now as you know, ME-2X is an abiding open season for the folks at SXL and obviously, is subject to the level of commercial interest that will then determine its likelihood to go forward. But the real beneficiary, as we've sort of articulated to many of the people on the phone as it relates to the Northeast, is really sort of almost the redirection of a lot of the Williams barrels or I should say, the liquids barrels that are touched by the Williams system that right now, are not committed or contracted on the ME-2 side. Now, as Mike Hennigan has repeatedly told everybody, he's had a tremendous success with the core customers of Mark West and their support for the ME-2 franchise, but was lot less successful with a lot of the Williams customers that obviously, whether it's through OVM, UEO or even through the blue race of Midstream facilities, actually, would move there overall hydrocarbons and obviously then, their liquids. So our anticipation is SXL will be a large beneficiary, I would say, certainly, on the liquid side and then it's really going to be, as Mackie would tell, WPZ and ETP around what we do on the gathering side because you've got two great companies with great sets of capabilities to really capitalize on sort of that area which to us, continues to go from strength to strength; notwithstanding that you've got some shut-in in volume simply because of price, lack of takeaway capacity. As Mr. Warren keeps telling us, you build takeaway capacity, you create a better environment for people to capitalize on the value for their product and people will keep drilling and we'll be able to make money because we'll be able to offer more services.

So when I think about your comments, it would appear that SXL is pretty much a very important cog in the proposed organic investment cycle. As I think about it, it means that you would need to continue benefiting from an advantage cost of capital. Some investors have expressed concern about the potential for assets to be put into SXL from elsewhere in the family, can you comment about how you think about SXL and whether these concerns are unfounded?

Shneur, I take it the question is do you think that we would sort of exploit SXL's cost of capital to serve alternative purposes within the family? Is that the gist of the question?

Effectively.

Okay.

This is Kelcy. No, we don't do that.

I mean, we've never done it to date. It's not the way we operate. It's not the way we believe -- it's not in our belief system of the way that you operate a business successfully. I think SXL has done a great job and now it will benefit, but our viewpoint is it continues to run its own course.

So what you're essentially saying is that you continue to expect SXL to continue financing itself as it is and to be more focused on organic growth? Is that a fair way to think about it?

Yes. But also, its our belief from all the MLPs that are under ETE that to correctly grow yourself, build yourself for sustainability, you must have a diversified cash flow. And SXL is not as pretty as I would like to see them, although they're getting pretty cute. But I would really like to see them kind of broaden their services ultimately. If we're successful with Williams, I'd love to see WPZ do the same thing and Sun -- ETP's done a very good job, but it's just now beginning to show as to how important it is to be diversified across the services that they provide. So there's some improvements that we'd like to see with SXL, but I think Mike Hennigan and his team are doing about as good a job as any Management team I've ever seen in running their business.

Our next question is coming from the line of Michael Blum with Wells Fargo. Please proceed with your question.

The big picture question I wanted you to address if you could is just obviously, you've got a tremendous amount of organic opportunities across the various MLPs in the Energy Transfer family, but that comes with a lot of financing as well. So can you just address how you're thinking about financing over the next two to three years? And how ETE could play a support role, potentially, in that financing? Then I guess, specifically, if you talk -- also interested about how you're thinking about supporting WPZ in light of where the equity is trading right now? Thanks.

I will take maybe the first part of this and then maybe we'll tag team this one a little bit. But looking at it from an ETP standpoint, the beauty of the entire Energy Transfer family here is that we do have a lot of different leverage and a lot of different options of what we can do. So as you kind of look at 2015 and the CapEx that I talked about little bit here, you can see with where we're right now, for 2015, basically we're zero drawn on the facility as we sit here today, the $3.75 billion facility. Just to update from the 930, that's post the ownership that SXL took into the Bakken pipeline. And then we're going to continue to utilize, to be opportunistic on the ATM program. In other words we really don't have any type, overnight or any type, equity offerings planned at this point. The other thing I want to be sure I highlight here is that the leverage ratio, you saw it actually drop on the pro forma basis with the -- assuming the calculation per the credit facility. You know that's very important. That's a very important piece of it as we look out and we decide how much is going to be debt, equity or like I say, some of the other options that we have at our disposal. So the $5.7 million to $6 billion that we put for 2015, we feel very comfortable as we go through this fourth quarter with where we're. Then we'll continue to look out at 2016. There's been a lot of dialogue about the retail gasoline assets, c-stores, et cetera and that's where I'll probably go ahead and hand it off to Jamie. But I do want to add one more piece before doing that, is as we continue to fund these growth projects which I think it's very clear that we've come a long ways with where we're in the funding looking through 2016, but a real key component that we do spend a lot of time with the rating agencies, we communicate on a regular basis with them, is talking about these projects and the pre-funding of these and then where we're going to be. I think I real key component to getting the rating agencies comfortable is your track record. Your track record of delivering on time, under budget and to have good committed quality counterparties on these projects and that's something that, once again, we have a great track record of. And so that is always actually a very easy conversation with the rating agencies as we walk through that. So anyway, it's always an important component as we look out and Jamie, why don't you go a little bit with a little more detail on the drop discussion?

So Michael, as you know, right now, the anticipation, if you look at the about $11 billion which is commonly referred to out there as the capital program between 2015 and 2016 for ETP would mean that we've got about $5 billion, as you can see at the back of the earnings results, if we've got to sort of get to close to $6 billion spend for the sure. We've said that the drops obviously remain a big piece of that, then you've got some ATM in the balance, would just be traditional -- that will be traditional debt. We've got some other options, as you know, within the overall arsenal that we have as far as different levers for ETP because we're very mindful of -- and I don't think people fully appreciate, when you spend $6 billion and you have a blended cost of capital between debt and equity, including the IDRs of say 9%. So $6 billion, you're carrying almost $514 million of cash burden on your back for which you get no cash flow until assets go in service. That's a massive amount versus our, if you just look at four times our current distributions at sort of around $3.5 billion which is a full year of DCF, that's a lot to carry on the back of obviously ETP and its balance sheet. And it's done a phenomenal job that we've continued to deliver performance that's allowed us to do it. So we've always said, we're taking on a tremendous challenge. We will make it. It's transformational for this Company and we'll get there through 2016. As far as ETE is concerned, Kelcy is in a much better position to articulate that, but we will do whatever we need to from the ETE standpoint to help ETP. That's what we do. That's how we run our business and that's what we believe. The right thing here is a very healthy ETP and I tell you, sitting 12 months from now I think we will be the proudest people on the planet that we will have got through this incredible build cycle with some of the best projects in the industry, as well as Williams. It's going to be a tremendous, tremendous accomplishment for this overall group.

Just two quick follow-ups to that and I appreciate all that commentary. One, just where are you comfortable managing leverage at ETP during this build-out phase through 2016? And then a second question is, if you're willing to talk about it is more specifically, just what are the latest thoughts in terms of drop downs of the remaining assets to Sunoco? Do you think that'll be multiple small drops or one big drop? Thanks.

I think it's too early to say which way it's going to go as far as is it multiple drops or it's one drop. I think there's a -- simplicity would tell you, if you could do it and you could do it once, it's obviously better to do it quicker and simpler. It is a lot of benefit, I think, for Sun, there's a lot of benefit at ETP. There is obviously -- we recognize there's an overhang on Sun. There's an overhang on ETP because there's obviously a recognition that it's a piece of, obviously, the capital funding that we're looking for 2016. The conversations are continuing between Sun and ETP, I would tell you and between the three entities, ETE, ETP and Sun. We continue to have those conversations and when we've got something to tell everybody, we'll let everybody know.

And as to the leverage part of your question, Michael, we, of course, target the 4.5, like I mentioned, but we're comfortable with moving this to 5. And the reason I can say that is because it's back to that kind of the comment as you look out and talk with the rating agencies, its all about where you're going to be as you complete these projects going forward. So I think up in that 5 range is definitely doable, but we're going to continue to manage toward that 4.5, I will tell you that.

Our next question is coming from the line of Helen Rue from Barclays. Please proceed with your question.

So operational question on Midstream, I guess there was some shut-ins and a plant outage. Where are you -- is that pretty much resolved? When it comes to the equity volume drop, I guess some has to do with the operational issues and some with the contract renegotiations, could you maybe talk about that little bit? Where that's taking place in terms of Basin and who's sort of initiating that discussion? Is it you guys or the producers?

You bet. Helen, this is Mackie. As we've kind of closed out the Regency acquisition and get our arms around those assets, we're out in the area where we have had some difficulties with some of the plants. We have lined those out. The facilities that were impacted are up and running in great shape. Also, it has been mentioned, we talked about the bigger projects that are coming online a year from now, but some smaller projects, for example, our Orla facility, that's a 200,000 a day cryo that's coming on first quarter of next year and there's over 200,000 Mcf that's dedicated to that plant that will come online almost simultaneously. So we've kind of weathered the storm on volume impacts, whether it's plant issues or whether, up in the Northeast, it's pipeline issues or pricing issues. We continue to kind of battle through that. We believe we've turned the corner in not only getting all that lined out and that revenue flowing, but also expect to have some fairly significant revenue growth with assets that we're bringing on in the first and second quarter of next year.

Okay. And then the contract renegotiations, could you maybe touch upon that a little bit?

The contract negotiations as a whole?

Yes.

As a whole, for example, our strategy on West Texas and I want to sling this to a lot of detail is that we have, are building Orla and we'll be announcing another plant in a very new future, we've had the opportunity to build what we call firm space instead of allocated space which has always been ETP's strategy over the years. And in doing that, we've been able to and are continuing to negotiate rolling over agreements that end in three or four years and extend those out seven or eight more years making it 10 year contracts. The negatives of the issues that we've had here earlier this year in the last quarter have turned to positives in regards to extending contracts by creating a firm demand charge or fee-based type capacity which we see as very positive for our partnership in the future.

Okay.

This is Kelcy. I'd like to add. I'll give you just one example. We have a very large producer that, due to commodity prices falling that probably their drilling activity in an area is not going to support their volume commitment. They've asked if we would work with them to change that contract, ratify the contract and what Mackie and his team are doing is they're looking at other areas in the country where either natural gas crude or natural gas liquids are not going to us and so this particular party could, in fact, direct those barrels or gas to us and we both do well. Very similar to what Williams and others have done and so there's -- that kind of dialogue is going on in many parts of Energy Transfer today.

And just going forward, should we expect your equity volumes to perhaps stay flat or maybe go down as a result of maybe more of these contract renegotiations going on? Also, with the new plants coming online, as Mackie mentioned, should that be fee-based rather than POPs?

Helen, it is a combination but yes, by and large, we're sticking with our strategy that we believe works. Also, with the producers are asking for, both at Orla, we're also bringing on our Alamo 200,000 a day cryo and those are mostly fee-based business where we don't have a lot of equity risk around the pricing of the liquids or the residue gas, but yet, we benefit from not only the gathering and the processing, but also the residue, downstream revenue and the downstream TNF for our Lone Star group.

And then just on interstate, I guess could you maybe talk a little bit about the dynamics there on what's driving the favorable market condition and higher demand at Transwestern line. I think a portion of the trunk line was taken out of service and what's the financial impact from that line taken out of service and how long would that go on? Is it until the project finishes?

Well, as we've mentioned, as you know, we took that out of service the middle of this year. It did have a financial impact; however, prior to taking that out of service and even as we speak today, we have contracted backhaul capacity on the existing 36 inch that still remains in gas service with our Rover project. We'll see that volume grow exponentially as we bring that on the later part of this year and the early part of 2017. We've also been able to extract larger margins on the capacity that's available that we sell on a month-to-month basis, because of course, there's less capacity now going north when it's needed. So yes, there is, of course, a financial impact by taking a 30 inch out of service, but we're making up for that by a stronger fees for new business and for the backhaul business that we continue to contract.

And then lastly, just on Midstream spending, I mean that's been one of the biggest spending for this year. As you look at next year, have you talked about the total spending on revolution and the updates there and what the total Midstream spending would be in your 2016 CapEx?

I think on the revolution in particular, Helen, we said around $1.5 million, although I think would Mackie would be tell you it's probably likely to be inside of that number. I don't think we've given a specific number for Midstream as far as overall expectations next year, but just -- we'll do that over the course of the next quarter when we basically come out with capital guidance for 2016.

Our next question is coming from the line of John Edwards from Credit Suisse. Please proceed with your question.

Jamie, you alluded in your prepared comments about the tremendous organic backlog you have. Help us think about reconciling that against comments by others in the industry that certain areas are overbuilt. Is it more just you've got specifically commercially underpinned projects so that you're more or less immune to that or are you expecting maybe perhaps some sort of push out a little bit on some of your backlog? How's that coming together? How are those dynamics working?

I would tell you, John, on the actual backlog, as we were very clear in the remarks I made earlier, they are fully supported by third party demand fee long-term contracts. I think our viewpoint is that these contracts by the way, whether it's on the gathering and processing side or the gas side, are 10, 215 to 20 years of duration. They give you a long, long runway of certainty of demand fees and obviously therefore, distributable cash flow. So I think our viewpoint is, as we capitalized incredibly well, I think, given the talent of the commercial team, on what was the supply push dynamic that existed leading up to 12 months ago. And now we recognized the next chapter of growth, most likely post-Williams for us, will be a lot of demand pull and we're going to have more assets than just about anybody that we will be able to capitalize on for customers and consumers to actually make sure that we can get the hydrocarbons to the best places possible.

John, this is Kelcy. I would, as far as comments by others in our sector, there's no question there's certain areas that are overbuilt. There's no question. For example, I mean, we overbuilt in the Barnett Shale. The production peaked and it's now down. So I wouldn't argue with those statements. I think throwing the industry under the bus, though, I'm going to argue that. Because one thing you've got to do in this business is you can't build your business around basis differential between say West Texas and Gulf Coast or Cushing and Gulf Coast, you can't do that. You must diversify and when one area is challenged from a basis, another area is growing because there's lack of infrastructure, so you must diversify your cash flow stream and that's what we've done here. I hope it's being noticed and that's what the whole family concept is, too. So as far as those comments go, sure. I'd hate to be caught as the Texas intrastate pipeline today, it wouldn't be a very nice life, but fortunately we have diversified and we're not there.

Our next question is coming from the line of Darren Horowitz from Raymond James. Please proceed with your question.

Quick question, I'm curious, just briefly, on cost of capital and support in the family concept like you just mentioned, Kelcy. With ETE's excess coverage and obviously, you mentioned the ETE buyback in the quarter, how do you balance repurchasing ETE common units versus maybe a direct investment in ETP? Outside of the opportunities to enhance some of the other LPs, just from an internal perspective, how do you think about other capital structure options to better manage that cash burden through the build cycle and maybe shave a little bit of return to your side with regard to cost of capital?

Jamie, I'll let you take the second one, I'll do the first. Darren, we're going to absolutely -- ETE is going to do whatever is necessary, Jamie said that earlier, but I want to reaffirm that. We're going to do whatever is necessary. If ETP needs help in the way of IDR subsidies, IDR givebacks, things of that nature to make projects more accretive and improve ETP's financial health, you can guarantee ETE will do that. We're watching that closely. At the same time there's some ETE unitholders on this call, too. And it's not, were not giving away candy bars around here, we're trying to get everybody to stand on their own feet and do their job. But as you know, the math tells you when you get as big as ETP is that the GP needs to step up and subsidize growth from time to time and we will do that. And Jamie would you - -

Yes, so on cost of capital, Darren, I would say, specifically as it relates to ETP, the focus is that Tom Long and I have is looking to in fact, create equity content within ETP to complete the build program without having to rely solely on just units. And so there's a lot of, as we keep mentioning, whether it's a PES stake, whether it's the monetization of the residual balance of the retail, there's lots of different levers within ETP that create equity for the purposes of creating capital infusion for the build program without relying on creating -- on issuing units that have a price and an IDR obligation that attends to it. So I think we're looking at it, as Kelsey said, we, from an ETE standpoint, whether it's on the buyback, I think we've been very comfortable where we're from a buyback standpoint. As we think about what makes sense going forward, certainly Kelcy is going to be influenced to thinking what's in the best interests of the collective group. That's how we'll look at it and we'll go forth from there.

Jamie, if I could, just one quick housekeeping question, as you look forward to launching that debt financing on Lake Charles, has anything changed with regard to the expected costs? Are you still forecasting just over $9 billion? Has there be any shift in your top process with regard to the duration or the structure of the debt?

No, Darren, I think that's twofold. One is, I think our viewpoint is and we'll probably just mentioned this on Analyst Days, is that our expectation on the overall cost, much like many projects across of anyone is undertaking large capital projects right now, is the costs have come down. That obviously benefits, since we earn a return on a effectively on invested capital standpoint, so that works to the benefit of obviously BG and Shell. As it relates to the debt, much like what has been done before us, we will put in place bank financing that gives us financing that is the most flexible. We draw it as needed, as basically spent over the EPC contract life and we'll be sort of a seven or eight year facility that's put in place and then, as we go forward, we'll look to turn that financing out in the capital markets. So I think it's a very tried and true path that we're going to go down, very similar to the four or five other projects before us.

Our next question is coming from the line of Kristina Kazarian from Deutsche Bank. Please proceed with your question.

First, Jamie, just a quick question and this is bigger picture, but how should I be thinking about the strategy going into the Analyst Day. I don't want specific topics, but just generally, should I be thinking more updates on business, growth programs, announcements there, maybe stuff that removes the equity overhang that you guys have been alluding to a lot today? Or can we talk more about what we can do with the Williams portfolio or does that second part have to hold off until the deal closes?

Obviously if we tell you too much, it'd spoil it for everybody. So I think, look, consistent with what we did last year, we'll obviously give you a much deeper dive on the business. Because, look, I think the quality of the people that you've seen whether it's Luke Fletcher, Steve Spaulding, Lee Hanse, all these guys who've worked for Mackie and Kelcy for a long time are tremendous at what they do and they've got valuable insight. I think we'll give you insights and perspectives. We do have a large capital program, so I'm sure there's lots you want to about what's going on. As it relates to Williams, I'm sure there'll be some commentary from Kelcy, Mackie, Mike Hennigan, to talk about how they think about Williams as part of the potential Energy Transfer Group and what that does for us. So I think we'll have a little bit of everything.

Okay. And then for the revolution on update, just a couple quick clarification questions here. Can you talk -- I know you guys said thinking online 2Q 2016 or 2017, but you can talk a little bit more about producer interest, like when we get announcements? I don't think I've seen an announcement since EdgeMarc and if information here is like more eminent?

Of course, with the commodity environment, it's more difficult than it would be otherwise. The fortunate thing of that project is we bought and we're extending a line up into an area that has almost zero pipeline infrastructure, yet it's very good rock all the way up to the North end and even East to West 30 to 40 miles. So we're in a really good situation. We're in negotiations with multiple producers and we're very optimistic that's going to turn into a really good project, a huge growth area for us and also for SXL and their Mariner East revenues and volumes, in addition to, we've already announced with EdgeMarc what others we'll be bringing residue gas to Rover. So we see it as a really good foothold in an area that, even in tough commodity times, will turn out very well for us.

And when I think about the next set of updates, do I get them piece by piece or do I maybe get total stream, meaning like pipe, plant, frac all at the same time?

We probably want to announce every producer that we sign up, but certainly as we expand to a second plant and add fractionation, I'm sure we'll let the public know that.

Okay and then last quick clarification question for me, I know you guys talked a little bit just about Lake Charles and financing on it, but can you talk a little bit about the FID process and updates on Shell's current thoughts or conversations you guys have been having there.

I would say, Kristina, we continue to move forward from an FID standpoint, we're really waiting just for our FERC authorization. Once we have that, we continue to, in fact, identify the early works that we will, in fact, fund as part of our 2016 budget. I think we're signing up contracts on various things. We're doing local community initiatives right now. I mean there is a lot of activity that's probably not necessarily visible to you that's going on that is part and parcel, as we move to this last stage between all the regulatory approvals and then the FID process, I think the folks at Shell BG have also focused on just getting their merger closed which we respect and understand. I think we're working with our project team and continue to sort of make projects with our EPC contractors and on the other elements of the overall development schedule.

Our next question is coming from the line of Elvira Scotto from RBC Capital Markets. Please proceed with your question.

I'm not sure if this is a question for you or for Sun, but Kelcy, you mentioned you'd like to see Sun diversify its business a little more. Can you elaborate on that a little bit? Would you like to see diversification into adjacent areas, maybe terminals or just broader diversification? Would you follow sort of that ETP blueprint how ETP kind of grew out of propane into what it is today?

Absolutely. First of all, Sun is an incredibly run business. These people really know what they're doing. But I don't like businesses that you can work as hard as you can, be the brightest people in your field and when something goes against you, like crude prices rising, you make less money. I don't like those businesses. So therefore, I would like to see Sun and Bob Owens knows this, Bob reports to me and does an outstanding job, I would like to see him diversify into businesses that are complementary to his retail sales. So terminaling more access to the wholesale market, less - - in other words, every area where Bob is paying somebody else to provide a service, I would like to see him get into that business.

Our next question is coming from the line of Mark Reichman from Simmons. Please proceed with your question.

I was hoping you might be able to just recap your projects aimed at serving the growing natural gas exports to Mexico. And also, talk a little bit about what knocked on effect that might have for your intrastate gas pipeline systems and then an update on Trans-Pecos?

Of course, a very exciting area for us to talk about for the reasons you just said. We kicked off our first flows through our 36 inch Nueces project early part of this year that has grown to about 400,000 to 500,000 day and will grow to close to a Bcf a day by second quarter of next year. We also brought on our first pipelines that we actually own in Mexico, our Edinburgh project, that's flowing a little over 100,000 a day. Our two 42-inch projects from the Waha hub are going exceptionally well and we expect those to be under budget and on time. All that feeds into, as I just said, a header at Waha, a 6 Bcf header, that has interconnects to Oasis or will have interconnects with Oasis, ET Fuel, TW. Not only are they great projects for us and we'll be operating them, but they also will be a conduit to reach up through our entire intrastate and interstate pipeline systems to add revenues that were not part of the project when we announced it. So it's a huge growth area for us. We're very excited about it and we see a big future in volumes throughout our intrastate pipeline, growth in volumes, throughout our intrastate pipeline feeding into these projects into Mexico.

And then, Trans-Pecos, any updates there on terms of the process?

I'm sorry, Trans-Pecos is one of the 42 inch pipes. One's going down south to Presidio and one just south of El Paso. Both of those are coming online in the end of the first quarter 2017 and right now, we expect those to be on time.

Our next question is coming from the line of Jeremy Tonet from JPMorgan. Please proceed with your question.

A lot has been talked about the potential financing for ETP on the call and I just wanted to check, there's one other lever it seems like ETP might have as far as the Lake Charles project. It seems like there is a lot of value there and there's been moving assets between the family before. Is that a lever that you guys can pull to really bring in some sizable equity into ETP if you guys so chose?

The short answer is yes. I think that's very much a lever as we move towards FID. Because, recognize that there will be this five years of no cash flow benefit to ETP or ETE for that matter, because obviously, you've got the construction build. And as that has value, that makes beat a lot of difference. The only question is obviously one of timing, but as you move to FID, that is certainly another lever in the overall arsenal.

And just want to go back to the synergy target for the Williams deal as you had discussed before. I was just wondering if we could touch base on that and as far as if there's any updates you're thinking there? I realize it's quite recently since you last discussed it. Also, how do you think about where those synergies land? Is it kind of one-third/one-third/one-third among the three sub MLPs or any color that you could share there would be great.

Yes, we haven't broke the over $2 billion of the commercial synergies. I think most people have recognized so much of it is going to be in the northeast. And then you've got some, I want to say, displacement of volumes from others that we'll be able to capture within our system going forward that will lead to expansions of our Lone Star business that may be laying in another line, a new line for the Midcon on the liquid side. So 1/3, 1/3, 1/3, it's very hard to say. Certainly, the most easily identifiable is related to the liquids volumes around the Northeast and that obviously is very much within the SXL wheelhouse, given the Marcus Hook and the [indiscernible] franchise, that's a big piece of it and then how it gets split up between WPZ and ETP is still TBD. It's way too early to tell. I think everyone's going to benefit. I think our viewpoint is it's a collective benefit here not to basically have the synergies cornered within one entity. That's just not -- I think there's benefits here for everybody and we'll make sure we do our damnedest to be sure that they get allocated appropriately so everyone, everyone wins.

And then just as far as in the marketplace, I think there's a big debate these days as far as managing distribution coverage versus distribution growth rate and how do you think about that for ETP, the balance between the two there and I guess the current trajectory for all three, for the whole family of MLPs? Especially because it doesn't feel like the market is giving you guys credit for what is really kind of leading growth across all your peers there.

So Jeremy, I think Tom's going to jump in, but let me just a couple of things. Because Kelcy talked about ETE and our support. Recognize that for this year, we've got about a 1.2 times coverage. So we don't really have many moving pieces up at ETE so we have excess coverage that we can utilize to support the key operating businesses to continue to health of them and obviously, ETE going forward. The other thing people don't I think fully appreciate is once you get to the end of 2016, whether it's SXL, whether it's ETP, our forecasts, our internal forecasts, don't have any need for further equity. Our biggest issue is the challenge of right now. And of course, there may be new projects, but new projects will bring new growth. And we understand there may be lag, we'll just have to see what happens, but the beauty right now for this partnership is we've set ourselves up from 2016 as we can go clear, as we can see very clearly with these projects in 2018 and even to 2019 this tremendous EBITDA growth. We also now have Williams and other projects and other opportunities we will create with ourselves and amongst ourselves that we think will continue to allow us to in fact, grow the distributable cash flow profile going forward. So I would say we're unique. There is no doubt about it. I don't think people quite appreciated and they don't appreciate just what a great job we've been actually doing and executing to that plan.

So it seems like, as far as you guys see, there's nothing to really break stride from ETE's current 30% distribution growth for the next multiple years there?

That's putting a little bit of words in our mouth.

Sorry about that.

That's okay. We understand what's expected. Obviously, the largest holder of ETE sits across the table from me right now and he sets a very high bar as far as distributions. We understand what we need to be doing as far as and we communicate with, I think, we try to be creatures of habit and show people clear consistency with our actions that we take. So we see ourselves comfortably positioned right now and as we think about the future.

Just one last one if I could, pivoting back to WPZ. Should we expect that business to be run differently? Is there any philosophical changes to how you approach that is going to drive any kind of noticeable differences from how WPZ has been run historically to how it could be going forward?

As of course, we've already identified and as Jamie continues to discuss, we know of a lot of very advantageous benefits that Williams brings to themselves and to our other assets, but we will work with them and help manage the Williams assets in a very similar way that we've grown ETP. And the main thing with that is what does the customer want? Most of the customers, at least the producers that we deal with, they would like to go from the well head all the way to the burner tip all the way to exporting overseas. So we will kind of extend that strategy into the Williams assets by offering not only just gathering, processing and interstate service, but whatever other services that their customers are looking for.

Our next question is coming from the line of Brandon Blossman from Tudor, Pickering, Holt & Company. Please proceed with your question.

Just two quick ones for me, one, Jamie, just to tie a bow on this, Lake Charles, the bank debt market, any concerns on that front?

As far as the debt market's concerned, no. I would say the bank market remains incredibly strong. We've had, I would say, even better receptivity on the Trans-Pecos/Comanche Trail project financing than we anticipated. We had tremendous receptivity on the Williams syndication that we did for the $6.5 billion. I think we're continuing to see a lot of support. It's hard to fault the project that is as well-structured as Lake Charles. And the amount of interest, more broadly, but from our internal roster of banks, as well as banks that we don't do as much business with, remains incredibly high.

Okay. Good positive reminder there. Williams cost synergies directionally as you move through the shared services process, any thoughts there?

We said to the market look up to $400 million. I think we feel very good about that number and obviously, as we move down the path here and we sort of get the integration committee fully mobilized and get working, we'll all have further updates as we go forward.

Utica, Ohio coming online third quarter, second phase end of the year, any additional color that you're willing to share in terms of EBITDA contribution third quarter and then beyond?

Well we don't really share EBITDA projections in the northeast. If you're talking about the Williams assets, of course we wouldn't be able to share anything there. But as Jamie has said, we see tremendous opportunity with revenue growth within our entire family of partnerships, both in the Utica and the Marcellus.

Yes, just that the Utica Ohio River project, the Regency project are --

I'm sorry.

Just contribution in quarter, just directionally or any color?

That system, we brought that online here recently and it is a slow volume growth. It's a ramp up. The economics expected the volumes to ramp up relatively over a period of time, so it'll take two or three years for that to fully ramp up and we're also chasing additional producers and customers for that project. In addition, we're connecting the Ohio River project into Rover in two different locations for synergistic benefits downstream.

Thank you. It appears we have no additional questions at this time. I'd like to turn the floor back over to Mr. Long for any additional concluding comments.

Yes. Well once again, thanks, everyone, for joining today. We really do appreciate it. You can see that it's, once again, a very solid quarter. Obviously, very, very excited about the base assets here and how they have all performed. Likewise, as you look forward, we have a lot of exciting projects. We look forward to talking with all of you. So thanks again for joining and that concludes the conference.

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